View Filing Data

$ 1,349

$ 898

247

207

4,607

4,445

1,256

1,132

Unamortized energy contract assets, current

804

976

334

340

1,351

1,311

1,222

1,267

904

1,238

1,260

13,360

11,896

76,707

74,202

8,237

8,021

11,661

13,272

625

640

6,677

Unamortized energy contract assets, noncurrent

452

337

372

395

1,575

1,330

29,599

30,672

^[1]

119,666

116,770

714

929

1,349

2,088

3,800

3,532

2,112

1,837

644

523

Unamortized energy contract liabilities, current

475

232

149

231

Renewable energy credit obligation

344

352

777

1,035

1,069

11,404

10,798

34,075

32,176

390

389

Deferred income taxes and unamortized investment tax credits

11,330

11,235

9,679

10,029

3,988

3,736

Spent nuclear fuel obligation

1,928

2,093

1,171

1,147

Mark-to-market derivative liabilities, noncurrent

9,559

9,865

479

409

Unamortized energy contract liabilities, noncurrent

463

609

2,130

2,097

40,727

41,220

^[1]

86,596

84,583

19,116

18,964

Treasury stock, at cost

(123)

14,766

14,081

(2,995)

(3,026)

30,764

29,896

2,306

2,291

Total equity

33,070

32,187

Variable Interest Entity, Consolidated, Assets, Not Pledged

119,666

116,770

9,667

9,597

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,548

3,618

750

416

153

138

2,941

2,697

562

321

804

976

Unamortized energy contract assets, current

173

140

251

264

963

937

904

883

933

8,433

6,882

23,981

24,906

11,661

13,272

414

433

452

334

Unamortized energy contract assets, noncurrent

1,421

1,502

371

395

755

670

15,142

16,669

^[2]

47,556

48,457

906

346

1,847

1,773

898

1,022

139

123

100

Unamortized energy contract liabilities, current

449

211

Renewable energy credit obligation

343

352

777

279

265

5,769

4,191

Long-term debt to affiliates

6,989

7,734

898

910

Deferred income taxes and unamortized investment tax credits

3,383

3,811

9,450

9,844

Spent nuclear fuel obligation

900

916

1,171

1,147

Mark-to-market derivative liabilities, noncurrent

2,606

3,065

252

174

Unamortized energy contract liabilities, noncurrent

610

658

18,392

19,663

^[2]

32,048

32,498

3,724

4,349

(38)

(37)

9,518

9,357

Total member’s equity

13,204

13,669

2,304

2,290

Total equity

15,508

15,959

Variable Interest Entity, Consolidated, Assets, Not Pledged

47,556

48,457

9,634

9,556

Variable Interest Entity, Consolidated, Liabilities, No Recourse

3,480

3,516

135

539

559

320

266

Inventories, net

148

152

293

225

1,570

1,364

22,058

20,723

1,307

1,054

2,625

2,217

2,528

1,035

1,188

395

238

7,585

7,639

31,213

29,726

300

840

607

568

373

327

119

293

249

111

112

103

1,925

2,294

7,801

6,761

205

Deferred income taxes and unamortized investment tax credits

3,813

3,469

118

111

201

219

Mark-to-market derivative liabilities, noncurrent

6,050

6,328

223

235

630

562

11,035

10,924

20,966

20,184

Retained earnings (deficit) unappropriated

1,588

Other paid-in capital

7,322

6,822

(1,639)

Retained earnings (deficit) appropriated

2,976

2,771

10,247

9,542

31,213

29,726

130

271

321

327

151

105

Prepaid utility taxes

782

822

8,610

8,053

460

381

389

537

349

340

1,250

1,295

10,642

10,170

500

370

113

114

175

141

809

1,267

3,084

2,403

^[3]

184

Deferred income taxes and unamortized investment tax credits

1,933

1,789

288

421

549

2,745

2,739

6,822

6,593

2,578

2,489

1,242

1,087

3,820

3,577

10,642

10,170

353

375

Gas Held in Storage

177

174

Prepaid utility taxes

786

811

8,243

7,602

398

397

279

285

687

691

9,716

9,104

295

265

155

164

120

116

774

760

2,876

2,577

Deferred income taxes and unamortized investment tax credits

1,222

1,244

201

202

1,192

1,101

2,712

2,626

6,362

5,963

1,714

1,605

1,640

1,536

3,354

3,141

9,716

9,104

124

453

486

177

206

163

151

Gas Held in Storage

489

554

1,533

1,551

13,446

12,498

2,312

2,493

130

132

4,005

486

490

Long-term note receivable

7,005

7,198

^[4]

21,984

21,247

179

350

125

396

496

348

256

261

Unamortized energy contract liabilities, current

119

188

116

119

123

1,592

1,931

6,134

5,478

Deferred income taxes and unamortized investment tax credits

2,146

2,070

103

105

Unamortized energy contract liabilities, noncurrent

1,864

1,872

442

561

369

389

4,976

5,013

^[4]

12,702

12,422

(10)

9,220

8,835

Total member’s equity

9,282

8,825

Total equity

9,282

8,825

Variable Interest Entity, Consolidated, Assets, Not Pledged

21,984

21,247

Variable Interest Entity, Consolidated, Liabilities, No Recourse

102

225

250

Inventories, net

270

213

760

710

6,460

6,001

643

678

105

102

316

322

1,079

1,121

8,299

7,832

214

139

126

137

Merger related obligation

Current portion of DC PLUG obligation

628

550

2,704

2,521

Deferred income taxes and unamortized investment tax credits

1,064

1,063

822

829

312

300

2,227

2,228

5,559

5,299

1,636

1,470

1,104

1,063

2,740

2,533

8,299

7,832

134

146

Gas Held in Storage

336

325

3,821

3,579

231

245

186

193

431

453

4,588

4,357

216

111

375

547

1,403

1,217

Deferred income taxes and unamortized investment tax credits

628

603

606

593

1,301

1,258

3,079

3,022

914

764

595

571

1,509

1,335

4,588

4,357

Inventories, net

240

258

2,966

2,706

386

359

Long-term note receivable

493

481

^[5]

3,699

3,445

139

108

281

154

118

422

619

1,170

840

Deferred income taxes and unamortized investment tax credits

535

493

402

411

981

943

^[5]

2,573

2,402

979

912

147

131

1,126

1,043

Variable Interest Entity, Consolidated, Assets, Not Pledged

3,699

3,445

Variable Interest Entity, Consolidated, Liabilities, No Recourse

$ 59

$ 90

[1]	Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities for additional information.
[2]	Generation’s consolidated assets include $9,634 million and $9,556 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,480 million and $3,516 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities for additional information.
[3]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[4]	PHI’s consolidated total assets include $33 million and $41 million at December 31, 2018 and 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 $69 million and $102 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities for additional information.
[5]	ACE’s consolidated assets include $23 million and $29 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $59 million and $90 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities for additional information.

Consolidated Balance Sheets (Parenthetical) - $ / shares $ / shares in Millions	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	968,187,955	963,335,888
Treasury stock, shares held	2,000,000	2,000,000

Consolidated Statement of Changes in Shareholders Equity - USD ($)
shares in Thousands, $ in Millions

Total

Pepco Holdings LLC [Member]

Commitments [Member]

Pepco Holdings LLC [Member]

Common Stock [Member]

Treasury Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

Exelon Generation Co L L C [Member]

Membership Interest [Member]

Exelon Generation Co L L C [Member]

Undistributed Earnings [Member]

Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Exelon Generation Co L L C [Member]

Noncontrolling Interest [Member]

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]

Parent [Member]

Baltimore Gas and Electric Company [Member]

Common Stock [Member]

Baltimore Gas and Electric Company [Member]

Common Stock [Member]

Parent [Member]

Baltimore Gas and Electric Company [Member]

Retained Earnings [Member]

Baltimore Gas and Electric Company [Member]

Membership Interest [Member]

Baltimore Gas and Electric Company [Member]

Membership Interest [Member]

Parent [Member]

Baltimore Gas and Electric Company [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

Pepco Holdings LLC [Member]

^[4]

Pepco Holdings LLC [Member]

Deferred Compensation, Share-based Payments [Member]

Pepco Holdings LLC [Member]

Common Stock [Member]

^[1]

Pepco Holdings LLC [Member]

Retained Earnings [Member]

Pepco Holdings LLC [Member]

Membership Interest [Member]

Pepco Holdings LLC [Member]

Membership Interest [Member]

Pepco Holdings LLC [Member]

^[4]

Pepco Holdings LLC [Member]

Undistributed Earnings [Member]

Pepco Holdings LLC [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Pepco Holdings LLC [Member]

Additional Paid-in Capital [Member]

Potomac Electric Power Company [Member]

Common Stock [Member]

Potomac Electric Power Company [Member]

Retained Earnings [Member]

Delmarva Power & Light Company [Member]

Common Stock [Member]

Delmarva Power & Light Company [Member]

Retained Earnings [Member]

Atlantic City Electric Company [Member]

Common Stock [Member]

Atlantic City Electric Company [Member]

Retained Earnings [Member]

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

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ 27,330

$ 18,676

$ (2,327)

$ 12,104

$ (2,624)

$ 1,308

$ 193

Other Additional Capital | Successor [Member]

$ 3,829

Beginning Balance (in shares) at Dec. 31, 2015

954,668

Beginning Balance (Predecessor [Member]) at Dec. 31, 2015

$ 8,243

$ 1,588

$ 5,677

$ (1,639)

$ 2,617

$ 3,236

$ 2,455

$ 780

$ 1

$ 2,877

$ 1,367

$ 1,320

$ 2,687

$ 190

$ 2,240

$ 1,122

$ 1,118

$ 1,237

$ 612

$ 625

$ 1,000

$ 773

$ 227

$ 4,413

$ 3,832

$ 617

$ (36)

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

$ 12,978

$ 8,997

$ 2,737

$ (63)

$ 1,307

Net income (loss) | Predecessor [Member]

Employee stock purchase plan issuances | Predecessor [Member]

Tax benefit on stock compensation | Predecessor [Member]

(1)

Other comprehensive income (loss), net of income taxes | Predecessor [Member]

Ending Balance (Predecessor [Member]) at Mar. 23, 2016

4,439

3,838

636

(35)

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

Stockholders' Equity, Other | Predecessor [Member]

Beginning Balance (in shares) at Dec. 31, 2015

954,668

Beginning Balance (Predecessor [Member]) at Dec. 31, 2015

8,243

1,588

5,677

(1,639)

2,617

3,236

2,455

780

2,877

1,367

1,320

2,687

190

2,240

1,122

1,118

1,237

612

625

1,000

773

227

4,413

3,832

617

(36)

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

12,978

8,997

2,737

(63)

1,307

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

$ 1,196

$ (66)

1,121

550

483

378

438

294

(9)

(42)

2,868

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

$ 85

Employee stock purchase plan issuances, shares

1,242

Employee stock purchase plan issuances

$ 55

Tax benefit on stock compensation

(18)

Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders

Sale of noncontrolling interests

239

(4)

243

239

(4)

243

Noncontrolling Interest, Change in Redemption Value

157

Noncontrolling Interest, Period Increase (Decrease)

Common stock dividends

(1,172)

(369)

(277)

(179)

(169)

(54)

(63)

Preferred and preference stock dividends

(8)

Stock Redeemed or Called During Period, Value

(193)

(190)

Adjustments to Additional Paid in Capital, Other

268

315

$ (7)

187

152

139

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

(922)

Income Tax Effects Allocated Directly to Equity, Other

Other comprehensive income (loss), net of income taxes

$ (36)

(36)

Ending Balance (in shares) at Dec. 31, 2016

958,778

Ending Balance (Successor [Member]) at Dec. 31, 2016

8,725

1,588

6,150

(1,639)

2,626

3,415

2,473

941

2,848

1,421

1,427

2,848

2,300

1,309

991

1,326

764

562

1,034

912

122

8,016

$ 8,077

$ (61)

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

13,284

9,261

2,298

(54)

1,779

Other Additional Capital | Successor [Member]

3,835

Common stock | Successor [Member]

$ 3

Beginning Balance (Predecessor [Member]) at Mar. 23, 2016

4,439

$ 3,838

$ 636

(35)

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

Net income (loss) | Successor [Member]

(61)

Other comprehensive income (loss), net of income taxes | Successor [Member]

Ending Balance (in shares) at Dec. 31, 2016

958,778

Ending Balance (Successor [Member]) at Dec. 31, 2016

8,725

1,588

6,150

(1,639)

2,626

3,415

2,473

941

2,848

1,421

1,427

2,848

2,300

1,309

991

1,326

764

562

1,034

912

122

8,016

8,077

(61)

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

13,284

9,261

2,298

(54)

1,779

Stockholders' Equity, Other | Successor [Member]

$ 33

Stockholders' Equity, Other

$ 29

Common stock | Successor [Member]

165

Business Combination, Contingent Consideration, Asset | Successor [Member]

235

Business Combination, Contingent Consideration, Asset

$ 235

163

Beginning Balance (Successor [Member]) at Mar. 24, 2016

^[2]

7,200

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

Net income (loss) | Successor [Member]

(61)

Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Paid | Successor [Member]

Distribution Made to Limited Liability Company (LLC) Member, Cash Distributions Declared | Successor [Member]

^[3]

(400)

Members Equity Including Portion Attributable To Noncontrolling Interest Acquisitions | Successor [Member]

1,251

Ending Balance (in shares) at Dec. 31, 2016

958,778

Ending Balance (Successor [Member]) at Dec. 31, 2016

8,725

1,588

6,150

(1,639)

2,626

3,415

2,473

941

2,848

1,421

1,427

2,848

2,300

1,309

991

1,326

764

562

1,034

912

122

8,016

8,077

(61)

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

13,284

9,261

2,298

(54)

1,779

Stockholders' Equity, Other | Successor [Member]

$ (62)

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ 27,640

18,794

(2,327)

12,053

(2,660)

^[5]

1,780

(54)

^[5]

Retained Earnings, Appropriated

158

(378)

378

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

$ 3,876

364

3,786

2,798

2,710

567

434

307

362

205

121

5,066

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

$ 56

Employee stock purchase plan issuances, shares

1,324

Employee stock purchase plan issuances

$ 150

150

Stock Issued During Period, Shares, New Issues

Stock Issued During Period, Value, New Issues

$ 0

Stock Issued During Period, Value, Treasury Stock Reissued

(1,150)

2,204

(1,054)

Tax benefit on stock compensation

Sale of noncontrolling interests

407

(36)

443

407

(36)

443

Noncontrolling Interest, Change in Redemption Value

(20)

Noncontrolling Interest, Period Increase (Decrease)

(18)

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

Common stock dividends

(1,243)

(422)

(288)

(198)

(133)

(112)

(68)

Adjustments to Additional Paid in Capital, Other

651

184

161

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

(659)

(311)

Income Tax Effects Allocated Directly to Equity, Other

Other comprehensive income (loss), net of income taxes

$ 171

173

^[5]

(2)

^[5]

(2)

^[5]

Members Equity Including Portion Attributable To Noncontrolling Interest Acquisitions

758

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

539

(539)

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

965,168

Ending Balance at Dec. 31, 2017

$ 29,896

9,542

1,588

6,822

(1,639)

2,771

3,577

2,489

1,087

3,141

1,605

1,536

3,141

2,533

1,470

1,063

1,335

764

571

1,043

912

131

Ending Balance at Dec. 31, 2017

15,959

9,357

4,349

(37)

2,290

8,825

8,835

(10)

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

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

32,187

18,964

(123)

14,081

(3,026)

^[5]

2,291

(37)

^[5]

Retained Earnings, Appropriated

2,771

(567)

567

Additional Paid in Capital

6,822

18,964

1,588

2,489

1,605

1,470

764

912

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

$ 2,084

$ 453

2,010

443

370

664

460

313

398

210

120

3,534

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

$ 41

Employee stock purchase plan issuances, shares

1,318

Employee stock purchase plan issuances

$ 105

105

Sale of noncontrolling interests

Noncontrolling Interest, Period Increase (Decrease)

(60)

Common stock dividends

(1,339)

(459)

(306)

(209)

(169)

(96)

(59)

Adjustments to Additional Paid in Capital, Other

155

500

109

166

150

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

(1,001)

(326)

Income Tax Effects Allocated Directly to Equity, Other

Other comprehensive income (loss), net of income taxes

^[5]

Members Equity Including Portion Attributable To Noncontrolling Interest Acquisitions

385

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

$ 4

(10)

(3)

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

970,020

Ending Balance at Dec. 31, 2018

$ 30,764

10,247

$ 1,588

$ 7,322

(1,639)

2,976

3,820

$ 2,578

$ 1,242

3,354

$ 1,714

$ 1,640

$ 3,354

$ 0

2,740

$ 1,636

$ 1,104

1,509

$ 914

$ 595

1,126

$ 979

$ 147

Ending Balance at Dec. 31, 2018

$ 15,508

$ 9,518

$ 3,724

(38)

$ 2,304

$ 9,282

$ 9,220

$ 62

$ 0

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

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

33,070

$ 19,116

$ (123)

$ 14,766

$ (2,995)

^[5]

$ 2,306

$ 0

$ (38)

^[5]

$ 0

^[5]

Retained Earnings, Appropriated

2,976

$ (664)

$ 664

Additional Paid in Capital

7,322

Significant Accounting Policies (All Registrants)

$ 19,116

$ 1,588

$ 2,578

$ 1,714

$ 1,636

$ 914

$ 979

[1]	At March 23, 2016 and December 31, 2015, PHI's (predecessor) shareholders' equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively.
[2]	The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger.
[3]	Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed by PHI to Exelon.
[4]	he liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 5 — Mergers, Acquisitions and Dispositions.
[5]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.

Consolidated Statement of Changes in Shareholders Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 1.38	$ 1.31	$ 1.26

Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Description of Business (All Registrants)

Exelon is a utility services holding company engaged in the generation, delivery and marketing of energy through Generation and the energy distribution and transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE. On March 23, 2016, Exelon completed the merger with PHI, which became a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. See Note 5 — Mergers, Acquisitions and Dispositions for additional information regarding the merger transaction.



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)

This is a combined annual report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.

As a result of the merger with PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which it has pushed-down to the consolidated financial statements of PHI such that the assets and liabilities of PHI are recorded at their respective fair values, and goodwill has been established as of the acquisition date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the results of operations and the financial positions of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly owned subsidiary utility registrants, Pepco, DPL and ACE.

For financial statement purposes, beginning on March 24, 2016, disclosures related to Exelon also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.

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

Exelon owns 100% of Generation, PECO, BGE and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL and ACE. Generation owns 100% of its significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for additional information of Exelon’s and Generation’s consolidated VIEs.

The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities without readily determinable fair value is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd and PECO. Under equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities without readily determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities without readily determinable fair values, the Registrants report their investments at cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.

The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.

Use of Estimates (All Registrants)

The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.

Prior Period Adjustments and Reclassifications (All Registrants)

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. See New Accounting Standards below for additional information.

Accounting for the Effects of Regulation (Exelon and the Utility Registrants)

For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements, which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their financial statements. See Note 4 — Regulatory Matters for additional information.

With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion representing the amount expected to be recovered from or settled to customers over the next twelve-month period as of the balance sheet date. Income tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align with the classification of the related deferred income tax balances.

Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.

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 4 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information.

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. 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 in its Consolidated Balance Sheets. See Note 4 — Regulatory Matters and Note 12 — Derivative Financial Instruments for additional 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 gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23 — 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.

Income Taxes (All Registrants)

Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense or Other income and deductions (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.

Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14 — Income Taxes for additional information.

Cash and Cash Equivalents (All Registrants)

The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents (All Registrants)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2018 and 2017, the Registrants' restricted cash and cash equivalents primarily represented the following items:



Registrant	Description
Exelon	Payment of medical, dental, vision and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants.
Generation	Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.
ComEd	Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site.
PECO	Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE	Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
PHI	Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts and repayment of transition bonds.
Pepco	Payment of merger commitments and collateral held from energy suppliers.
DPL	Collateral held from energy suppliers.
ACE	Repayment of transition bonds and collateral held from energy suppliers.

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2018 and 2017, the Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of transition bonds.

See Note 23 — Supplemental Financial Information for additional information.

Allowance for Uncollectible Accounts (All Registrants)

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances. For Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. Utility Registrants estimate the allowance by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. See Note 4 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd and ACE.

Variable Interest Entities (All Registrants)

Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:


•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,


•	requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and


•	requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

See Note 2 — Variable Interest Entities for additional information.

Inventories (All Registrants)

Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel, materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution and generating plant materials and are expensed to operating and maintenance or capitalized to property, plant and equipment, as appropriate, when installed or used.

Debt and Equity Security Investments (Exelon and Generation)

Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI.

Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair values. Exelon has elected to use the practicability exception to measure these investments, defined as cost adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.

Equity Security Investments with Readily Determinable Fair Values. Equity securities held in the NDT funds are classified as equity securities with readily determinable fair values. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO and in Noncurrent payables to affiliates at Generation and in Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation's NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. See Note 4 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 11 — Fair Value of Financial Assets and Liabilities and Note 15 — Asset Retirement Obligations for additional information regarding marketable securities held by NDT funds.

Property, Plant and Equipment (All Registrants)

Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation, Exelon Corporate and PHI and AFUDC for regulated property at the Utility Registrants. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and maintenance expense as incurred.

Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been accounted for as CIAC.

For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred.

For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL and ACE includes the estimated cost of dismantling and removing plant from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.

Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within Property, plant and equipment. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.

Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.

AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

See Note 6 — Property, Plant and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within Property, plant and equipment and charged to fuel expense using the unit-of-production method. Any potential future SNF disposal fees will be expensed through fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal.

Nuclear Outage Costs (Exelon and Generation)

Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized to Property, plant and equipment (based on the nature of the activities) in the period incurred.

Depreciation and Amortization (All Registrants)

Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The Utility Registrants' depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 8 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.

See Note 6 — Property, Plant and Equipment for additional information regarding depreciation.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating revenues.

Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

See Note 4 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and ARC, and the amortization of the Utility Registrants' regulatory assets.

Asset Retirement Obligations (All Registrants)

Generation estimates and recognizes a liability for its legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 15 — Asset Retirement Obligations for additional information.

Guarantees (All Registrants)

The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken by issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.

The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 22 — Commitments and Contingencies for additional information.

Asset Impairments

Long-Lived Assets (All Registrants). The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. See Note 7 — Impairment of Long-Lived Assets and Intangibles for additional information.

Goodwill (Exelon, ComEd and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10 — Intangible Assets for additional information.

Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.

Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included in earnings.

Equity Security Investments (Exelon and Generation). Equity investments with readily determinable fair values are measured and recorded at fair value with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired on the basis of the qualitative assessment, an impairment loss will be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value.

Derivative Financial Instruments (All Registrants)

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenue, Purchased power and fuel, Interest expense or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. While the majority of the derivatives serve as economic hedges, there are also derivatives entered into for proprietary trading purposes, subject to Exelon’s Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. See Note 4 — Regulatory Matters and Note 12 — Derivative Financial Instruments for additional information.

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12 — Derivative Financial Instruments for additional information.

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 16 — Retirement Benefits for additional information.

New Accounting Standards (All Registrants)

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

Defined Benefit Plan Disclosures (Issued August 2018). Eliminates existing disclosure requirements related to amounts in Accumulated other comprehensive income expected to be recognized in Net periodic benefit cost over the next year and the effects of a one-percentage-point change in the assumed health care cost trend rates. In addition, new disclosures were added such as the weighted-average interest crediting rates for cash balance plans and an explanation for the reasons for significant gains and losses related to changes in the benefit obligation. The standard is effective January 1, 2021, with early adoption permitted, and must be applied retrospectively. Exelon early adopted this standard in the fourth quarter of 2018. See Note 16 — Retirement Benefits for additional information.

Fair Value Measurement Disclosures (Issued August 2018). Updates the disclosure requirements for fair value measurements to improve the usefulness of information for financial statement users. The guidance removes the requirements to disclose (1) the amount of and reasons for transfers between Level 1 and Level 2, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements and adds a requirement to disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The standard is effective January 1, 2020, with early adoption permitted. The amendments to remove disclosures must be applied retrospectively and can be early adopted, while the amendments to add disclosures must be applied prospectively and adoption can be delayed until the effective date. The Registrants early adopted, in the fourth quarter of 2018, the amendments to remove disclosures and will adopt the amendments to add disclosures in the first quarter of 2020. The impact of the new disclosures is not expected to be material to the Registrants’ consolidated financial statements. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.

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 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 in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation or the Utility Registrants. 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 21— Changes in Accumulated Other Comprehensive Income for additional information.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017). Changes the accounting and presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. The guidance requires plan sponsors to report the service cost and other non-service cost components of net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under the new guidance, service cost is presented as part of income from operations and the other non-service cost components are classified outside of income from operations in the Consolidated Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization on a prospective basis beginning on January 1, 2018. Under prior GAAP, the total amount of net benefit cost was recorded as part of income from operations and all components were eligible for capitalization. Exelon applied the presentation of the service component and the other non-service cost components of net benefit costs retrospectively and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive Income in prior periods presented. 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. In Exelon’s consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework were prospectively reported as regulatory assets (previously, they were capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory assets are amortized outside of operating income. See Note 16 — Retirement Benefits for additional information.

Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-employer accounting. Multi-employer accounting was not impacted by this standard; therefore, Exelon's subsidiary financial statements did not change upon its adoption.

Statement of Cash Flows: Classification of Restricted Cash (Issued November 2016). The standard states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows (instead of being presented as cash flow activities). 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 23 — Supplemental Financial Information for additional information.

Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016). Eliminates the available-for-sale and cost method classification for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured and recorded at fair value with any changes in fair value recorded through earnings and, for equity investments without a readily determinable fair value, provides a measurement alternative of cost less impairment plus or minus adjustments for observable price changes in identical or similar assets. In addition, equity investments without readily determinable fair values must be qualitatively assessed for impairment each reporting period and fair value determined if any significant impairment indicators exist. If fair value is less than carrying value, the impairment is recorded through net income immediately in the period in which it is identified. The guidance does not impact the classification or measurement of investments in debt securities. The guidance also amends several disclosure requirements, including requiring i) financial assets and financial liabilities to be presented separately in the balance sheet or note, grouped by measurement category and form, ii) disclosure of the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and iii) for financial assets and liabilities measured at amortized cost, disclosure of the fair value of the amount that would be received to sell the asset or paid to transfer the liability. The guidance was applied using a modified retrospective transition approach with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants recorded an insignificant adjustment to opening retained earnings as of January 1, 2018 related to unrealized gains/losses on available for sale equity securities. See Note 21— Changes in Accumulated Other Comprehensive Income for additional information.

Revenue from Contracts with Customers (Issued May 2014 and subsequently amended to address implementation questions). Changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five-step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). 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' 2017 and 2016 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 3 — Revenue from Contracts with Customers for additional information.



														Successor
For the year ended December 31, 2017	Exelon			Generation		ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Operating Revenues - As reported
Competitive business revenues	$	17,360		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	16,171			—		—			—		—			—			—			—			—
Operating revenues	—			17,351		—			—		—			—			—			—			—
Electric operating revenues	—			—		5,521			2,369		2,484			4,468			2,152			1,131			1,184
Natural gas operating revenues	—			—		—			494		676			161			—			161			—
Operating revenues from affiliates	—			1,115		15			7		16			50			6			8			2
Total operating revenues	$	33,531		$	18,466	$	5,536		$	2,870	$	3,176		$	4,679		$	2,158		$	1,300		$	1,186

Operating Revenues - Adjustments
Competitive business revenues	$	34		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(207		)	—		—			—		—			—			—			—			—
Operating revenues	—			34		—			—		—			—			—			—			—
Electric operating revenues	—			—		(43		)	—		(100		)	(40		)	(26		)	(6		)	(8		)
Natural gas operating revenues	—			—		—			—		(24		)	—			—			—			—
Revenues from alternative revenue programs	207			—		43			—		124			40			26			6			8
Operating revenues from affiliates	—			—		—			—					—			—			—			—
Total operating revenues	$	34		$	34	$	—		$	—	$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	17,394		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	15,964			—		—			—		—			—			—			—			—
Operating revenues	—			17,385		—			—		—			—			—			—			—
Electric operating revenues	—			—		5,478			2,369		2,384			4,428			2,126			1,125			1,176
Natural gas operating revenues	—			—		—			494		652			161			—			161			—
Revenues from alternative revenue programs	207			—		43			—		124			40			26			6			8
Operating revenues from affiliates	—			1,115		15			7		16			50			6			8			2
Total operating revenues	$	33,565		$	18,500	$	5,536		$	2,870	$	3,176		$	4,679		$	2,158		$	1,300		$	1,186



																							Successor			Predecessor
																							March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon			Generation		ComEd			PECO		BGE			Pepco			DPL			ACE			PHI			PHI
Operating Revenues - As reported
Competitive business revenues	$	16,324		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	15,036			—		—			—		—			—			—			—			—			—
Operating revenues	—			16,312		—			—		—			—			—			—			—			—
Electric operating revenues	—			—		5,239			2,524		2,603			2,181			1,122			1,254			3,506			1,096
Natural gas operating revenues	—			—		—			462		609			—			148			—			92			57
Operating revenues from affiliates	—			1,439		15			8		21			5			7			3			45			—
Total operating revenues	$	31,360		$	17,751	$	5,254		$	2,994	$	3,233		$	2,186		$	1,277		$	1,257		$	3,643		$	1,153

Operating Revenues - Adjustments
Competitive business revenues	$	6		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(48		)	—		—			—		—			—			—			—			—			—
Operating revenues	—			6		—			—		—			—			—			—			—			—
Electric operating revenues	—			—		24			—		(72		)	(14		)	6			(9		)	(43		)	26
Natural gas operating revenues	—			—		—			—		19			—			—			—			—			—
Revenues from alternative revenue programs	48			—		(24		)	—		53			14			(6		)	9			43			(26		)
Operating revenues from affiliates	—			—		—			—		—			—			—			—			—			—
Total operating revenues	$	6		$	6	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	16,330		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	14,988			—		—			—		—			—			—			—			—			—
Operating revenues	—			16,318		—			—		—			—			—			—			—			—
Electric operating revenues	—			—		5,263			2,524		2,531			2,167			1,128			1,245			3,463			1,122
Natural gas operating revenues	—			—		—			462		628			—			148			—			92			57
Revenues from alternative revenue programs	48			—		(24		)	—		53			14			(6		)	9			43			(26		)
Operating revenues from affiliates	—			1,439		15			8		21			5			7			3			45			—
Total operating revenues	$	31,366		$	17,757	$	5,254		$	2,994	$	3,233		$	2,186		$	1,277		$	1,257		$	3,643		$	1,153

New Accounting Standards Adopted as of January 1, 2019: The following new authoritative accounting guidance issued by the FASB was adopted as of January 1, 2019 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2019.

Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard is effective January 1, 2020, with early adoption permitted, and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance is not expected to have a material impact on the Registrants’ financial statements.

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 Registrants adopted the standard on January 1, 2019.

The new standard requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas under previous GAAP only finance lease liabilities (referred to as capital leases) were 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 standard, 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 previous 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 previous disclosures related only to lessees. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from previous GAAP. Lessor accounting is also largely unchanged.

The new standard provides a number of transition practical expedients, which the Registrants have elected, including:


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


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


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

The Registrants have assessed the lease standard and executed a detailed implementation plan in preparation for adoption, which included the following key activities:


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


•	Evaluated the transition practical expedients available under the standard.


•	Identified, assessed and documented technical accounting issues, policy considerations and financial reporting implications.


•	Identified and implemented changes to processes and controls to ensure all impacts of the new standard are effectively addressed.

The adoption of the new standard is expected to result in right of use assets and lease obligations for operating leases recorded in the Registrants’ Consolidated Balance Sheets on January 1, 2019 of approximately:



	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
ROU Assets	$1,400-$1,500	$1,000-$1,100	$5-$10	$1-$5	$100-$120	$250-$270	$60-$65	$70-$75	$20-$25
Lease Liabilities	$1,600-$1,700	$1,200-$1,300	$5-$10	$1-$5	$100-$120	$300-$320	$60-$65	$75-$80	$20-$25

The impact of adopting the new standard on retained earnings as of January 1, 2019 is expected to be immaterial.

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

Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, Generation, ComEd, PHI and DPL have goodwill as of December 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.

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects the entity’s current estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January 1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. The Registrants are currently assessing the impacts of this standard.

Variable Interest Entities (All Registrants)

12 Months Ended

Dec. 31, 2018

Variable Interest Entity [Abstract]

Variable Interest Entity Disclosure [Text Block]

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 December 31, 2018 and 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 December 31, 2018 and 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

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at December 31, 2018 and 2017 are as follows:



	December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	938	$	931	$	7	4
Noncurrent assets	9,071		9,045		26		19
Total assets	$	10,009	$	9,976	$	33	$	23
Current liabilities	$	274	$	252	$	22	19
Noncurrent liabilities	3,280		3,233		47		40
Total liabilities	$	3,554	$	3,485	$	69	$	59



	December 31, 2017
	Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	662	$	652	$	10	$	6
Noncurrent assets	9,317		9,286		31		23
Total assets	$	9,979	$	9,938	$	41	$	29
Current liabilities	$	308	$	272	$	36	$	32
Noncurrent liabilities	3,316		3,250		66		58
Total liabilities	$	3,624	$	3,522	$	102	$	90

__________


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

Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the table can only be settled using VIE resources.

As of December 31, 2018 and 2017, Exelon's and Generation's consolidated VIEs consist of:

Investments in Other Energy Related Companies

During 2015, Generation sold 69% of its equity interest in a company to a tax equity investor. The company holds an equity method investment in a distributed energy company that is an unconsolidated VIE (see unconsolidated VIE section for additional details). Generation and the tax equity investor contributed a total of $227 million of equity in proportion to their ownership interests to the company. The company meets the definition of a VIE because it has a similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. Generation is the primary beneficiary because Generation manages the day-to-day activities of the entity.

During the fourth quarter of 2017 Generation acquired a controlling financial interest in an energy development company. The company is in the development stage and requires additional subordinated financial support from the equity holders to fund activities. Generation is the majority owner with a 62% equity interest and has the power to direct the activities that most significantly affect the economic performance of the company.

Renewable Energy Project Companies

In July 2017, Generation sold a 49% interest in EGRP to an outside investor for $400 million of cash plus immaterial working capital and other customary post-closing adjustments. EGRP meets the definition of a VIE because the EGRP has a similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner. Generation is the primary beneficiary because Generation manages the day-to-day activities of the entity; therefore, Generation will continue to consolidate EGRP. EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. The details relating to these VIEs are discussed below.

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

While Generation or EGRP owns 100% of the majority of the wind entities, four of the projects have noncontrolling equity interests of 1% held by third parties and one of the projects has noncontrolling equity interests related to its Class B Membership Interest (see additional details below). The entities with noncontrolling equity interests of 1% held by third parties meet the definition of a VIE because the entities have noncontrolling equity interest holders that absorb variability from the wind projects. Generation’s or the EGRP's current economic interests in three of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation or EGRP are to provide financial support to the projects in proportion to its current 99% economic interests in the projects. Generation provides operating and capital funding to the wind project entities for ongoing construction, operations and maintenance and there is limited recourse to Generation related to certain wind project entities. However, no additional support to these projects beyond what was contractually required has been provided. Generation is the primary beneficiary of these wind entities because Generation controls the design, construction, and operation of the facilities.

In December 2016, Generation sold 100% of the Class B Membership Interests to a tax equity investor and retained 100% of the Class A Membership Interests of its equity interest in one of its wind entities that was previously consolidated under the voting interest model and was subsequently contributed to EGRP in 2017. The wind entity meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. While Generation is the minority interest holder, Generation is the primary beneficiary, because Generation manages the day-to-day activities of the entity. Therefore, the entity continues to be consolidated by Generation.

In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 13 — Debt and Credit Agreements for additional information on ExGen Renewables IV and ITEM 2. PROPERTIES for additional details on the specific projects included within EGRP.

Retail Power and Gas Companies

In March 2014, Generation began consolidating retail power and gas VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $34 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs do not have a material impact on Generation’s financial results or financial condition.

CENG

CENG is a joint venture between Generation and EDF. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. As a result of executing the NOSA, CENG qualifies as a VIE due to the disproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. Further, since Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and, therefore, is required to consolidate the results of operations and financial position of CENG.

Exelon and Generation, where indicated, provide the following support to 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 RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017. (see Note 4 — Regulatory Matters for additional details),


•	Generation provided a $400 million loan to CENG. As of December 31, 2018, the remaining obligation is $196 million, including accrued interest. The remaining balance was fully paid by CENG in January 2019.

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 22 — Commitments and Contingencies for more details),


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


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

As of December 31, 2018 and 2017, Exelon's, PHI's and ACE's consolidated VIE consists of:

ACE Transition Funding

A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three years ended December 31, 2018, 2017 and 2016, ACE transferred $30 million, $48 million and $60 million to ATF, respectively.

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

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



	December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	66		62		4		4
Accounts receivable, net
Customer	146		146		—		—
Other	23		23		—		—
Inventory
Materials and supplies	212		212		—		—
Other current assets	52		49		3		—
Total current assets	913		906		7		4

Property, plant and equipment, net	6,145		6,145		—		—
Nuclear decommissioning trust funds	2,351		2,351		—		—
Other noncurrent assets	258		232		26		19
Total noncurrent assets	8,754		8,728		26		19
Total assets	$	9,667	$	9,634	$	33	$	23

Long-term debt due within one year	$	87	$	66	$	21	$	18
Accounts payable	96		96		—		—
Accrued expenses	72		72		1		1
Unamortized energy contract liabilities	15		15		—		—
Other current liabilities	3		3		—		—
Total current liabilities	273		252		22		19

Long-term debt	1,072		1,025		47		40
Asset retirement obligations	2,160		2,160		—		—
Unamortized energy contract liabilities	1		1		—		—
Other noncurrent liabilities	42		42		—		—
Total noncurrent liabilities	3,275		3,228		47		40
Total liabilities	$	3,548	$	3,480	$	69	$	59

__________


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



	December 31, 2017
	Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	126	$	126	$	—	$	—
Restricted cash and cash equivalents	64		58		6		6
Accounts receivable, net
Customer	170		170		—		—
Other	25		25		—		—
Inventory
Materials and supplies	205		205		—		—
Other current assets	45		41		4		—
Total current assets	635		625		10		6

Property, plant and equipment, net	6,186		6,186		—		—
Nuclear decommissioning trust funds	2,502		2,502		—		—
Other noncurrent assets	274		243		31		23
Total noncurrent assets	8,962		8,931		31		23
Total assets	$	9,597	$	9,556	$	41	$	29

Long-term debt due within one year	$	102	$	67	$	35	$	31
Accounts payable	114		114		—		—
Accrued expenses	67		66		1		1
Unamortized energy contract liabilities	18		18		—		—
Other current liabilities	7		7		—		—
Total current liabilities	308		272		36		32

Long-term debt	1,154		1,088		66		58
Asset retirement obligations	2,035		2,035		—		—
Other noncurrent liabilities	121		121		—		—
Total noncurrent liabilities	3,310		3,244		66		58
Total liabilities	$	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 in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

As of December 31, 2018 and 2017, Exelon and Generation had significant unconsolidated variable interests in seven VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation have several individually immaterial VIEs that in aggregate represent a total investment of $15 million and $13 million, respectively, as of December 31, 2018. These immaterial VIEs are equity and debt securities in energy development companies. As of December 31, 2018, the maximum exposure to loss related to these securities included in Investments in Exelon's and Generation's Consolidated Balance Sheets is limited to the $15 million and $13 million, respectively.

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



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



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 in 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 in 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 $9 million and $39 million as of December 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions LLC of $9 million and $37 million as of December 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE.

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 materially affect the fair value or risk of their variable interests in these VIEs.

As of December 31, 2018 and 2017, Exelon's and Generation's unconsolidated VIEs consist of:

Energy Purchase and Sale Agreements

Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.

ZionSolutions

Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 — Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning activities under the asset sale agreement are complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions’ creditors do not have any recourse to Exelon’s or Generation’s general credit.

Investment in Distributed Energy Companies

In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy company. Generation contributed a total $85 million of equity. The distributed energy company meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights of the general partner. Generation is not the primary beneficiary; therefore, the investment continues to be recorded using the equity method.

During 2015, a company that is consolidated by Generation as a VIE entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company (see additional details in the Consolidated Variable Interest Entities section above). The equity holders (of which Generation is one) contributed to the distributed energy company a total of $227 million of equity in proportion to their ownership interests. The equity holders provided a parental guarantee of up to $275 million in support of equity contributions to the distributed energy company. As all equity contributions were made as of the first quarter of 2017, there is no further payment obligation under the parental guarantee. The distributed energy company meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights of the general partner. Generation is not the primary beneficiary; therefore, the investment is recorded using the equity method.

Both distributed energy companies from the 2015 and 2014 arrangements are considered related parties to Generation.

ComEd and PECO

The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, PECO Trust III and PECO Trust IV, are not consolidated in Exelon’s, ComEd’s, or PECO’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd and PECO have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, or PECO Trust IV as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 — Debt and Credit Agreements for additional information.

Revenue Recognition Revenue Recognition (All Registrants)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer (All Registrants) [Abstract]

Revenue from Contract with Customer [Text Block]

3. 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. Certain performance obligations such as power and capacity are generally delivered over time whereas other performance obligations such as RECs and ZECs are generally delivered at a point in time. In either case, revenues related to all of the performance obligations in such bundled power sale contracts are generally recognized concurrently as the power is generated. Except as noted in the paragraph below, there are no significant judgments in allocating the transaction price since all performance obligations are satisfied simultaneously upon the generation of power. 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 and the Utility Registrants)

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 and the Utility Registrants)

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 $32 million and $26 million as of December 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 $22 million and $30 million for the twelve months ended December 31, 2018, and December 31, 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 in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 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	50
Amounts reclassified to receivables	(146		)
Balance at December 31, 2018	$	187

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. The Generation contract liability related to the Illinois ZEC program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated Balance Sheets. 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 in Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to December 31, 2018:



Contract Liabilities	Exelon			Generation
Balance as of January 1, 2018	$	35		$	35
Increases as a result of additional cash received or due	179			465
Amounts recognized into revenues	(187		)	(458		)
Balance at December 31, 2018	$	27		$	42

The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of December 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 December 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	$	631	$	329	$	119	$	47	$	138	$	1,264
Generation	631		329		119		47		138		1,264

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

Regulatory Matters (All Registrants)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Regulatory Matters (All Registrants)

The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.

Utility Regulatory Matters (Exelon and the Utility Registrants)

Distribution Base Rate Case Proceedings

The following tables show the completed and pending distribution base rate case proceedings in 2018.

Completed Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement Increase (Decrease)				Approved Revenue Requirement Increase (Decrease)				Approved ROE		Approval Date	Rate Effective Date
ComEd - Illinois (Electric)^(b)	April 16, 2018	$	(23	)	^(a)	$	(24	)	^(a)	8.69	%	December 4, 2018	January 1, 2019
PECO - Pennsylvania (Electric)^(c)	March 29, 2018	$	82		^(a)	$	25		^(a)	N/A		December 20, 2018	January 1, 2019
BGE - Maryland (Natural Gas)	June 8, 2018 (amended August 24, 2018 and October 12, 2018)	$	61			$	43			9.8	%	January 4, 2019	January 4, 2019
Pepco - Maryland (Electric)	January 2, 2018 (amended February 5, 2018)	$	3		^(a)	$	(15	)	^(a)	9.5	%	May 31, 2018	June 1, 2018
Pepco - District of Columbia (Electric)^(d)	December 19, 2017 (amended February 9, 2018)	$	66			$	(24	)	^(a)	9.525	%	August 9, 2018	August 13, 2018
DPL - Maryland (Electric)^(e)	July 14, 2017 (amended November 16, 2017)	$	19			$	13			9.5	%	February 9, 2018	February 9, 2018
DPL - Delaware (Electric)	August 17, 2017 (amended February 9, 2018)	$	12		^(a)	$	(7	)	^(a)	9.7	%	August 21, 2018	March 17, 2018
DPL - Delaware (Natural Gas)	August 17, 2017 (amended February 9, 2018)	$	4		^(a)	$	(4	)	^(a)	9.7	%	November 8, 2018	March 17, 2018

__________


(a)	Includes the annual ongoing TCJA tax savings further discussed below.

(b)

Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1^st, with resulting rates effective in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation).

ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 million for the initial year revenue requirement for 2018 and an increase of $34 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and the annual reconciliation for 2017 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. See table below for ComEd's regulatory assets associated with its electric distribution formula rate.

During the first quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a result of this revision, ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory asset in the first quarter of 2017.


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


(d)	On September 7, 2018, Pepco submitted an updated filing for an increase of $4 million to the customer base rate credit established in connection with the merger between Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018.


(e)	The DPL Maryland base rate case proceeding was resolved through a settlement agreement, which did not specify an overall ROE. The settlement agreement included an ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs.

In the second quarter of 2018, DPL discovered a rate design issue in Maryland such that the current rates were not sufficient to collect the full amount of the $13 million revenue increase agreed to by the parties in the recent settlement. On September 5, 2018, the MDPSC approved DPL’s proposed revisions to resolve the rate design issue on a prospective basis, effective September 5, 2018.

Pending Distribution Base Rate Case Proceedings



Registrant/Jurisdiction	Filing Date	Requested Revenue Requirement Increase			Requested ROE		Expected Approval Timing
ACE - New Jersey (Electric)	August 21, 2018 (amended November 19, 2018)	$	122	^(a)	10.1	%	Third quarter of 2019^(b)
Pepco - Maryland (Electric)	January 15, 2019	$	30		10.3	%	Third quarter of 2019

__________


(a)	Requested increase is before New Jersey sales and use tax and includes $40 million of higher depreciation expense related to its updated depreciation study and the annual ongoing TCJA tax savings further discussed below.


(b)	ACE plans to put interim rates in effect on or around May 21, 2019, subject to refund, as allowed by the regulation.

Transmission Formula Rates

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation).

For 2018, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:



Registrant	Initial Revenue Requirement (Decrease) Increase^(b)			Annual Reconciliation Increase/(Decrease)			Total Revenue Requirement (Decrease) Increase				Allowed Return on Rate Base^(d)		Allowed ROE^(e)
ComEd^(a)	$	(44	)	$	18		$	(26	)		8.32	%	11.50	%
BGE^(a)	10			4			26			^(c)	7.61	%	10.50	%
Pepco	6			2			8				7.82	%	10.50	%
DPL	14			13			27				7.29	%	10.50	%
ACE^(a)	4			(4		)	—				8.02	%	10.50	%

__________


(a)	The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.

(b)

The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69 million, $18 million, $13 million, $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See further discussion below.


(c)	The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE.


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

(e)

As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

Pending Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of providing transmission services. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested rate of return on common equity of 11%, inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission formula FERC may approve.

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

Tax Cuts and Jobs Act

The Utility Registrants have made filings with their state regulatory commissions to pass back tax savings related to TCJA to their distribution customers, which are detailed below. The tax savings include the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory liabilities established upon the enactment of the TCJA. The ongoing annual TCJA tax savings in the table below represent the annual savings for distribution customers reflected in the initial customers rates approved after the TCJA. Subsequent annual TCJA tax savings will be approved as part of the annual update to the electric distribution formula rate for ComEd or base rate case proceedings for PECO, BGE, Pepco, DPL and ACE.



	Ongoing TCJA Tax Savings				Stub Period Bill Credit from TCJA Tax Savings
Registrant/Jurisdiction	Amount		Approval Date	Rate Effective Date	Stub Period	Approval Date	Refund Amount/Period
ComEd - Illinois (Electric)	$	201	January 18, 2018	February 1, 2018	Not applicable
PECO - Pennsylvania (Electric)	$	71	December 20, 2018	January 1, 2019	January 1, 2018 - December 31, 2018	December 20, 2018	$67 / 2019 (majority in January)
PECO - Pennsylvania (Natural Gas)	$	4	(a)	July 1, 2018	Not applicable
BGE - Maryland (Electric)	$	72	January 31, 2018	February 1, 2018	January 1, 2018 - January 31, 2018	To be addressed in next electric distribution base rate case
BGE - Maryland (Natural Gas)	$	31	January 31, 2018	February 1, 2018	January 1, 2018 - January 31, 2018	January 4, 2019	$2 / Q1 2019
Pepco - Maryland (Electric)	$	31	May 31, 2018	June 1, 2018	January 1, 2018 - June 1, 2018	May 31, 2018	$10 / July 2018
Pepco - District of Columbia (Electric)	$	39	August 9, 2018	August 13, 2018	January 1, 2018 - August 12, 2018	September 7, 2018	$20 / September 2018
DPL - Maryland (Electric)	$	14	April 18, 2018	April 20, 2018	January 1, 2018 - March 31, 2018	April 18, 2018	$2 / June 2018
DPL - Delaware (Electric)	$	19	August 21, 2018	March 17, 2018	February 1, 2018 - March 17, 2018	August 21, 2018	$3 / Q4 2018
DPL - Delaware (Natural Gas)	$	7	November 8, 2018	March 17, 2018	February 1, 2018 - March 17, 2018	November 8, 2018	$1 / Q4 2018
ACE - New Jersey (Electric)	$	23	August 29, 2018	September 8, 2018	January 1, 2018 - June 30, 2018	August 29, 2018	$6 / Q4 2018

__________

(a)

On May 17, 2018, the PAPUC issued an order directing Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to that order, PECO filed a negative surcharge mechanism and began on July 1, 2018, to return the estimated annual 2018 tax savings above to its natural gas distribution customers.

As discussed above, 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 (as amended on March 13, 2017) and on February 23, 2018 (as amended on July 9, 2018), BGE and ComEd, Pepco, DPL and ACE, respectively, each filed with FERC to revise their transmission formula rate mechanisms to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets, including those established upon enactment of the TCJA. See discussion below for additional information regarding these filings.

See Note 14 - Income Taxes for additional information on Corporate Tax Reform.

Other State Regulatory Matters

Illinois Regulatory Matters

Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency formula rate on or before June 1^st each year, with resulting rates effective in January of the following year. The annual update is based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling provisions similar to those in ComEd’s electric distribution formula rate.

During 2018, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:



Filing Date	Requested Revenue Requirement Increase		Approved Revenue Requirement Increase			Approved ROE		Approval Date	Rate Effective Date
June 1, 2018	$	39	$	42	^(a)	8.69	%	December 4, 2018	January 1, 2019

_________

(a)

ComEd’s 2018 approved revenue requirement above reflects an increase of $41 million for the initial year revenue requirement for 2018 and 2019 and an increase of $1 million related to the annual reconciliation for 2017. The revenue requirement for 2018 and 2019 and the annual reconciliation for 2017 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. See table below for ComEd's regulatory assets associated with its energy efficiency formula rate.

Maryland Regulatory Matters

Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs. The Commission accepted BGE's positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the SOS. The appeal currently resides with the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. See AMI programs in the Regulatory Assets and Liabilities section below for additional information.

As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-beneficial advanced metering system. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3^rd order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. BGE and the residential consumer advocate subsequently both filed a petition for rehearing of the June 3^rd order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative.

As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution base rate case, BGE recorded a $52 million charge in June 2016 to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets and reclassified $56 million of legacy meter costs from Property, plant and equipment, net to Regulatory assets in Exelon's and BGE's Consolidated Balance Sheets. In BGE’s 2018 natural gas distribution base rate case, the MDPSC allowed BGE to recover the gas portion of the post-test year regulatory asset, including a return thereon, over three years. The electric portion of the same regulatory asset will be addressed in BGE’s next electric distribution base rate case.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation in Maryland was signed into law to establish a mechanism, separate from base rate proceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred after June 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution base rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation.

On December 1, 2017 (as amended on January 22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge will be effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million, with an associated revenue requirement of $200 million.

District of Columbia Regulatory Matters

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). The District of Columbia government enacted on a permanent basis (effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, a projected six year, $500 million project to place underground some of the District of Columbia’s most outage-prone power lines with $250 million of the project costs funded by Pepco and $250 million funded by the District of Columbia.

The $250 million of project costs funded by Pepco will earn a return and be recovered through a volumetric surcharge on the electric bill of Pepco's customers in the District of Columbia.

The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to $62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the operation and maintenance of assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion, and Pepco will not recover or earn a return on the cost of these assets.

In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year plan in the DC PLUG initiative (the First Biennial Plan) on July 3, 2017. Pepco will then be required to make two additional applications. On November 9, 2017, the DCPSC issued an order approving the First Biennial Plan and the application for a financing order. Pursuant to that order, Pepco is obligated to pay $187.5 million to the District of Columbia over the six-year project term, of which it expects to pay $30 million in 2019. Pepco recorded an obligation and offsetting regulatory asset in November. Rates for the DC PLUG initiative went into effect on February 7, 2018.

New Jersey Regulatory Matters

ACE Infrastructure Investment Program Filing (Exelon, PHI and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s Infrastructure Investment Program (IIP) proposing to seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. ACE currently expects a decision in this matter in the second quarter of 2019 but cannot predict if the NJBPU will approve the application as filed.

New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE). The Consolidated Tax Adjustment (CTA) is a ratemaking policy that requires utilities that are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base. After opening a generic proceeding to review the policy, in 2014, the NJBPU issued a decision which retained the CTA, but in a modified format that significantly reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. The NJBPU issued a proposed rule for comment, consistent with the requirements of the Administrative Procedures Act. On January 17, 2019, the NJBPU adopted the proposed CTA regulations, which do not have a material impact on ACE. The CTA regulations will be sent to the Office of Administrative Law for publication in the New Jersey Register, which is expected on or before March 4, 2019.

New Jersey Clean Energy Legislation (Exelon and ACE). On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021; lowers the solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency standard that each electric public utility will be required to reduce annual usage by 2% and provides for utilities to annually file for recovery of the costs of the programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution system; and requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property which the NJBPU issued regulations on January 17, 2019.

On the same day, the Governor of New Jersey also signed new legislation, effective immediately, that will 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. Electric distribution utilities in New Jersey, including ACE, will be authorized to collect from retail distribution customers through a non-bypassable charge all costs associated with the utility’s procurement of the ZECs. See Generation Regulatory Matters below for additional information.

Other Federal Regulatory Matters

Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). On December 13, 2016 (as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. ComEd, Pepco, DPL and ACE had similar transmission-related income tax regulatory liabilities and assets also requiring FERC approval. On November 16, 2017, FERC issued an order rejecting BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. FERC’s rejection order focused on the lack of timeliness of BGE’s request to recover amounts that would have been previously amortized but indicated that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. Based on FERC’s 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 the following charges to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017, reducing their associated transmission-related income tax regulatory assets. 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. See above for additional information regarding PECO's transmission formula rate filing.



	For the year ended December 31, 2017
Exelon	$	35
ComEd	3
BGE	5
PHI	27
Pepco	14
DPL	6
ACE	7

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, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. 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 the 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.

On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, and ACE each filed with FERC to revise their transmission formula rate mechanisms to facilitate passing back to customers ongoing annual TCJA tax savings and to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.

On September 7, 2018, FERC issued orders rejecting BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and ACE's February 23, 2018 (as amended on July 9, 2018) filings, again citing the lack of timeliness of the requests to recover amounts that would have been previously amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue requirement. The orders did not address the remittance of TCJA transmission-related income tax regulatory liabilities, but rather referenced FERC’s separate Notice of Inquiry of such amounts issued on March 15, 2018.

On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted new filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-related income tax regulatory liabilities for the prospective period starting on October 1, 2018. FERC issued deficiency letters requesting additional information on November 21, 2018 and January 28, 2019. ComEd, BGE, Pepco, DPL, and ACE responded to the November 21, 2018 deficiency letter on November 29, 2018 but cannot predict the outcome of these FERC proceedings. If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would record additional charges to Income tax expense, which could be up to approximately $76 million, $51 million, $15 million, $10 million, $3 million, $5 million and $2 million, respectively, as of December 31, 2018.

On October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order, still seeking full recovery of their existing transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery. ComEd, Pepco, DPL, and ACE cannot predict the outcome of this rehearing request. On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit.

PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500 kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or recovered through PJM wholesale transmission rates through December 2025.

On May 31, 2018, FERC issued an order approving the settlement and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the order, similar charges for the period January 1, 2016 through June 30, 2018 will also be refunded or recovered through PJM wholesale transmission rates over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018. The Utility Registrants expect to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, several parties filed petitions for rehearing or clarification.

Pursuant to the FERC approval of the settlement and the expected refund or recovery of the associated amounts from electric distribution customers, in the second quarter of 2018 and as adjusted in the third quarter of 2018, the Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities. Generation recorded a $41 million net payable to PJM and a pre-tax charge within Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.



	PJM Receivable		PJM Payable		Regulatory Asset		Regulatory Liability
Exelon	$	220	$	176	$	136	$	221
Generation^(a)	—		41		—		—
ComEd	122		—		—		122
PECO	85		—		—		85
BGE	—		51		51		—
PHI	13		84		85		14
Pepco	—		84		84		—
DPL	10		—		—		10
ACE	3		—		1		4

__________


(a)	Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.

Regulatory Assets and Liabilities

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 December 31, 2018 and December 31, 2017:



December 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	2,553	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and other postretirement benefits - Merger related	1,266		—		—		—		—		—		—		—
Deferred income taxes	414		—		404		—		10		10		—		—
AMI programs - Deployment Costs	202		—		—		113		89		50		39		—
AMI programs - Legacy Meters	328		136		24		48		120		90		30		—
AMI programs - Post-test year costs	32		—		—		32		—		—		—		—
Electric distribution formula rate annual reconciliations	158		158		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	81		81		—		—		—		—		—		—
Energy efficiency costs	472		472		—		—		—		—		—		—
Fair value of long-term debt	702		—		—		—		569		—		—		—
Fair value of PHI's unamortized energy contracts	561		—		—		—		561		—		—		—
Asset retirement obligations	118		79		22		16		1		1		—		—
MGP remediation costs	326		309		17		—		—		—		—		—
Renewable energy	249		249		—		—		—		—		—		—
Electric Energy and Natural Gas Costs	193		—		49		51		93		84		—		9
Transmission formula rate annual reconciliations	41		6		—		4		31		10		14		7
Energy efficiency and demand response programs	545		—		1		289		255		188		67		—
Merger integration costs	42		—		—		3		39		18		11		10
Under-recovered revenue decoupling	59		—		—		2		57		57		—		—
Securitized stranded costs	50		—		—		—		50		—		—		50
Removal costs	564		—		—		—		564		158		97		309
DC PLUG charge	159		—		—		—		159		159		—		—
Deferred storm costs	41		—		—		—		41		9		4		28
Other	303		110		24		17		162		79		28		13
Total regulatory assets	9,459		1,600		541		575		2,801		913		290		426
Less: current portion	1,222		293		81		177		489		270		59		40
Total noncurrent regulatory assets	$	8,237	$	1,307	$	460	$	398	$	2,312	$	643	$	231	$	386



December 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	5,228	$	2,394	$	—	$	1,132	$	1,702	$	798	$	510	$	394
Nuclear decommissioning	2,606		2,217		389		—		—		—		—		—
Removal costs	1,547		1,368		—		52		127		20		107		—
Electric Energy and Natural Gas Costs	294		137		132		6		19		—		18		1
Other	528		227		75		79		100		11		30		25
Total regulatory liabilities	10,203		6,343		596		1,269		1,948		829		665		420
Less: current portion	644		293		175		77		84		7		59		18
Total noncurrent regulatory liabilities	$	9,559	$	6,050	$	421	$	1,192	$	1,864	$	822	$	606	$	402



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	2,455	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and other postretirement benefits - Merger related	1,393		—		—		—		—		—		—		—
Deferred income taxes	306		—		297		—		9		9		—		—
AMI programs - Deployment costs	385		—		—		129		101		58		43		—
AMI programs - Legacy meters	223		155		36		53		134		100		34		—
AMI programs - Post-test year costs	32		—		—		32		—		—		—		—
Electric distribution formula rate annual reconciliations	186		186		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	58		58		—		—		—		—		—		—
Energy efficiency costs	166		166		—		—		—		—		—		—
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		—		—		—		—		—
Renewable energy	258		256		—		—		2		—		1		1
Electric energy and natural gas costs	47		—		1		16		30		8		7		15
Transmission formula rate annual reconciliations	35		6		—		7		22		3		8		11
Energy efficiency and demand response programs	596		—		1		285		310		229		81		—
Merger integration costs	45		—		—		6		39		20		10		9
Under-recovered revenue decoupling	55		—		—		14		41		38		3		—
Securitized stranded costs	79		—		—		—		79		—		—		79
Removal costs	529		—		—		—		529		150		93		286
DC PLUG charge	190		—		—		—		190		190		—		—
Deferred storm costs	27		—		—		—		27		7		5		15
Other	311		106		31		15		165		79		29		14
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
Deferred income taxes	$	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		—
Electric Energy and Natural Gas Costs	111		47		60		—		4		—		1		3
Other	399		185		94		26		64		3		14		8
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

Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.



Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Pension and Other Postretirement Benefits	Primarily reflects the Utility Registrants' portion of deferred costs, including unamortized actuarial losses (gains) and prior service costs (credits), associated with Exelon's pension and other postretirement benefit plans, which are recovered through customer rates once amortized through net periodic benefit cost. Also, includes the Utility Registrants' non–service cost components capitalized in Property, plant and equipment, net on their Consolidated Balance Sheets.	The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 16 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	No
Pension and Other Postretirement Benefits - Merger Related	The deferred costs are amortized over the plan participants' average remaining service periods subject to applicable pension and other postretirement cost recognition policies. See Note 16 – Retirement Benefits for additional information. The capitalized non–service cost components are amortized over the lives of the underlying assets.	Legacy Constellation - 2038 Legacy PHI - 2032	No



Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Deferred Income Taxes	Deferred income taxes that are recoverable or refundable through customer rates, primarily associated with accelerated depreciation, the equity component of AFUDC, and the effects of income tax rate changes, including those resulting from the TCJA. These amounts include transmission-related regulatory liabilities that require FERC approval separate from the transmission formula rate. See Transmission-Related Income Tax Regulatory Assets section above for additional information.	Over the period in which the related deferred income taxes reverse, which is generally based on the expected life of the underlying assets. For TCJA, generally refunded over the remaining depreciable life of the underlying assets, except in certain jurisdictions where the commissions have approved a shorter refund period for certain assets not subject to IRS normalization rules.	No
AMI Programs - Deployment Costs	Installation costs of new smart meters, including implementation costs at Pepco and DPL of dynamic pricing for energy usage resulting from smart meters.	BGE - 2026 Pepco - 2027 DPL - 2030	Yes
AMI Programs - Legacy Meters	Early retirement costs of legacy meters.	ComEd - 2028 PECO - 2020 BGE - 2028 Pepco - 2027 DPL - 2030	ComEd, Pepco (District of Columbia), DPL (Delaware) - Yes PECO, BGE, Pepco (Maryland), DPL (Maryland) - No
AMI Programs - Post-test year incremental costs	Post-test year incremental program deployment costs of smart meters. As of December 31, 2018 and 2017, the portion of BGE's regulatory asset related to gas and electric costs was $10 million and $22 million, respectively.	BGE (gas) - 2021 BGE (electric) - Not currently being recovered.	BGE (gas) - Yes BGE (electric) - No
Electric distribution formula rate annual reconciliations	Under-recoveries related to electric distribution service costs recoverable through ComEd's performance-based formula rate, which is updated annually with rates effective on January 1^st.	2020	Yes
Electric distribution formula rate significant one-time events	Under-recoveries of electric distribution service costs related to significant one-time events (e.g., storm costs), which are recovered over 5 years from date of the event.	2022	Yes



Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Energy Efficiency Costs	Costs recovered through the energy efficiency formula rate tariff and the reconciliation of the difference of the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs. Deferred energy efficiency costs are recovered over the weighted average useful life of the related energy measure.	2029	Yes
Fair Value of Long-Term Debt	Represents the difference between the carrying value and fair value of long-term debt of PHI and BGE of $569 million and $133 million, respectively, as of December 30, 2018 and $619 million and $139 million, respectively, as of December 30, 2017, as of the PHI and Constellation merger dates.	BGE - 2043 PHI - 2045	No
Fair Value of PHI’s Unamortized Energy Contracts	Represents the regulatory assets recorded at Exelon and PHI offsetting the fair value adjustment related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI merger date.	2036	No
Asset Retirement Obligations	Future legally required removal costs associated with existing asset retirement obligations.	Over the life of the related assets.	Yes, once the removal activities have been performed.
MGP Remediation Costs	Environmental remediation costs for MGP sites.	Over the expected remediation period. See Note 22 - Commitments and Contingencies for additional information.	ComEd, PECO - No
Renewable Energy	Represents the change in fair value of ComEd‘s 20-year floating-to-fixed long-term renewable energy swap contracts.	2032	No
Electric Energy and Natural Gas Costs	Under (over) recoveries related to energy and gas supply related costs recoverable (refundable) under approved rate riders.	2025	DPL (Delaware), ACE - Yes ComEd, PECO, BGE, Pepco, DPL (Maryland) - No
Transmission formula rate annual reconciliations	Under (over)-recoveries related to transmission service costs recoverable through the Utility Registrants’ FERC formula rates, which are updated annually with rates effective each June 1^st.	2020	Yes



Line Item	Description	End Date of Remaining Recovery/Refund Period	Return
Energy efficiency and demand response programs	Includes under (over)-recoveries of costs incurred related to energy efficiency programs and demand response programs and recoverable costs associated with customer direct load control and energy efficiency and conservation programs that are being recovered from customers.	PECO - 2021 BGE - 2023 Pepco, DPL - 2033	BGE, Pepco, DPL, ACE - Yes PECO - Yes on capital investment recovered through this mechanism
Merger Integration Costs	Integration costs to achieve distribution synergies related to the Constellation merger and PHI acquisition. Costs for Pepco (Maryland) and Pepco (District of Columbia) were $9 million each as of December 31, 2018 and $11 million and $9 million, respectively, as of December 31, 2017.	BGE - 2021 Pepco - 2021 DPL- 2023 ACE - Not currently being recovered.	BGE, Pepco (Maryland), DPL - Yes Pepco (District of Columbia), ACE - No
Under (Over)-Recovered Revenue Decoupling	Electric and / or gas distribution costs recoverable from or (refundable) to customers under decoupling mechanisms.	BGE, Pepco and DPL - 2019	BGE, Pepco, DPL- No
Securitized Stranded Costs	Represents certain stranded costs associated with ACE's former electricity generation business.	2022	Yes
Removal Costs	For PHI, Pepco, DPL and ACE, the regulatory asset represents costs incurred to remove property, plant and equipment in excess of amounts received from customers through depreciation rates. For ComEd, BGE, PHI, Pepco and DPL, the regulatory liability represents amounts received from customers through depreciation rates to cover the future non–legally required cost to remove property, plant and equipment, which reduces rate base for ratemaking purposes.	PHI, Pepco, DPL and ACE - Asset is generally recovered over the life of the underlining assets. ComEd, BGE, PHI, Pepco and DPL - The liability is reduced as costs are incurred.	Yes
DC PLUG Charge	Costs associated with the DC Plug Initiative. See District of Columbia Regulatory Matters discussion above.	2019 - $30M $127 million to be determined based on future biennial plans filed with the DCPSC.	Portion of asset funded by Pepco-Yes
Deferred Storm Costs	For Pepco, DPL and ACE amounts represent total incremental storm restoration costs incurred due to major storm events recoverable from customers in the Maryland and New Jersey jurisdictions.	Pepco - 2022 DPL - 2023 ACE - 2020	Pepco, DPL - Yes ACE - No
Nuclear Decommissioning	Estimated future decommissioning costs for the Regulatory Agreement Units that are less than the associated NDT fund assets. See Note 15 - Asset Retirement Obligations for additional information	Not currently being refunded.	No

Capitalized Ratemaking Amounts Not Recognized

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



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

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.

Generation Regulatory Matters (Exelon and Generation)

Illinois Regulatory Matters

Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1 and Quad Cities Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.

Generation executed the required ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue, with compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year, June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. For the year ended December 31, 2018, Generation recognized revenue of $373 million, of which $150 million related to ZECs generated from June 1, 2017 through December 31, 2017.

On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of setting wholesale prices and sought a permanent injunction preventing the implementation of the program. Exelon intervened and filed motions to dismiss in both lawsuits, which were granted by the district court. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. The U.S. Circuit Court of Appeals for the Seventh Circuit panel denied the plaintiffs’ request for rehearing on October 9, 2018. On January 7, 2019, plaintiffs filed a petition seeking Supreme Court review of the case.

New Jersey Regulatory Matters

New Jersey Clean Energy Legislation. On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that will 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. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. Selected nuclear plants will receive annual 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. The quantity of ZECs issued will be determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price. On November 19, 2018, the NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which Generation owns a 42.59% ownership interest, to participate in the ZEC program. On the same day, Generation filed certain Supplemental Information with the NJBPU providing proprietary information that was requested in the application but which could not be shared with PSEG. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. See Note 8 - Early Plant Retirements for additional information on New Jersey’s ZEC program potential impacts to PSEG’s Salem nuclear plant.

New York Regulatory Matters

New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which included a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that met specific criteria demonstrating public necessity, determined by the NYPSC to be Generation's FitzPatrick, Ginna and Nine Mile Point nuclear facilities. The New York State Energy Research and Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on increases in underlying energy and capacity prices. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) is required to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from ratepayers is incorporated into the commodity charges on customer bills.

Generation is currently recognizing revenue for the sale of New York ZECs in the month they are generated and for the years ended December 31, 2018 and 2017, Generation has recognized revenue of $438 million and $311 million, respectively.

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, several parties filed motions to intervene in the case and to dismiss the lawsuit. On July 25, 2017, the court granted the motions to dismiss. On September 27, 2018, the U.S. Court of Appeals for the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a petition seeking Supreme Court review of the case.

In addition, on November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisions of the State Administrative Procedures Act when adopting the ZEC program. Subsequently, Generation, CENG and the NYPSC filed motions to dismiss the state court action, which were later opposed by the plaintiffs. On January 22, 2018, the court dismissed the environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims, without commenting on the merits of the case. Generation, CENG and the state's answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filed a reply brief introducing new arguments and new evidence. The State of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and CENG filed a motion to strike the new arguments and new evidence. After briefing is completed, the court will decide whether or not to set the case for hearing.

Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 - Early Plant Retirements for additional information related to Ginna and Nine Mile Point, and Note 5 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time.

On April 8, 2016, FERC accepted Ginna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31, 2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.

The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 8 - Early Plant Retirements for additional information regarding the impacts of a decision to early retire a nuclear plant.

Federal Regulatory Matters

Operating License Renewals

Conowingo Hydroelectric Project. 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, Generation and the U.S. Fish and Wildlife Service of the U.S. 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 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, the MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with MDE, alleging that the conditions are unfair and onerous violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer action on the federal license while these significant state and federal law issues are pending. On July 9, 2018, MDE filed a motion to dismiss Generation's complaint in state court, which was granted without prejudice on October 9, 2018. The court found MDE's Certification was not a "final decision" of Exelon's rights and because Exelon's motion for reconsideration remains pending, as does its administrative appeal of the 401 Certification, there was no final administrative decision for the court to review at this time. On November 5, 2018, Exelon appealed the Maryland Circuit Court's dismissal of Exelon's state complaint. Exelon continues to challenge the 401 Certification through the administrative process and in federal court. Exelon and Generation cannot predict the final outcome or its financial impact, if any, on Exelon or Generation.

As of December 31, 2018, $37 million of direct costs associated with Conowingo licensing efforts have been capitalized.

Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3. Generation anticipates the second license renewal process to take approximately 2 years from the application submission until completion of the NRC’s review process. Peach Bottom Units 2 and 3 are currently licensed to operate through 2033 and 2034, respectively.

PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.

Mergers, Acquisitions and Dispositions (All Registrants)

12 Months Ended

Dec. 31, 2018

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions

Mergers, Acquisitions and Dispositions (Exelon, Generation and PHI)

Acquisition of FirstEnergy Solutions Load Business (Exelon and Generation)

On July 9, 2018, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with FirstEnergy Solutions Corporation (FirstEnergy). Pursuant to the Purchase Agreement, FirstEnergy agreed to assign all of its retail electricity and wholesale load serving contracts and certain other related commodity contracts to Generation for an all cash purchase price of $140 million. The closing of the transaction was subject to certain conditions including the approval of the Purchase Agreement by the United States Bankruptcy Court for the Northern District of Ohio (Bankruptcy Court). At FirstEnergy's request, Bankruptcy Court's review of the transaction was delayed on six occasions, and Generation disputed these delays with the Bankruptcy Court. On January 23, 2019 the Bankruptcy Court approved an order that stipulated FirstEnergy's termination of the Purchase Agreement, effective January 22, 2019. The termination order provided for Generation to receive a refund of its escrow deposit, payment of a termination fee and reimbursement of transaction expenses, all of which were immaterial.

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 shutdown 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.

An after-tax bargain purchase gain of $233 million was included within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income which primarily reflects differences in strategies between Generation and Entergy for the intended use and ultimate decommissioning of the plant. See Note 15 — Asset Retirement Obligations and Note 16 — Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and pension and OPEB updates.

The following table summarizes the final 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 22-Commitments and Contingencies for additional information regarding SNF obligations to the DOE.

Exelon and Generation incurred $57 million of merger and integration related costs to FitzPatrick for the year ended December 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 year ended December 31, 2018.

Acquisition of ConEdison Solutions (Exelon and Generation)

On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction.

The purchase price of $257 million equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of the acquisition date.

Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI), for a total purchase price consideration of approximately $7.1 billion. As a result of the merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). Following the completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose subsidiary of EEDC.

Regulatory Matters

Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing 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.

Total nominal cost of commitments was $513 million excluding renewable generation commitments (approximately $444 million on a net present value basis amount, excluding renewable generation commitments and charitable contributions).

During the fourth quarter of 2018, Exelon finalized the application of $5 million funding for residential and non-residential customers in the DPL Maryland service territory. This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate and DPL. Exelon Corporate recorded a decrease of $5 million and DPL recorded an increase of $5 million in Operating and maintenance expense.

The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the merger date:



	Expected Payment Period			Successor
Description	Expected Payment Period	Exelon		PHI		Pepco		DPL		ACE
Rate credits	2016 - 2021	$	259	$	264	$	91	$	72	$	101
Energy efficiency	2016 - 2021	117		—		—		—		—
Charitable contributions	2016 - 2026	50		50		28		12		10
Delivery system modernization	Q2 2017	22		—		—		—		—
Green sustainability fund	Q2 2017	14		—		—		—		—
Workforce development	2016 - 2020	17		—		—		—		—
Other		29		6		1		5		—
Total commitments		$	508	$	320	$	120	$	89	$	111
Remaining commitments as of December 31, 2018		$	128	$	92	$	73	$	12	$	7

Pursuant to the orders approving the merger, Exelon made $73 million, $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively, in the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.

In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia and Delaware, at an estimated cost of approximately $127 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, will be recognized as incurred and recorded on Exelon's and Generation's financial statements. As of December 31, 2018, 27 MWs were developed and Exelon and Generation have incurred costs of $83 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that is pending review and approval with the DPSC. The third and final 40 MW wind REC tranche will be conducted in 2022.

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

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 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 Maryland Court of Appeals, which is the highest court in Maryland. On August 29, 2018, the Maryland Court of Appeals affirmed the MDPSC's May 2015 Order approving the merger of Exelon and PHI.

Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District Legal Entity of Columbia Office of People’s Counsel, the District of Columbia Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review of the DCPSC’s March 23, 2016 order with the District of Columbia Court of Appeals. On July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the merger.

Accounting for the Merger Transaction

The total purchase price consideration for the PHI merger was approximately $7.1 billion. The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4 billion, which was recognized as goodwill by PHI and Exelon at the merger date, reflecting the value associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. None of this goodwill is expected to be tax deductible. For purposes of future required impairment assessments, the goodwill has been assigned to PHI's reportable units Pepco, DPL and ACE. See Note 10 - Intangible Assets for additional information.

Immediately following closing of the merger, $235 million of net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed $163 million of such net assets to Generation.

Rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI's utility registrants, and therefore the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.

The current impact of PHI, including its unregulated businesses, in Exelon's Consolidated Statements of Operations and Comprehensive Income includes Operating revenues and Net Income (Loss) as follows:



	For the Years Ended December 31,
	2018	2017	2016
Operating Revenues	4,670	4,829	3,785
Net Income (Loss)	453	364	(66	)

For the periods ended December 31, 2018, 2017 and 2016, the Registrants have recognized costs to achieve the PHI merger as follows:



	For the Year Ended December 31,
Acquisition, Integration and Financing Costs^(a)	2018		2017			2016
Exelon	$	7	$	16		$	143
Generation	5		22			37
ComEd^(b)	—		1			(6		)
PECO	1		4			5
BGE^(b)	1		4			(1		)
Pepco^(b)	—		(6		)	28
DPL^(b)	—		(7		)	20
ACE^(b)	—		(6		)	19



	Successor							Predecessor
	For the Year Ended December 31,					March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Acquisition, Integration and Financing Costs^(a)	2018		2017			March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
PHI^(b)	$	—	$	(18	)	$	69	$	29

______________


(a)	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

(b)

For the year ended December 31, 2017, includes deferrals of previously incurred integration costs as regulatory assets of $24 million, $8 million, $8 million, and $8 million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $8 million, $6 million, $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information.

Pro-forma Impact of the Merger

The following unaudited pro-forma financial information reflects the consolidated results of operations of Exelon as if the PHI merger had taken place on January 1, 2015. The unaudited pro forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase accounting adjustments.

The unaudited pro-forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or future consolidated results of operations of the combined company.



	Year Ended December 31,
	2016^(a)		2015^(b)
Total operating revenues	$	32,342	$	33,823
Net income attributable to common shareholders	1,562		2,618

Basic earnings per share	$	1.69	$	2.85
Diluted earnings per share	1.69		2.84

______________


(a)	The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.


(b)	The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015.

Disposition of Oyster Creek (Exelon and Generation)

On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental Protection, LLC (OCEP), for the sale and decommissioning of the Oyster Creek Generating Station (Oyster Creek) located in Forked River, New Jersey. On September 17, 2018, Oyster Creek permanently ceased generation operations.

Under the terms of the transaction, Generation will transfer to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the spent fuel is moved offsite. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec to deliver a letter of credit to Generation upon the occurrence of specified events.

As a result of the transaction, in 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. At December 31, 2018 Generation has $897 million and $777 million of Assets held for sale and Liabilities held for sale, respectively, for Oyster Creek. Upon remeasurement of the Oyster Creek ARO in 2018, Exelon and Generation recognized an $84 million pre-tax charge to Operating and maintenance expense. See Note 15 -Asset Retirement Obligations for additional information.

Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and other regulatory approvals, and the receipt of a private letter ruling from the IRS. Generation currently anticipates satisfaction of the closing conditions to occur in the second half of 2019.

Disposition of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)

EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones. EGTP was an indirect wholly owned subsidiary of Exelon and Generation.

EGTP’s operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment loss. See Note 13 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 7 - Impairment of Long-Lived Assets and Intangibles for additional information.

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 that resulted in a pre-tax gain upon deconsolidation of $213 million. 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 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.

Other Asset Dispositions (Exelon, Generation, DPL and Pepco)

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 in Exelon's and Generation's 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 within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. In June 2018, additional proceeds were received, and a pre-tax gain was recorded within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

During the fourth quarter of 2016, as part of its continual assessment of growth and development opportunities, Generation reevaluated and in certain instances terminated or renegotiated certain projects and contracts. As a result, a pre-tax loss of $69 million was recorded within Loss on sales of assets and businesses and pre-tax impairment charges of $23 million was recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 13 - Debt and Credit Agreements for additional information. In December 2016, Generation sold substantially all of the Upstream assets for $37 million which resulted in a pre-tax loss on sale of $10 million which is included in Gain (loss) on sales of assets and businesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Property, Plant and Equipment (All Registrants)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment (All Registrants)

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-90	$	53,090	$	49,506
Electric—generation	1-56	29,170		29,019
Gas—transportation and distribution	5-90	5,530		5,050
Common—electric and gas	5-75	1,627		1,447
Nuclear fuel ^(a)	1-8	5,957		6,420
Construction work in progress	N/A	3,377		2,825
Other property, plant and equipment ^(b)	1-50	858		999
Total property, plant and equipment		99,609		95,266
Less: accumulated depreciation ^(c)		22,902		21,064
Property, plant and equipment, net		$	76,707	$	74,202

__________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017. Includes land held for future use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $39 million, $19 million, $25 million, $61 million, $17 million and $28 million, respectively, at December 31, 2018.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.73	%	2.75	%	2.73	%
Electric—generation^(a)	5.37	%	4.36	%	5.94	%
Gas	2.07	%	2.10	%	2.17	%
Common—electric and gas	6.98	%	7.05	%	7.41	%

__________


(a)	See Note 8 — Early Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—generation	1-56	$	29,170	$	29,019
Nuclear fuel ^(a)	1-8	5,957		6,420
Construction work in progress	N/A	997		838
Other property, plant and equipment ^(b)	1-8	63		57
Total property, plant and equipment		36,187		36,334
Less: accumulated depreciation ^(c)		12,206		11,428
Property, plant and equipment, net		$	23,981	$	24,906

__________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively.


(b)	Includes buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively.

The annual depreciation provisions as a percentage of average service life for electric generation assets were 5.37%, 4.36% and 5.94% for the years ended December 31, 2018, 2017 and 2016, respectively. See Note 8 — Early Plant Retirements for additional information on the accelerated depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.

License Renewals

Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual renewal of the operating licenses for all of Generation's operating nuclear generating stations except for TMI and Clinton. As a result, the receipt of license renewals has no material impact in the Consolidated Statements of Operations and Comprehensive Income. Beginning in 2017, TMI and Oyster Creek depreciation provisions were based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown date of September 2018. Clinton depreciation provisions are based on an estimated useful life through 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 4 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 8 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirement.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-80	$	25,991	$	24,423
Construction work in progress	N/A	705		517
Other property, plant and equipment ^{(a), (b)}	35-50	46		52
Total property, plant and equipment		26,742		24,992
Less: accumulated depreciation		4,684		4,269
Property, plant and equipment, net		$	22,058	$	20,723

__________


(a)	Includes buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017.


(b)	Represents land held for future use and non-utility property.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.95%, 2.99% and 3.03% for the years ended December 31, 2018, 2017 and 2016, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-65	$	8,359	$	7,975
Gas—transportation and distribution	5-70	2,694		2,504
Common—electric and gas	5-50	756		710
Construction work in progress	N/A	343		254
Other property, plant and equipment ^(a)	50	19		21
Total property, plant and equipment		12,171		11,464
Less: accumulated depreciation		3,561		3,411
Property, plant and equipment, net		$	8,610	$	8,053

__________


(a)	Represents land held for future use and non-utility property.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.35	%	2.37	%	2.32	%
Gas	1.90	%	1.89	%	1.82	%
Common—electric and gas	5.44	%	5.47	%	5.11	%

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-90	$	7,951	$	7,464
Gas—distribution	5-90	2,630		2,379
Common—electric and gas	5-40	860		771
Construction work in progress	N/A	410		367
Other property, plant and equipment ^(a)	20	25		26
Total property, plant and equipment		11,876		11,007
Less: accumulated depreciation		3,633		3,405
Property, plant and equipment, net		$	8,243	$	7,602

__________


(a)	Represents plant held for future use and non-utility property.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.61	%	2.58	%	2.56	%
Gas	2.36	%	2.33	%	2.45	%
Common—electric and gas	8.50	%	8.64	%	9.45	%

PHI

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-75	$	12,664	$	11,517
Gas—distribution	5-75	486		449
Common—electric and gas	5-75	126		82
Construction work in progress	N/A	912		835
Other property, plant and equipment ^(a)	3-43	99		102
Total property, plant and equipment		14,287		12,985
Less: accumulated depreciation		841		487
Property, plant and equipment, net		$	13,446	$	12,498

__________


(a)	Represents plant held for future use and non-utility property.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.61	%	2.63	%	2.52	%
Gas	1.59	%	2.07	%	2.57	%
Common—electric and gas	6.30	%	6.50	%	8.12	%

Pepco

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-75	$	9,217	$	8,646
Construction work in progress	N/A	536		473
Other property, plant and equipment^(a)	25-33	61		59
Total property, plant and equipment		9,814		9,178
Less: accumulated depreciation		3,354		3,177
Property, plant and equipment, net		$	6,460	$	6,001

__________


(a)	Represents plant held for future use and non-utility property.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.40%, 2.35% and 2.17% for the years ended December 31, 2018, 2017 and 2016, respectively.

DPL

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-70	$	4,195	$	3,875
Gas—distribution	5-75	651		614
Common—electric and gas	5-75	136		117
Construction work in progress	N/A	151		205
Other property, plant and equipment ^(a)	10-43	17		15
Total property, plant and equipment		5,150		4,826
Less: accumulated depreciation		1,329		1,247
Property, plant and equipment, net		$	3,821	$	3,579

__________


(a)	Represents plant held for future use and non-utility property.

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.77	%	2.75	%	2.49	%
Gas	1.59	%	2.07	%	2.57	%
Common—electric and gas	3.70	%	4.14	%	4.99	%

ACE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-60	$	3,866	$	3,607
Construction work in progress	N/A	209		138
Other property, plant and equipment ^(a)	13-15	28		27
Total property, plant and equipment		4,103		3,772
Less: accumulated depreciation		1,137		1,066
Property, plant and equipment, net		$	2,966	$	2,706

__________


(a)	Represents plant held for future use and non-utility property.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.45%, 2.46% and 2.45% for the years ended December 31, 2018, 2017 and 2016, respectively.

Capitalized Software Costs (All Registrants)

The following tables presents net unamortized capitalized software costs and amortization of capitalized software costs by year.



Net unamortized software costs	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2018	$	810	$	164	$	206	$	98	$	166	$	165	$	26	$	21	$	14
December 31, 2017	834		173		227		111		179		133		2		1		1



Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
2018	$	282	$	78	$	79	$	37	$	48	$	2	$	2	$	1
2017	270		73		73		39		46		—		—		—
2016	255		72		62		33		44		—		—		—



	Successor						Predecessor
PHI	For the year ended December 31, 2018		For the year ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Amortization of capitalized software costs	$	33	$	34	$	29	$	8

Capitalized Interest and AFUDC (All Registrants)

The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:



		Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
2018	Total incurred interest^(a)	$	1,695	$	464	$	377	$	141	$	130	$	162	$	62	$	68
	Capitalized interest	31		31		—		—		—		—		—		—
	Credits to AFUDC debt and equity	109		—		30		12		24		34		4		4
2017	Total incurred interest^(a)	$	1,658	$	502	$	369	$	130	$	111	$	133	$	54	$	64
	Capitalized interest	63		63		—		—		—		—		—		—
	Credits to AFUDC debt and equity	108		—		20		12		22		34		10		9
2016	Total incurred interest^(a)	$	1,678	$	472	$	469	$	127	$	114	$	137	$	52	$	65
	Capitalized interest	108		107		—		—		—		—		—		—
	Credits to AFUDC debt and equity	98		—		22		11		30		29		7		9



	Successor						Predecessor
PHI	For the year ended December 31, 2018		For the year ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Total incurred interest^(a)	$	305	$	263	$	207	$	68
Credits to AFUDC debt and equity	44		54		35		10

__________


(a)	Includes interest expense to affiliates.

See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 13 — Debt and Credit Agreements for additional information regarding Exelon’s, ComEd’s and PECO’s property, plant and equipment subject to mortgage liens.

Impairment of Long-lived Assets (Exelon and Generation)	12 Months Ended
Impairment of Long-lived Assets (Exelon and Generation)	Dec. 31, 2018
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Impairment Of Long-Lived Assets (Exelon and Generation)	(Exelon, Generation and PHI) Long-Lived Assets (Exelon, Generation and PHI) Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2018, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than its carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result, long-lived merchant wind assets held and used with a net carrying amount of $41 million were fully impaired and a pre-tax impairment charge of $41 million was recorded during 2018 within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. 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 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 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. 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, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights were to be determined over time through future negotiations. In the fourth quarter of 2017, based upon the lack of currently available sponsorship opportunities, the asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon’s and PHI’s Consolidated Statements of Operations and Comprehensive Income. On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax impairment charge of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income during 2017. On November 7, 2017, EGTP and 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 and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their consolidated financial statements. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. In the second quarter of 2016, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter of 2016 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. In the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its Upstream subsidiary CEU Holdings, LLC (as described in Note 13 — Debt and Credit Agreements) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream natural gas and oil exploration and production business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 13 — Debt and Credit Agreements for additional information. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 5 — Mergers, Acquisitions and Dispositions for additional information. The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material. Like-Kind Exchange Transaction (Exelon) In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased back to MEAG as part of the transactions (Leases). Pursuant to the applicable authoritative guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other-than-temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments based on the income approach, which uses a discounted cash flow analysis, taking into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements. All the Headleases were terminated by the second quarter of 2016, and no events occurred prior to the termination that required Exelon to review the estimated residual values of the direct financing lease investments in 2016. On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income. See Note 14 — Income Taxes for additional information.

Early Plant Retirements Early Plant Retirements (Exelon, Generation)

12 Months Ended

Dec. 31, 2018

Implications of Potential Early Plant Retirements [Abstract]

Implications Of Potential Early Retirement Disclosure [Text Block]

Early Plant Retirements (Exelon and Generation)

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

Nuclear Generation

In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors.

On June 2, 2016, Generation announced it would shutdown the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively, given a lack of progress on Illinois energy legislation and MISO market reforms, and capacity auctions results that failed to cover cash operating costs and a risk-adjusted rate of return to shareholders.

On December 7, 2016, Illinois FEJA was signed into law by the Governor of Illinois and included a ZES that now provides compensation to Clinton and Quad Cities for the carbon-free attributes of their production through 2027. With the passage of the Illinois ZES in December 2016, Generation reversed its June 2016 decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants. Clinton and Quad Cities are currently licensed to operate through 2026 and 2032, respectively. See Note 4 - Regulatory Matters for additional information on the Illinois FEJA and the ZES.

In New York, the Ginna and Nine Mile Point nuclear plants faced similar economic challenges and on August 1, 2016, the NYPSC issued an order adopting the CES, which now provides payments to Ginna and Nine Mile Point, as well as FitzPatrick, for the environmental attributes of their production through 2029. Ginna and Nine Mile Point Unit 1 are currently licensed to operate through 2029, and Nine Mile Point Unit 2 through 2046. See Note 4 - Regulatory Matters for additional information on the New York CES.

Assuming the continued effectiveness of both 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 financial statements.

In Pennsylvania, the TMI nuclear plant failed to clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear in the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019. TMI is currently committed to operate through May 2019 and is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to shutdown the plant. PJM has subsequently notified Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.

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 continued to face rising operating costs amid a historically low wholesale power price environment. On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased generation operations in September 2018.

As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized 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 15 — Asset Retirement Obligations for additional information on changes to the nuclear decommissioning ARO balance. The total annual impact of these charges by year are summarized in the table below.



Income statement expense (pre-tax)	2018^(a)		2017^(b)		2016^(c)
Depreciation and Amortization
Accelerated depreciation^(d)	$	539	$	250	$	712
Accelerated nuclear fuel amortization	57		12		60
Operating and Maintenance
One-time charges^(e,f)	32		77		26
Change in ARO accretion, net of any contractual offset^(g)	—		—		2
Contractual offset for ARC depreciation^(g)	—		—		(86		)
Total	$	628	$	339	$	714

_________


(a)	Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.


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

(c)

Reflects incremental charges for Clinton and Quad Cities including incremental accelerated depreciation and amortization from June 2, 2016 through December 6, 2016. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation updated the expected economic useful life for both facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates.


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


(e)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.


(f)	In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially recorded in June 2016.

(g)

For Quad Cities based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision making authority to retire Salem.

On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, that will provide compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. The NJBPU must complete its processes for determining eligibility for, and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk of earlier retirement for Salem. See Note 4 - Regulatory Matters for additional information.

The following table provides the balance sheet amounts as of December 31, 2018 for Generation’s ownership share of the significant assets and liabilities associated with Salem that would potentially be impacted by a decision to permanently cease generation operations.



	December 31, 2018
Asset Balances
Materials and supplies inventory	$	45
Nuclear fuel inventory, net	118
Completed plant, net	538
Construction work in progress	44
Liability Balances
Asset retirement obligation	(395		)

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

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

Other Generation

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

The ISO-NE announced that it would take a three-step approach to fuel security.

•

First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel security for the 2022 - 2024 capacity commitment periods. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.


•	Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.

•

Third, ISO-NE stated its intention to 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. In its July 2, 2018 order, FERC ordered ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns. In January 2019, ISO-NE has indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. Among the costs included in the filing are costs associated with the Everett Marine Terminal. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. FERC also directed a paper hearing on ROE using a new methodology. Initial and reply briefs on ROE will be due on April 18, 2019 and July 18, 2019. These will be reflected in a compliance filing due February 18, 2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period.

The following table provides the balance sheet amounts as of December 31, 2018 for Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by a decision to permanently cease generation operations.



	December 31, 2018
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	20
Completed plant, net	901
Construction work in progress	9
Liability Balances
Asset retirement obligation	(1		)

To ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on October 1, 2018, Generation acquired the Everett Marine Terminal in Massachusetts for a purchase price of $81 million, with the majority of the fair value allocated to Property, plant and equipment and no goodwill recorded. Generation also settled its existing long-term gas supply agreement, resulting in a pre-tax gain of $75 million, which is included within Purchased power and fuel expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)

12 Months Ended

Dec. 31, 2018

Public Utilities, Property, Plant and Equipment [Abstract]

Jointly Owned Electric Utility Plant

Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)

Exelon's, Generation's, PECO's, BGE's, Pepco's, DPL's and ACE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2018 and 2017 were as follows:



	Nuclear Generation												Fossil-Fuel Generation			Transmission				Other
	Quad Cities			Peach Bottom			Salem^(a)			Nine Mile Point Unit 2			Wyman			PA^(b)		NJ/ DE^(c)		Other^(d)
Operator	Generation			Generation			PSEG Nuclear			Generation			FP&L			First Energy		PSEG/ DPL		various
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	5.89		%	various		various		various
Exelon’s share at December 31, 2018:
Plant^(e)	$	1,131		$	1,451		$	648		$	910		$	4		$	28	$	103	$	15
Accumulated depreciation^(e)	587			523			227			126			3			16		53		13
Construction work in progress	13			15			44			56			—			1		—		—
Exelon’s share at December 31, 2017:
Plant^(e)	$	1,074		$	1,417		$	631		$	839		$	3		$	27	$	102	$	15
Accumulated depreciation^(e)	550			461			205			97			3			15		52		13
Construction work in progress	35			18			33			55			—			—		—		—

__________


(a)	Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2018 and 2017.


(b)	PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.


(c)	PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.


(d)	Generation, DPL and ACE own a 44.24%, 11.91% and 4.83% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center.


(e)	Excludes asset retirement costs and general plant.

Exelon’s, Generation’s, PECO's, BGE's, Pepco's, DPL's and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO's, BGE's, Pepco's, DPL's and ACE's share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, BGE's, Pepco's, DPL's and ACE's Consolidated Statements of Operations and Comprehensive Income.

Intangible Assets (All Registrants)

12 Months Ended

Dec. 31, 2018

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets (All Registrants)

Intangible Assets (Exelon, Generation, ComEd, PECO, PHI, Pepco, DPL and ACE)

Goodwill

Exelon’s, ComEd’s and PHI's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2018 and 2017 were as follows:



	Balance at January 1, 2017		Impairment losses		Balance at December 31, 2017		Impairment losses		Balance at December 31, 2018
Exelon
Gross amount	$	8,660	$	—	$	8,660	$	—	$	8,660
Accumulated impairment loss	1,983		—		1,983		—		1,983
Carrying amount	6,677		—		6,677		—		6,677
ComEd^(a)
Gross amount	4,608		—		4,608		—		4,608
Accumulated impairment loss	1,983		—		1,983		—		1,983
Carrying amount	2,625		—		2,625		—		2,625
PHI^(b)
Gross amount	4,005		—		4,005		—		4,005
Carrying amount	4,005		—		4,005		—		4,005

__________


(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).


(b)	Reflects goodwill recorded in 2016 from the PHI merger.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL and ACE. See Note 24 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit. PHI identified an error related to the allocation of goodwill to its reporting units in 2016 while performing the 2018 annual impairment assessment. As revised in 2018, Exelon's and PHI's $4 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $2.1 billion, $1.4 billion and $0.5 billion, respectively, an increase (decrease) of $0.4 billion, $0.3 billion, and $(0.7) billion for Pepco, DPL and ACE, respectively, from the originally reported amounts. This error did not result in a change to the total amount of goodwill recorded at PHI nor would it have resulted in an impairment of PHI's goodwill in 2016 or 2017. Therefore, management has concluded that the error is not material to the previously issued financial statements.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. In performing a qualitative assessment, entities should assess, among other things, macroeconomic conditions, industry and market considerations, overall financial performance, cost factors and entity-specific events. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required.

If an entity bypasses the qualitative assessment or performs the qualitative assessment but determines that it is more likely than not that its fair value is less than its carrying amount, a quantitative two-step, fair value-based test is performed. Exelon's, ComEd's and PHI's accounting policy is to perform a quantitative test of goodwill at least once every three years. The first step in the quantitative test compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.

Application of the goodwill impairment test requires management judgment, including the identification of reporting units and determining the fair value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis. Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for ComEd's, Pepco's, DPL's and ACE's businesses and the fair value of debt. In applying the second step (if needed), management must estimate the fair value of specific assets and liabilities of the reporting unit.

2018 and 2017 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2018 and 2017 for ComEd and as of November 1, 2017 for PHI. As part of their qualitative assessments, ComEd and PHI evaluated, among other things, management’s best estimate of projected operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the discount rate and regulated utility peer company EBITDA multiples, while also considering, the passing margin from their last quantitative assessments as of November 1, 2016.

As a result of the reallocation of goodwill to PHI’s reporting units as discussed above, as of November 1, 2018, PHI performed a quantitative test for its 2018 annual goodwill impairment assessment. The first step of the test comparing the estimated fair values of the Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second step was required.

While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's and PHI’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective impairment tests.

Other Intangible Assets and Liabilities

Exelon’s, Generation’s, ComEd’s and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2018 and 2017:



	December 31, 2018									December 31, 2017
	Gross			Accumulated Amortization			Net			Gross			Accumulated Amortization			Net
Generation
Unamortized Energy Contracts^(b)	1,957			(1,588		)	369			1,938			(1,574		)	364
Customer Relationships	325			(162		)	163			305			(133		)	172
Trade Name	243			(171		)	72			243			(148		)	95
ComEd
Chicago Settlement Agreements^(c)	162			(148		)	14			162			(141		)	21
PHI
Unamortized Energy Contracts^(b)	(1,515		)	954			(561		)	(1,515		)	766			(749		)
Exelon Corporate
Software License^(a)	95			(34		)	61			95			(25		)	70
Exelon	$	1,267		$	(1,149	)	$	118		$	1,228		$	(1,255	)	$	(27	)

__________


(a)	On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.


(b)	Includes unamortized energy contract assets and liabilities in Exelon's, Generations and PHI's Consolidated Balance Sheets.


(c)	In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement.

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2018:



For the Years Ending December 31,	Exelon			Generation		ComEd		PHI
2019	$	(32	)	$	70	$	7	$	(119	)
2020	(20		)	78		7		(115		)
2021	(4		)	78		—		(92		)
2022	(23		)	56		—		(89		)
2023	(21		)	50		—		(81		)

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2018, 2017 and 2016:



For the Years Ended December 31,	Exelon ^(a)(b)			Generation ^(a)		ComEd		PHI^(b)
2018	$	(109	)	$	63	$	7	$	(188	)
2017	(237		)	83		7		(336		)
2016	(336		)	79		7		(430		)

__________


(a)	At Exelon and Generation, amortization of unamortized energy contracts totaling $14 million, $35 million and $35 million for the years ended December 31, 2018, 2017 and 2016, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.


(b)	At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.

Acquired Intangible Assets and Liabilities

Business combinations require the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.

Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy contracts that Exelon and Generation have acquired. The valuation of unamortized energy contracts was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise, the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The Exelon Wind unamortized energy contracts are amortized on a straight-line basis over the period in which the associated contract revenues are recognized as a decrease in Operating revenues within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG, Integrys and ConEdison, the fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition dates through either Operating revenues or Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. At PHI, offsetting regulatory assets or liabilities were also recorded. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities, respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows.

Customer Relationships. The customer relationship intangibles were determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key assumptions include the customer attrition rate and the discount rate. The authoritative guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. The amortization of the trade name is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, PECO, PHI, DPL and ACE)

Exelon’s, Generation’s, PECO's, PHI's, DPL's and ACE's other intangible assets, included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets, include RECs (Exelon, Generation, PHI, DPL and ACE) and AECs (Exelon and PECO). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

The following table summarizes the current and noncurrent Renewable and Alternative Energy Credits as of December 31, 2018 and 2017:



	As of December 31, 2018
	Exelon		Generation		PECO		PHI		DPL		ACE
Current AEC's	$	2	$	—	$	2	$	—	$	—	$	—
Current REC's	279		270		—		9		8		1
Noncurrent REC's	52		52		—		—		—		—
	As of December 31, 2017
	Exelon		Generation		PECO		PHI		DPL		ACE
Current AEC's	$	1	$	—	$	1	$	—	$	—	$	—
Current REC's	321		312		—		9		8		1
Noncurrent REC's	27		27		—		—		—		—

The entire disclosure for the aggregate amount of goodwill and a description of intangible assets, which may include (a) for amortizable intangible assets (also referred to as finite-lived intangible assets), the carrying amount, the amount of any significant residual value, and the weighted-average amortization period, (b) for intangible assets not subject to amortization (also referred to as indefinite-lived intangible assets), the carrying amount, and (c) the amount of research and development assets acquired and written off in the period, including the line item in the income statement in which the amounts written off are aggregated, if not readily apparent from the income statement. Also discloses (a) for amortizable intangibles assets in total and by major class, the gross carrying amount and accumulated amortization, the total amortization expense for the period, and the estimated aggregate amortization expense for each of the five succeeding fiscal years, (b) for intangible assets not subject to amortization the carrying amount in total and by major class, and (c) for goodwill, in total and for each reportable segment, the changes in the carrying amount of goodwill during the period (including the aggregate amount of goodwill acquired, the aggregate amount of impairment losses recognized, and the amount of goodwill included in the gain (loss) on disposal of a reporting unit). If any part of goodwill has not been allocated to a reportable segment, discloses the unallocated amount and the reasons for not allocating. For each impairment loss recognized related to an intangible asset (excluding goodwill), discloses: (a) a description of the impaired intangible asset and the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method for determining fair value, (c) the caption in the income statement or the statement of activities in which the impairment loss is aggregated, and (d) the segment in which the impaired intangible asset is reported. For each goodwill impairment loss recognized, discloses: (a) a description of the facts and circumstances leading to the impairment, (b) the amount of the impairment loss and the method of determining the fair value of the associated reporting unit, and (c) if a recognized impairment loss is an estimate not finalized and the reasons why the estimate is not final. May also disclose the nature and amount of any significant adjustments made to a previous estimate of an impairment loss.

Fair Value of Financial Assets and Liabilities (All Registrants)

Fair Value of Financial Assets and Liabilities (All Registrants)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair Value of Financial Liabilities Recorded at the Carrying Amount

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 December 31, 2018 and 2017:

Exelon



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



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

Generation



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



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

ComEd



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



	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)^(a)	$	7,601	$	—	$	8,418	$	—	$	8,418
Long-term debt to financing trusts^(b)	205		—		—		227		227

PECO



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



	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)^(a)	$	2,903	$	—	$	3,194	$	—	$	3,194
Long-term debt to financing trusts	184		—		—		204		204

BGE



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



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

PHI



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



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

Pepco



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



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

DPL



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



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

ACE



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



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

__________

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

(b) Includes unamortized debt issuance costs which are not fair valued of $0 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018. Includes unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2017.

Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in Other current liabilities) (Level 1) and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.

Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3.

The fair value of Generation’s and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities. Variable rate financing debt resets on a monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.

SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030. The carrying amount also includes $119 million and $114 million as of December 31, 2018 and 2017 for the one-time fee obligation associated with closing of the FitzPatrick acquisition on March 31, 2017. The fair value was determined using a similar methodology, however the New York Power Authority's (NYPA) discount rate is used in place of Generation's given the contractual right to reimbursement from NYPA for the obligation; see Note 5 - Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.

Long-Term Debt to Financing Trusts. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.

Recurring Fair Value Measurements

Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:


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


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


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

Generation and Exelon

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

The following tables present assets and liabilities measured and recorded at fair value in Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2018 and 2017:



	Generation										Exelon
As of December 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	581	$	—	$	—	$	—	$	581	$	1,243	$	—	$	—	$	—	$	1,243
NDT fund investments
Cash equivalents^(b)	252		86		—		—		338		252		86		—		—		338
Equities	2,918		1,591		—		1,381		5,890		2,918		1,591		—		1,381		5,890
Fixed income
Corporate debt	—		1,593		230		—		1,823		—		1,593		230		—		1,823
U.S. Treasury and agencies	2,081		99		—		—		2,180		2,081		99		—		—		2,180
Foreign governments	—		50		—		—		50		—		50		—		—		50
State and municipal debt	—		149		—		—		149		—		149		—		—		149
Other^(c)	—		30		—		846		876		—		30		—		846		876
Fixed income subtotal	2,081		1,921		230		846		5,078		2,081		1,921		230		846		5,078
Middle market lending	—		—		313		367		680		—		—		313		367		680
Private equity	—		—		—		329		329		—		—		—		329		329
Real estate	—		—		—		510		510		—		—		—		510		510
NDT fund investments subtotal^(d)	5,251		3,598		543		3,433		12,825		5,251		3,598		543		3,433		12,825



	Generation									Exelon
As of December 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
Pledged assets for Zion Station decommissioning
Cash equivalents	9		—		—		—	9		9		—		—		—	9
Equities	—		—		—		—	—		—		—		—		—	—
Middle market lending	—		—		—		—	—		—		—		—		—	—
Pledged assets for Zion Station decommissioning subtotal	9		—		—		—	9		9		—		—		—	9
Rabbi trust investments
Cash equivalents	5		—		—		—	5		48		—		—		—	48
Mutual funds	24		—		—		—	24		72		—		—		—	72
Fixed income	—		—		—		—	—		—		15		—		—	15
Life insurance contracts	—		22		—		—	22		—		70		38		—	108
Rabbi trust investments subtotal^(f)	29		22		—		—	51		120		85		38		—	243
Commodity derivative assets
Economic hedges	541		2,760		1,470		—	4,771		541		2,760		1,470		—	4,771
Proprietary trading	—		69		77		—	146		—		69		77		—	146
Effect of netting and allocation of collateral^(e)	(582	)	(2,357	)	(732	)	—	(3,671	)	(582	)	(2,357	)	(732	)	—	(3,671	)
Commodity derivative assets subtotal	(41	)	472		815		—	1,246		(41	)	472		815		—	1,246
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—		—		—		—	—		—		—		—		—	—
Economic hedges	—		13		—		—	13		—		13		—		—	13
Effect of netting and allocation of collateral	—		(3	)	—		—	(3	)	—		(3	)	—		—	(3	)
Interest rate and foreign currency derivative assets subtotal	—		10		—		—	10		—		10		—		—	10
Other investments	—		—		42		—	42		—		—		42		—	42
Total assets	5,829		4,102		1,400		3,433	14,764		6,582		4,165		1,438		3,433	15,618



	Generation														Exelon
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)	(2,963		)	(1,027		)	—		(4,632		)	(642		)	(2,963		)	(1,276		)	—		(4,881		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(e)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(240		)	—		(698		)	(3		)	(455		)	(489		)	—		(947		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(4		)	—			—		(4		)
Economic hedges	—			(6		)	—			—		(6		)	—			(6		)	—			—		(6		)
Effect of netting and allocation of collateral	—			3			—			—		3			—			3			—			—		3
Interest rate and foreign currency derivative liabilities subtotal	—			(3		)	—			—		(3		)	—			(7		)	—			—		(7		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(137		)	—			—		(137		)
Total liabilities	(3		)	(493		)	(240		)	—		(736		)	(3		)	(599		)	(489		)	—		(1,091		)
Total net assets	$	5,826		$	3,609		$	1,160		$	3,433	$	14,028		$	6,579		$	3,566		$	949		$	3,433	$	14,527



	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



	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
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	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^(e)	(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
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



	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
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^(e)	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 $283 million and $259 million at December 31, 2018 and 2017 and restricted cash of $39 million and $127 million at December 31, 2018 and 2017. Exelon excludes cash of $458 million and $389 million at December 31, 2018 and 2017 and restricted cash of $80 million and $145 million at December 31, 2018 and 2017 and includes long-term restricted cash of $185 million and $85 million at December 31, 2018 and 2017, which is reported in Other deferred debits in the Consolidated Balance Sheets.


(b)	Includes $50 million and $77 million of cash received from outstanding repurchase agreements at December 31, 2018 and 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 $44 million and less than $1 million, which have a total notional amount of $1,432 million and $811 million at December 31, 2018 and 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 $130 million and $82 million at December 31, 2018 and 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 less than $1 million at December 31, 2018 and 2017. 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 years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017, respectively.

(g)

Collateral posted/(received) from counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2018. Collateral posted/(received) from 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), $(94) million and $(117) million represents variation margin on the exchanges as of December 31, 2018 and 2017, respectively.

Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $72 million as of December 31, 2018. Changes were immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2018.

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value in ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2018 and 2017:



	ComEd											PECO										BGE
As of December 31, 2018	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents^(a)	$	209	$	—		$	—		$	209		$	111	$	—		$	—	$	111		$	4	$	—		$	—	$	4
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			6		—			—		6
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal^(b)	—		—			—			—			7		10			—		17			6		—			—		6
Total assets	209		—			—			209			118		10			—		128			10		—			—		10
Liabilities
Deferred compensation obligation	—		(6		)	—			(6		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities^(c)	—		—			(249		)	(249		)	—		—			—		—			—		—			—		—
Total liabilities	—		(6		)	(249		)	(255		)	—		(10		)	—		(10		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	209	$	(6	)	$	(249	)	$	(46	)	$	118	$	—		$	—	$	118		$	10	$	(5	)	$	—	$	5



	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 $93 million and $45 million at December 31, 2018 and 2017 and restricted cash of $28 million at December 31, 2018 and includes long-term restricted cash of $166 million and $62 million at December 31, 2018 and December 31, 2017, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $24 million and $47 million at December 31, 2018 and 2017. BGE excludes cash of $7 million and $17 million at December 31, 2018 and 2017 and restricted cash of $2 million and $1 million at December 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 years ended December 31, 2018 and December 31, 2017.


(c)	The Level 3 balance consists of the current and noncurrent liability of $26 million and $223 million, respectively, at December 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 in PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2018 and 2017:




	As of December 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)	$	147	$	—		$	—	$	147		$	83		$	—		$	—	$	83
Rabbi trust investments
Cash equivalents	42		—			—		42			72			—			—		72
Mutual Funds	13		—			—		13			—			—			—		—
Fixed income	—		15			—		15			—			12			—		12
Life insurance contracts	—		22			38		60			—			23			22		45
Rabbi trust investments subtotal^(b)	55		37			38		130			72			35			22		129
Total assets	202		37			38		277			155			35			22		212
Liabilities
Deferred compensation obligation	—		(21		)	—		(21		)	—			(25		)	—		(25		)
Mark-to-market derivative liabilities	—		—			—		—			(1		)	—			—		(1		)
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—
Total liabilities	—		(21		)	—		(21		)	—			(25		)	—		(25		)
Total net assets	$	202	$	16		$	38	$	256		$	155		$	10		$	22	$	187



	Pepco										DPL										ACE
As of December 31, 2018	Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	38	$	—		$	—	$	38		$	16	$	—		$	—	$	16		$	23	$	—	$	—	$	23
Rabbi trust investments
Cash equivalents	41		—			—		41			—		—			—		—			—		—		—		—
Fixed income	—		5			—		5			—		—			—		—			—		—		—		—
Life insurance contracts	—		22			37		59			—		—			—		—			—		—		—		—
Rabbi trust investments subtotal^(b)	41		27			37		105			—		—			—		—			—		—		—		—
Total assets	79		27			37		143			16		—			—		16			23		—		—		23
Liabilities
Deferred compensation obligation	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(3		)	—		(3		)	—		(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	79	$	24		$	37	$	140		$	16	$	(1	)	$	—	$	15		$	23	$	—	$	—	$	23



	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	—		—			—		—			(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 $39 million and $12 million at December 31, 2018 and 2017 and includes long term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $15 million and $4 million at December 31, 2018 and 2017. DPL excludes cash of $8 million and $2 million at December 31, 2018 and 2017. ACE excludes cash of $7 million and $2 million at December 31, 2018 and 2017 and includes long-term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 at December 31, 2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets.


(b)	The amount of unrealized gains/(losses) at PHI totaled $1 million for the years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Pepco totaled less than $1 million for the years ended December 31, 2018 and 2017, respectively.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2018 and 2017:



	Generation																ComEd				PHI					Exelon
For the year ended December 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 January 1, 2018	$	648		$	12		$	552			$	37		$	1,249		$	(256	)		$	22	$	—		$	1,015
Total realized / unrealized gains (losses)
Included in net income	—			—			(105		)	^(a)	3			(102		)	—				4		—			(98		)
Included in noncurrent payables to affiliates	(1		)	—			—				—			(1		)	—				—		1			—
Included in payable for Zion Station decommissioning	—			7			—				—			7			—				—		—			7
Included in regulatory assets/liabilities	—			—			—				—			—			7			^(b)	—		(1		)	6
Change in collateral	—			—			(5		)		—			(5		)	—				—		—			(5		)
Purchases, sales, issuances and settlements
Purchases	36			1			190			^(e)	4			231			—				—		—			231
Sales	—			(20		)	(4		)		—			(24		)	—				—		—			(24		)
Issuances	—			—			—				—			—			—				—		—			—
Settlements	(140		)	—			5				—			(135		)	—				12		—			(123		)
Transfers into Level 3	—			—			(22		)	^(d)	—			(22		)	—				—		—			(22		)
Transfers out of Level 3	—			—			(36		)	^(d)	(2		)	(38		)	—				—		—			(38		)
Other miscellaneous	—			—			—							—			—				—		—			—
Balance as of December 31, 2018	$	543		$	—		$	575			$	42		$	1,160		$	(249	)		$	38	$	—		$	949
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2018	$	(5	)	$	—		$	165			$	3		$	163		$	—			$	—	$	—		$	163



	Generation																ComEd				PHI						Exelon
For the year ended December 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 January 1, 2017	$	677		$	19		$	493			$	42		$	1,231		$	(258	)		$	20		$	—		$	993
Total realized / unrealized gains (losses)
Included in net income	3			—			(90		)	^(a)	3			(84		)	—				3			—			(81		)
Included in noncurrent payables to affiliates	6			—			—				—			6			—				—			(6		)	—
Included in payable for Zion Station decommissioning	—			(8		)	—				—			(8		)	—							—			(8		)
Included in regulatory assets/liabilities	—			—			—				—			—			2			^(b)	—			6			8
Change in collateral	—			—			20				—			20			—				—			—			20
Purchases, sales, issuances and settlements
Purchases	64			1			178				5			248			—				—			—			248
Sales	—			—			(16		)		—			(16		)	—				—			—			(16		)
Issuances	—			—			—				—			—			—				(1		)	—			(1		)
Settlements	(102		)	—			(8		)		—			(110		)	—				—			—			(110		)
Transfers into Level 3	—			—			(6		)	^(d)	—			(6		)	—				—			—			(6		)
Transfers out of Level 3	—			—			(50		)	^(d)	(11		)	(61		)	—				—			—			(61		)
Other miscellaneous	$	—		$	—		$	31			$	(2	)	$	29		$	—			$	—		$	—		$	29
Balance as of December 31, 2017	$	648		$	12		$	552			$	37		$	1,249		$	(256	)		$	22		$	—		$	1,015
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2017	$	1		$	—		$	254			$	3		$	258		$	—			$	3		$	—		$	261

__________


(a)	Includes a reduction for the reclassification of $265 million and $352 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2018 and 2017, respectively.

(b)

Includes $24 million of decreases in fair value and an increase for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2018. Includes $18 million of decreases in fair value and an increase for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2017.


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


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


(e)	Includes $(19) million of fair value from contracts acquired as a result of the Everett Marine Terminal acquisition

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 years ended December 31, 2018 and 2017:



	Generation									PHI		Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net			Operating and Maintenance		Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net
Total (losses) gains included in net income for the year ended December 31, 2018	$	(7	)	$	(93	)	$	3		$	4	$	(7	)	$	(93	)	$	4	$	3
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2018	144			21			(2		)	—		144			21			—		(2		)



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net		Operating and Maintenance		Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net
Total gains (losses) included in net income for the year ended December 31, 2017	$	28	$	(126	)	$	6	$	3	$	28	$	(126	)	$	3	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2017	290		(36		)	4		3		290		(36		)	3		4

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.

NDT 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, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.

As of December 31, 2018, Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments of approximately $127 million, $224 million, $326 million and $273 million, respectively. These commitments will be funded by Generation’s existing NDT funds.

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 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 December 31, 2018, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 15 — Asset Retirement Obligations for additional information 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 as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 12 — Derivative Financial Instruments for additional information 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)

NDT 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. Therefore, Generation has not disclosed such inputs.

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. Therefore, Exelon has not disclosed such inputs.

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

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

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $3.18 and $0.64 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 12 — Derivative Financial Instruments for additional information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

The following tables present the significant inputs to the forward curve used to value these positions:



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

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

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

______


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


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


(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.



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 $81 million as of December 31, 2017.


(c)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

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.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments (All Registrants)

12 Months Ended

Dec. 31, 2018

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 December 31, 2018, $2 million of cash collateral posted with external counterparties and an additional $12 million of cash collateral posted with ComEd, and as of December 31, 2017, $4 million of cash collateral held, 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 related to commodity contracts recorded by the Registrants as of December 31, 2018:



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

__________

(a)

Exelon and Generation net all available amounts allowed under the derivative authoritative guidance 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 $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.


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


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

The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2017:



	Generation												ComEd			Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(d)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,061		$	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		)	(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		)	(637		)
Total mark-to-market derivative net assets (liabilities)	$	442		$	15		$	466		$	923		$	(256	)	$	667

__________

(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 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)	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 years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows.



	For the Years Ended December 31,
	2018			2017			2016
Income Statement Location	Gain (Loss)
Operating revenues	$	(270	)	$	(126	)	$	(490	)
Purchased power and fuel	(47		)	(43		)	459
Total Exelon and Generation	$	(317	)	$	(169	)	$	(31	)

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 December 31, 2018, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 89%-92%, 56%-59% and 32%-35% for 2019, 2020 and 2021, respectively.

On December 17, 2010, ComEd executed several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts 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 4 — Regulatory Matters for additional information.

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

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

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

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

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

DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecast 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 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 years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.



	For the Years Ended December 31,
	2018		2017		2016
Income Statement Location	Gain
Operating revenues	$	17	$	6	$	2

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 also utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. 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 December 31, 2018:



	Generation										Exelon Corporate			Exelon
Description		Economic Hedges			Collateral and Netting^(a)			Subtotal			Economic Hedges			Total
Mark-to-market derivative assets (current assets)		$	5		$	(2	)	$	3		$	—		$	3
Mark-to-market derivative assets (noncurrent assets)		8			(1		)	7			—			7
Total mark-to-market derivative assets		13			(3		)	10			—			10
Mark-to-market derivative liabilities (current liabilities)		(4		)	2			(2		)	—			(2		)
Mark-to-market derivative liabilities (noncurrent liabilities)		(2		)	1			(1		)	(4		)	(5		)
Total mark-to-market derivative liabilities		(6		)	3			(3		)	(4		)	(7		)
Total mark-to-market derivative net assets (liabilities)		$	7		$	—		$	7		$	(4	)	$	3

__________

(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)

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.

Economic Hedges (Interest Rate and Foreign Exchange Risk)

Exelon and Generation execute 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. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The amount deferred in AOCI associated with the previously designated cash flow hedges will be reclassified into earnings as the underlying forecasted transaction occurs. The result of this de-designation is that all economic hedges for interest rate swaps will be recorded at fair value through earnings going forward, referred to as economic hedges in the following tables.

The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2018 related to interest rate swaps and foreign currency exchange rate swaps.



	Generation		Exelon Corporate		Exelon
Foreign currency exchange rate swaps	$	268	$	—	$	268
Interest rate swaps	620		800		1,420
Total	$	888	$	800	$	1,688

The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 related to interest rate swaps and foreign currency exchange rate swaps.



	Generation		Exelon Corporate		Exelon
Foreign currency exchange rate swaps	$	94	$	—	$	94
Interest rate swaps^(a)	1		—		1
Total	$	95	$	—	$	95

__________


(a)	On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017.

For the years ended December 31, 2018, 2017 and 2016, 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.



		For the Years Ended December 31,
		2018			2017			2016
	Income Statement Location	Gain (Loss)
Generation	Operating Revenues	$	7		$	(6	)	$	(10	)
Generation	Purchased Power and Fuel	(9		)	—			—
Generation	Interest Expense	(7		)	(3		)	—
Total Generation		$	(9	)	$	(9	)	$	(10	)



		For the Years Ended December 31,
		2018			2017			2016
	Income Statement Location	Gain (Loss)
Exelon	Operating Revenues	$	7		$	(6	)	$	(10	)
Exelon	Purchased Power and Fuel	(9		)	—			—
Exelon	Interest Expense	(4		)	(3		)	—
Total Exelon		$	(6	)	$	(9	)	$	(10	)

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 had no fixed-to-floating swaps designated as fair value hedges as of December 31, 2018 and had $800 million notional amounts designated as fair value hedges as of December 31, 2017. 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:



		Year Ended December 31,
	Income Statement Location	2018			2017			2016			2018		2017		2016
	Income Statement Location	Loss on Swaps									Gain on Borrowings
Exelon	Interest expense	$	(11	)	$	(13	)	$	(9	)	$	20	$	28	$	23

During the years ended December 31, 2018, 2017 and 2016, the impact on the results of operations due to ineffectiveness from fair value hedges were gains of $9 million, $15 million and $14 million, 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. Exelon and Generation have no floating-to-fixed swaps designated as cash flow hedges as of December 31, 2018, and had $636 million notional amounts designated as cash flow hedges as of December 31, 2017.

The tables below provide the activity of OCI related to cash flow hedges for the years ended December 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 AOCI, 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 AOCI Activity, Net of Income Tax
		Generation			Exelon
For the Year Ended December 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		11			11
Reclassifications from AOCI to net income	Interest expense	1			1
AOCI derivative loss at December 31, 2018		$	(4	)	$	(2	)



		Total Cash Flow Hedge AOCI Activity, Net of Income Tax
		Generation				Exelon
For the Year Ended December 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		(1		)		(1		)
Reclassifications from AOCI to net income	Interest expense	4			^(a)	4			^(a)
AOCI derivative loss at December 31, 2017		$	(16	)		$	(14	)

__________


(a)	Amount is net of related income tax expense of $1 million for the year ended December 31, 2017.

During the years ended December 31, 2018, 2017 and 2016, the impact on the results of operations as a result of ineffectiveness from cash flow hedges 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.

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 years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).



	For the Years Ended December 31,
	2018		2017			2016
Income Statement Location	Loss
Operating revenues	$	—	$	(1	)	$	(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 December 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 $43 million, $30 million, $24 million, $28 million, $7 million and $5 million as of December 31, 2018, respectively.



Rating as of December 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	$	795	$	—	$	795	1	$	153
Non-investment grade	133		45		88		—	—
No external ratings
Internally rated — investment grade	181		1		180		—	—
Internally rated — non-investment grade	92		6		86		—	—
Total	$	1,201	$	52	$	1,149	1	$	153



Net Credit Exposure by Type of Counterparty	December 31, 2018
Financial institutions	$	12
Investor-owned utilities, marketers, power producers	737
Energy cooperatives and municipalities	324
Other	76
Total	$	1,149

__________


(a)	As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 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. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2018, ComEd’s net credit exposure to suppliers was immaterial.

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

PECO’s unsecured credit used by electric suppliers represents PECO’s net credit exposure. As of December 31, 2018, PECO had no material net credit exposure to electric suppliers.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. As of December 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 4 — Regulatory Matters 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 December 31, 2018, BGE had no material net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. At December 31, 2018, BGE had credit exposure of $3 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 December 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 4 — Regulatory Matters 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 December 31, 2018, DPL's credit exposure under its natural gas supply and asset management agreements was immaterial.

Collateral (All Registrants)

As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:



	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2018			2017
Gross fair value of derivative contracts containing this feature^(a)	$	(1,723	)	$	(926	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	1,105			577
Net fair value of derivative contracts containing this feature^(c)	$	(618	)	$	(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 $418 million and letters of credit posted of $367 million, and cash collateral held of $47 million and letters of credit held of $44 million as of December 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 $2.1 billion and $1.8 billion as of December 31, 2018 and 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 December 31, 2018, Generation’s and Exelon's swaps were in an asset position with a fair value of $7 million and $3 million, respectively.

See Note 24 — Segment Information for additional information regarding the letters of credit supporting the cash collateral.

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2018, ComEd held approximately $38 million in collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's ZEC contracts, collateral postings are required to cover a percentage of the ZEC contract value. ComEd’s REC contracts require collateral postings that are either a fixed price per REC or a percentage of the REC contract value. As of December 31, 2018, ComEd held approximately $31 million in collateral from suppliers for REC and ZEC contract obligations. Under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 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 December 31, 2018, it would have been required to post approximately $7 million of collateral to its counterparties. See Note 4 — Regulatory Matters 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 December 31, 2018, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2018, PECO could have been required to post approximately $39 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 December 31, 2018, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2018, BGE could have been required to post approximately $69 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 December 31, 2018, DPL could have been required to post an additional amount of approximately $11 million of collateral to its natural gas 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)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Debt and Credit Agreements (All Registrants)

Short-Term Borrowings

Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Commercial Paper

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2018 and 2017:



	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer	2018^(a)(b)(c)		2017^(a)(b)(c)		2018		2017		2018		2017
Exelon Corporate	$	600	$	600	$	—	$	—	1.93	%	1.16	%
Generation	5,300		5,300		—		—		1.96	%	1.23	%
ComEd	1,000		1,000		—		—		2.14	%	1.24	%
PECO	600		600		—		—		2.24	%	1.13	%
BGE	600		600		35		77		2.18	%	1.28	%
Pepco	300		500		40		26		2.24	%	1.06	%
DPL	300		500		—		216		2.07	%	1.48	%
ACE	300		350		14		108		2.21	%	1.43	%
Total	$	9,000	$	9,450	$	89	$	427

__________


(a)	Excludes $545 million and $480 million in bilateral credit facilities at December 31, 2018 and 2017, respectively, and $159 million and $179 million in credit facilities for project finance at December 31, 2018 and 2017, respectively. These credit facilities do not back Generation's commercial paper program.

(b)

At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. At December 31, 2017, excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million, and $2 million, respectively.

(c)

Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of outstanding commercial paper does not reduce available capacity under a Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.

At December 31, 2018, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:



								Available Capacity at December 31, 2018
Borrower	Facility Type	Aggregate Bank Commitment^(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper^(b)
Exelon Corporate	Syndicated Revolver	$	600	$	—	$	9	$	591	$	591
Generation	Syndicated Revolver	5,300		—		1,203		4,097		4,097
Generation	Bilaterals	545		—		353		192		—
Generation	Project Finance	159		—		119		40		—
ComEd	Syndicated Revolver	1,000		—		2		998		998
PECO	Syndicated Revolver	600		—		—		600		600
BGE	Syndicated Revolver	600		—		1		599		564
Pepco	Syndicated Revolver	300		—		8		292		252
DPL	Syndicated Revolver	300		—		1		299		299
ACE	Syndicated Revolver	300		—		—		300		286
Total		$	9,704	$	—	$	1,696	$	8,008	$	7,687

__________

(a)

Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2018, 2017 and 2016.



Exelon
	2018			2017			2016
Average borrowings	$	531		$	823		$	1,125
Maximum borrowings outstanding	1,237			2,147			3,076
Average interest rates, computed on a daily basis	2.21		%	1.32		%	0.88		%
Average interest rates, at December 31	2.15		%	1.24		%	1.12		%

Generation
	2018			2017			2016
Average borrowings	$	37		$	405		$	536
Maximum borrowings outstanding	583			1,455			1,735
Average interest rates, computed on a daily basis	1.96		%	1.23		%	0.94		%
Average interest rates, at December 31	1.96		%	1.23		%	1.14		%



ComEd
	2018			2017			2016
Average borrowings	$	154		$	200		$	256
Maximum borrowings outstanding	520			470			755
Average interest rates, computed on a daily basis	2.14		%	1.24		%	0.77		%
Average interest rates, at December 31	2.14		%	1.24		%	N/A

PECO
	2018			2017			2016
Average borrowings	$	68		$	2		$	—
Maximum borrowings outstanding	350			60			—
Average interest rates, computed on a daily basis	2.24		%	1.13		%	N/A
Average interest rates, at December 31	2.24		%	1.13		%	N/A

BGE
	2018			2017			2016
Average borrowings	$	65		$	54		$	143
Maximum borrowings outstanding	239			165			369
Average interest rates, computed on a daily basis	2.18		%	1.28		%	0.77		%
Average interest rates, computed at December 31	2.18		%	1.28		%	0.95		%



PHI Corporate
	2018			2017			2016
Average borrowings	N/A			N/A			$	153
Maximum borrowings outstanding	N/A			N/A			559
Average interest rates, computed on a daily basis	N/A			N/A			1.03		%
Average interest rates, computed at December 31	N/A			N/A			N/A

Pepco
	2018			2017			2016
Average borrowings	$	22		$	51		$	4
Maximum borrowings outstanding	90			197			73
Average interest rates, computed on a daily basis	2.24		%	1.06		%	0.71		%
Average interest rates, computed at December 31	2.24		%	1.06		%	0.90		%

DPL
	2018			2017			2016
Average borrowings	$	87		$	40		$	33
Maximum borrowings outstanding	245			216			116
Average interest rates, computed on a daily basis	2.07		%	1.48		%	0.68		%
Average interest rates, computed at December 31	2.07		%	1.48		%	N/A

ACE
	2018			2017			2016
Average borrowings	$	95		$	30		$	—
Maximum borrowings outstanding	210			133			5
Average interest rates, computed on a daily basis	2.21		%	1.43		%	0.65		%
Average interest rates, computed at December 31	2.21		%	1.43		%	N/A

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 on 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.

On May 23, 2018, ACE entered into two term loan agreements in the aggregate amount of $125 million, which expire on May 22, 2019. Pursuant to the term loan agreements, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.55% and all indebtedness thereunder is unsecured.

Credit Agreements

On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility. On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to April 2021. This facility will solely be utilized by Generation to issue lines of credit. This facility does not back Generation's commercial paper program.

On April 1, 2016, the credit agreement for CENG's $100 million bilateral credit facility was amended to increase the overall facility size to $200 million, scheduled to mature in October of 2019. This facility is utilized by CENG to fund working capital and capital projects. The facility does not back Generation's commercial paper program.

On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600 million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August 1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.

On January 9, 2017, the credit agreement for Generation's $75 million bilateral credit facility was amended and restated to increase the facility size to $100 million. On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to March 2021. This facility will solely be used by Generation to issue letters of credit.

On March 15, 2018, the credit agreement for a Generation bilateral credit facility of $30 million was amended to increase the overall facility size to $95 million, scheduled to mature in March of 2020. This facility will solely be used by Generation to issue letters of credit.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's and ACE's revolving credit agreements bear interest at a rate based upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Prime based borrowings	27.5	27.5	7.5	—	—	7.5	7.5	7.5
LIBOR-based borrowings	127.5	127.5	107.5	90.0	100.0	107.5	107.5	107.5

The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the borrower.

Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2018:

Exelon

Generation

ComEd

PECO

BGE

Pepco

DPL

ACE

Credit agreement threshold

2.50 to 1

3.00 to 1

2.00 to 1

At December 31, 2018, the interest coverage ratios at the Registrants were as follows:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Interest coverage ratio	7.34	10.99	7.34	8.14	9.77	5.98	7.03	5.06

An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an event of default with respect to the other PHI Utilities under the PHI Utilities' combined credit facility.

The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability of credit under any of the borrowers' credit agreement. None of the credit agreements include any rating triggers.

Variable Rate Demand Bonds

DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of both December 31, 2018 and December 31, 2017, $79 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's and DPL's Consolidated Balance Sheet.

Long-Term Debt

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2018 and 2017:

Exelon



							Maturity Date	December 31,
	Rates						Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.70	%	-	7.90	%		2019 - 2048	16,496			15,197
Senior unsecured notes	2.45	%	-	7.60	%		2019 - 2046	11,285			11,285
Unsecured notes	2.40	%	-	6.35	%		2021 - 2048	2,900			2,600
Pollution control notes	2.50	%	-	2.70	%		2025 - 2036	435			435
Nuclear fuel procurement contracts				3.15	%		2020	39			82
Notes payable and other^(b)(c)	2.85	%	-	8.88	%		2019 - 2053	188			405
Junior subordinated notes				3.50	%		2022	1,150			1,150
Long-term software licensing agreement				3.95	%		2024	73			79
Unsecured Tax-Exempt Bonds	1.74	%	-	5.40	%	—	2024 - 2031	112			112
Medium-Terms Notes (unsecured)	7.61	%	-	7.72	%		2019 - 2027	22			26
Transition bonds				5.55	%		2023	59			90
Loan Agreement				2.00	%		2023	50			—
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%		2031 - 2037	1,253			1,331
Variable rates^(f)				5.81	%		2019 - 2024	849			865
Total long-term debt								34,911			33,657
Unamortized debt discount and premium, net								(66		)	(57		)
Unamortized debt issuance costs								(216		)	(201		)
Fair value adjustment								795			865
Long-term debt due within one year^(e)								(1,349		)	(2,088		)
Long-term debt								$	34,075		$	32,176
Long-term debt to financing trusts^(d)
Subordinated debentures to ComEd Financing III				6.35	%		2033	$	206		$	206
Subordinated debentures to PECO Trust III	7.38	%	-	7.50	%		2028	81			81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103			103
Total long-term debt to financing trusts								390			390
Unamortized debt issuance costs								—			(1		)
Long-term debt to financing trusts								$	390		$	389

__________


(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.


(b)	Includes capital lease obligations of $36 million and $53 million at December 31, 2018 and 2017, respectively. Lease payments of $21 million, $5 million, $1 million, $1 million, less than $1 million, and $8 million will be made in 2019, 2020, 2021, 2022, 2023, and thereafter, respectively.


(c)	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.


(d)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.


(e)	In January 2019, $300 million of ComEd long-term debt due within one year was paid in full.


(f)	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.

Generation



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
Senior unsecured notes	2.95	%	-	7.60	%	2019 - 2042	$	6,019		$	6,019
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			435
Nuclear fuel procurement contracts				3.15	%	2020	39			82
Notes payable and other^(a)(b)	2.85	%	-	7.83	%	2019 - 2024	164			223
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,253			1,331
Variable rates^(c)				5.81	%	2019 - 2024	849			865
Total long-term debt							8,759			8,955
Unamortized debt discount and premium, net							(6		)	(8		)
Unamortized debt issuance costs							(51		)	(60		)
Fair value adjustment							91			103
Long-term debt due within one year							(906		)	(346		)
Long-term debt							$	7,887		$	8,644

__________


(a)	Includes Generation’s capital lease obligations of $14 million and $18 million at December 31, 2018 and 2017, respectively. Generation will make lease payments of $7 million, $5 million, $1 million, and $1 million in 2019, 2020, 2021, and 2022, respectively. Lease payments of less than $1 million annually will be made from 2023 through expiration of the final capital lease in 2024.


(b)	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.


(c)	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.

ComEd



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	2.15	%	-	6.45	%	2019 - 2048	$	8,179		$	7,529
Notes payable and other^(b)				7.49	%	2053	8			147
Total long-term debt							8,187			7,676
Unamortized debt discount and premium, net							(23		)	(23		)
Unamortized debt issuance costs							(63		)	(52		)
Long-term debt due within one year^(d)							(300		)	(840		)
Long-term debt							$	7,801		$	6,761
Long-term debt to financing trust^(c)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Total long-term debt to financing trusts							206			206
Unamortized debt issuance costs							(1		)	(1		)
Long-term debt to financing trusts							$	205		$	205

__________


(a)	Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.


(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2018 and 2017, respectively. Lease payments of less than $1 million annually will be made from 2019 through expiration at 2053.


(c)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.


(d)	In January 2019, the $300 million balance was paid in full.

PECO



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.70	%	-	5.95	%	2021 - 2048	$	3,075		$	2,925
Loan Agreement				2.00	%	2023	50			0
Total long-term debt							3,125			2,925
Unamortized debt discount and premium, net							(18		)	(5		)
Unamortized debt issuance costs							(23		)	(17		)
Long-term debt due within one year							—			(500		)
Long-term debt							$	3,084		$	2,403
Long-term debt to financing trusts^(b)
Subordinated debentures to PECO Trust III	7.38	%	-	7.50	%	2028	$	81		$	81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103			103
Long-term debt to financing trusts							$	184		$	184

__________


(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.


(b)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

BGE



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
Unsecured notes	2.40	%	-	6.35	%	2021 - 2048	2,900			2,600
Total long-term debt							2,900			2,600
Unamortized debt discount and premium, net							(6		)	(6		)
Unamortized debt issuance costs							(18		)	(17		)
Long-term debt							$	2,876		$	2,577

PHI



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.81	%	-	7.90	%	2021 - 2048	$	5,242		$	4,743
Senior unsecured notes				7.45	%	2032	185			185
Unsecured Tax-Exempt Bonds	1.74	%	-	5.40	%	2024 - 2031	112			112
Medium-terms notes (unsecured)	7.61	%	-	7.72	%	2019 - 2027	22			26
Transition bonds^(b)				5.55	%	2023	59			90
Notes payable and other^(c)	7.28	%	-	8.88	%	2019 - 2022	16			33
Total long-term debt							5,636			5,189
Unamortized debt discount and premium, net							4			5
Unamortized debt issuance costs							(14		)	(6		)
Fair value adjustment							633			686
Long-term debt due within one year							(125		)	(396		)
Long-term debt							$	6,134		$	5,478

__________


(a)	Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.


(b)	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.


(c)	Includes Pepco's capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively.

Pepco



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	3.05	%	-	7.90	%	2022 - 2048	$	2,735		$	2,535
Notes payable and other^(b)	7.28	%	-	8.88	%	2019 - 2022	16			35
Total long-term debt							2,751			2,570
Unamortized debt discount and premium, net							2			2
Unamortized debt issuance costs							(34		)	(32		)
Long-term debt due within one year							(15		)	(19		)
Long-term debt							$	2,704		$	2,521

__________


(a)	Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.


(b)	Includes capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively. Lease payments of $14 million will be made in 2019.

DPL



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.81	%	-	4.27	%	2023 - 2048	$	1,370		$	1,171
Unsecured Tax-Exempt Bonds	1.74	%	-	5.40	%	2024 - 2031	112			112
Medium-terms notes (unsecured)	7.61	%	-	7.72	%	2019 - 2027	22			26
Total long-term debt							1,504			1,309
Unamortized debt discount and premium, net							2			2
Unamortized debt issuance costs							(12		)	(11		)
Long-term debt due within one year							(91		)	(83		)
Long-term debt							$	1,403		$	1,217

__________


(a)	Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture.

ACE



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	3.38	%	-	6.80	%	2021 - 2036	$	1,137		$	1,037
Transition bonds^(b)				5.55	%	2023	59			90
Total long-term debt							1,196			1,127
Unamortized debt discount and premium, net							(1		)	(1		)
Unamortized debt issuance costs							(7		)	(5		)
Long-term debt due within one year							(18		)	(281		)
Long-term debt							$	1,170		$	840

__________


(a)	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.


(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021.

Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2019 through 2023 and thereafter are as follows:



Year	Exelon			Generation		ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
2019	$	1,349		$	906	$	300		$	—		$	—	$	125	$	15	$	91	$	18
2020	3,528			2,108		500			—			—		20		—		—		20
2021	1,511			1		350			300			300		261		1		—		260
2022	3,084			1,024		—			350			250		310		310		—		—
2023	850			—		—			50			300		500		—		500		—
Thereafter	24,979		^(a)	4,720		7,243		^(b)	2,609		^(c)	2,050		4,420		2,425		913		898
Total	$	35,301		$	8,759	$	8,393		$	3,309		$	2,900	$	5,636	$	2,751	$	1,504	$	1,196

__________


(a)	Includes $390 million due to ComEd and PECO financing trusts.


(b)	Includes $206 million due to ComEd financing trust.


(c)	Includes $184 million due to PECO financing trusts.

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15 billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to retained earnings as of December 31, 2017. See Note 20 — Earnings Per Share for additional information on the issuance of common stock.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.9 billion of generating assets have been pledged as collateral at December 31, 2018. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project in Denver, Colorado. The agreement is scheduled to mature on June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2018, $6 million was outstanding.

CEU Upstream. In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserve based lending agreement (RBL) associated with certain Upstream oil and gas properties. The lenders do not have recourse against Exelon or Generation in the event of default pursuant to the RBL. Borrowings under this arrangement are secured by the assets and equity of CEU Holdings.

In December 2016, substantially all of the Upstream natural gas and oil exploration and production assets were sold for $37 million. The proceeds were used to reduce the debt balance by $31 million. The remaining proceeds of $6 million were being held in escrow. In addition, during 2016, $15 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $22 million at December 31, 2016. During 2017, additional assets were sold for $1 million and the remaining $6 million in escrow was released and applied to the debt balance resulting in an outstanding amount of $15 million at December 31, 2017. Upon final resolution, CEU Holdings will be released of its obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. At December 31, 2018, the outstanding debt balance of $15 million was classified within Long term debt due within one year in Exelon’s and Generation’s Consolidated Balance Sheets. See Note 5 — Mergers, Acquisitions and Dispositions and Note 7 — Impairment of Long-Lived Assets and Intangibles for additional information.

Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solar construction project in Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2018, $8 million was outstanding.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2018, $508 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2018, Generation had $38 million in letters of credit outstanding related to the project. In 2017, Generation’s interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2018, $479 million was outstanding.

In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2018, the Continental Wind letter of credit facility had $114 million in letters of credit outstanding related to the project.

In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 2 - Variable Interest Entities for additional information on EGRP.

ExGen Texas Power. In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan was scheduled to mature on September 18, 2021. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants.

On May 2, 2017, as a result of the negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders, which permitted EGTP to draw on its revolving credit facility and initiate an orderly sales process of its assets. On November 7, 2017, the debtors 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. As a result, Exelon and Generation deconsolidated the nonrecourse senior secured term loan, the revolving credit facility, and the interest rate swaps from their consolidated financial statements as of December 31, 2017. Due to their nonrecourse nature, these borrowings are secured solely by the assets of EGTP and its subsidiaries.

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. See Note 5 — Mergers, Acquisitions and Dispositions for additional information on EGTP.

Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2018, $115 million was outstanding.

In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 2 - Variable interest Entities for additional information on EGRP.

SolGen. In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2018, $137 million was outstanding. In 2017, Generation’s interests in SolGen were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.

ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement, were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash in Exelon’s and Generation’s Consolidated Balance Sheets and Consolidated Statements of Cash Flows. The loan is scheduled to mature on November 28, 2024. The term loan bears interest at a variable rate equal to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2018, $834 million was outstanding. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing. See Note 2 - Variable interest Entities for additional information on EGRP.

Income Taxes (All Registrants)

12 Months Ended

Dec. 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 are determined by the Utility Registrants’ respective rate regulators, subject to certain IRS “normalization” rules. See Note 4 — Regulatory Matters for additional information regarding settlements for passing back of TCJA income tax savings benefits to customers.

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

On August 3, 2018, the U.S. Department of Treasury, in conjunction with the IRS, released proposed regulations clarifying the immediate expensing provisions enacted by the TCJA, specifically that regulated utility property acquired after September 27, 2017, and placed in service by December 31, 2017, qualifies for 100% expensing. Until the proposed regulations are finalized, taxpayers may rely on the proposed regulations for tax years ending after September 28, 2017. The Registrants recorded the impact of these proposed regulations and the adjustment was immaterial.

While the Registrants have recorded the impacts of the TCJA based on their interpretation of the provisions as enacted, it is expected the U.S. Department of Treasury and the IRS will issue additional interpretative guidance in the future that could result in changes to previously finalized provisions. At this time, many of the states in which Exelon does business have issued guidance regarding TCJA and the impact was not material.

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:



						Successor
	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



						Successor
	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



						Successor
	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 remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA.

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.



					Successor
	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 was 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.

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. See Note 4 - Regulatory Matters for additional information.

Components of Income Tax Expense or Benefit

Income tax expense (benefit) from continuing operations is comprised of the following components:



	For the Year Ended December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Included in operations:
Federal
Current	$	226		$	337		$	(63	)	$	11		$	(5	)	$	(4	)	$	28		$	(3	)	$	(14	)
Deferred	(98		)	(347		)	145			10			47			24			(21		)	13			18
Investment tax credit amortization	(24		)	(21		)	(2		)	—			—			(1		)	—			—			—
State
Current	(1		)	6			(29		)	1			—			7			—			—			—
Deferred	17			(83		)	117			(16		)	32			9			6			12			8
Total	$	120		$	(108	)	$	168		$	6		$	74		$	35		$	13		$	22		$	12



	For the Year Ended December 31, 2017^(a)
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Included in operations:
Federal
Current	$	194		$	584		$	(191	)	$	71		$	74		$	(60	)	$	(20	)	$	(24	)	$	(12	)
Deferred	(471		)	(2,005		)	523			28			101			250			114			82			34
Investment tax credit amortization	(25		)	(21		)	(2		)	—			(1		)	(1		)	—			—			—
State
Current	14			65			(49		)	14			(5		)	(4		)	(2		)	—			—
Deferred	162			1			136			(9		)	49			32			13			13			4
Total	$	(126	)	$	(1,376	)	$	417		$	104		$	218		$	217		$	105		$	71		$	26



																								Successor			Predecessor
	For the Year Ended December 31, 2016^(a)																							March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO		BGE			Pepco			DPL			ACE			PHI			PHI
Included in operations:
Federal
Current	$	60		$	513		$	(135	)	$	63	$	51		$	(118	)	$	(88	)	$	(26	)	$	(281	)	$	—
Deferred	600			(254		)	379			72		88			136			97			22			283			10
Investment tax credit amortization	(24		)	(20		)	(2		)	—		(1		)	—			—			—			(1		)	—
State
Current	39			45			(4		)	9		5			7			1			—			(11		)	—
Deferred	78			(2		)	63			5		31			16			12			—			13			7
Total	$	753		$	282		$	301		$	149	$	174		$	41		$	22		$	(4	)	$	3		$	17

__________


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

Rate Reconciliation

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



	For the Year Ended December 31, 2018
											Successor
	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	0.6		(16.6	)	8.3		(2.6	)	6.6		3.0		2.2		6.7		7.4
Qualified NDT fund income	(1.9	)	(11.8	)	—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)	(6.5	)	(0.2	)	(0.1	)	(0.1	)	(0.2	)	(0.1	)	(0.3	)	(0.4	)
Plant basis differences	(3.5	)	—		(0.2	)	(14.1	)	(1.3	)	(1.6	)	(2.7	)	(0.3	)	(0.5	)
Production tax credits and other credits	(2.2	)	(13.5	)	—		—		—		—		—		—		—
Noncontrolling interests	(1.0	)	(6.1	)	—		—		—		—		—		—		—
Excess deferred tax amortization	(8.3	)	—		(9.1	)	(3.2	)	(8.0	)	(14.5	)	(14.8	)	(12.0	)	(14.9	)
Tax Cuts and Jobs Act of 2017	0.9		2.7		(0.1	)	—		—		0.1		—		—		—
Other	1.0		1.3		0.5		0.3		0.9		0.3		0.2		0.4		1.2
Effective income tax rate	5.4	%	(29.5	)%	20.2	%	1.3	%	19.1	%	8.1	%	5.8	%	15.5	%	13.8	%



	For the Year Ended December 31, 2017^(a)
											Successor
	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	2.3		2.9		5.7		0.6		5.4		4.8		3.2		5.4		5.6
Qualified NDT fund income	3.8		9.9		—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9	)	(2.1	)	(0.2	)	(0.1	)	(0.1	)	(0.2	)	(0.1	)	(0.2	)	(0.4	)
Plant basis differences^(b)	(1.7	)	—		0.3		(13.8	)	0.1		1.1		(0.4	)	2.0		3.6
Production tax credits and other credits	(1.8	)	(4.7	)	—		—		—		—		—		—		—
Like-kind exchange	(1.2	)	—		1.3		—		—		—		—		—		—
Merger expenses	(3.6	)	(1.2	)	—		—		—		(9.5	)	(6.3	)	(7.8	)	(19.8	)
FitzPatrick bargain purchase gain	(2.2	)	(5.6	)	—		—		—		—		—		—		—
Tax Cuts and Jobs Act of 2017^(c)	(33.1	)	(128.3	)	0.1		(2.3	)	0.9		6.4		2.7		2.5		1.6
Other	0.1		(0.5	)	0.2		(0.1	)	0.2		(0.1	)	(0.2	)	0.1		(0.4	)
Effective income tax rate	(3.3	)%	(94.6	)%	42.4	%	19.3	%	41.5	%	37.5	%	33.9	%	37.0	%	25.2	%



																	Successor		Predecessor
	For the Year Ended December 31, 2016^(a)																March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL ^(d)		ACE ^(d)		PHI ^(d)		PHI
U.S. Federal statutory rate	35.0	%	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 ^(e)	3.3		3.2		5.6		1.3		5.0		15.7		52.7		6.2		5.8		11.9
Qualified NDT fund income	3.4		7.9		—		—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)	(2.3	)	(0.3	)	(0.1	)	(0.1	)	(0.2	)	(3.7	)	0.8		1.4		(0.9	)
Plant basis differences	(4.9	)	—		(0.6	)	(9.6	)	(2.7	)	(22.8	)	(25.5	)	10.3		39.0		(13.5	)
Production tax credits and other credits	(3.6	)	(8.3	)	—		—		—		—		—		—		—		—
Noncontrolling interests	(0.2	)	(0.6	)	—		—		—		—		—		—		—		—
Statute of limitations expiration	(0.4	)	(1.7	)	—		—		—		—		—		—		—		—
Penalties	1.9		—		4.5		—		—		—		—		—		(0.7	)	—
Merger Expenses	5.6		1.1		—		—		—		23.5		112.9		(44.9	)	(89.0	)	11.1
Other ^(f)	(0.7	)	(1.4	)	0.1		(1.2	)	—		(1.8	)	(2.2	)	1.3		3.3		3.6
Effective income tax rate	38.2	%	32.9	%	44.3	%	25.4	%	37.2	%	49.4	%	169.2	%	8.7	%	(5.2	)%	47.2	%

__________


(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 the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 4 - Regulatory Matters for additional information.


(c)	Included are impacts for TCJA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives, the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback.


(d)	DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.


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


(f)	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and accepted in 2017. No change to the results recorded as of December 31, 2016.

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2018 and 2017 are presented below:



	As of December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Plant basis differences	$	(12,533	)	$	(2,495	)	$	(4,059	)	$	(1,862	)	$	(1,399	)	$	(2,577	)	$	(1,148	)	$	(743	)	$	(645	)
Accrual based contracts	117			(44		)	—			—			—			161			—			—			—
Derivatives and other financial instruments	89			35			69			—			—			3			—			—			—
Deferred pension and postretirement obligation	1,435			(188		)	(255		)	(26		)	(26		)	(102		)	(78		)	(46		)	(14		)
Nuclear decommissioning activities	(351		)	(351		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	234			23			(7		)	—			(3		)	187			(4		)	(2		)	(1		)
Regulatory assets and liabilities	(749		)	—			300			(129		)	172			(90		)	58			96			83
Tax loss carryforward	237			78			—			18			25			96			12			52			26
Tax credit carryforward	811			816			—			—			—			—			—			—			—
Investment in partnerships	(797		)	(775		)	—			—			—			—			—			—			—
Other, net	934			239			151			67			12			196			98			17			19
Deferred income tax liabilities (net)	$	(10,573	)	$	(2,662	)	$	(3,801	)	$	(1,932	)	$	(1,219	)	$	(2,126	)	$	(1,062	)	$	(626	)	$	(532	)
Unamortized investment tax credits	(724		)	(700		)	(12		)	(1		)	(3		)	(8		)	(2		)	(2		)	(3		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,297	)	$	(3,362	)	$	(3,813	)	$	(1,933	)	$	(1,222	)	$	(2,134	)	$	(1,064	)	$	(628	)	$	(535	)



	As of December 31, 2017 ^(a)
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Plant basis differences	$	(12,490	)	$	(2,819	)	$	(3,825	)	$	(1,762	)	$	(1,368	)	$	(2,521	)	$	(1,152	)	$	(717	)	$	(607	)
Accrual based contracts	150			(66		)	—			—			—			216			—			—			—
Derivatives and other financial instruments	(85		)	(66		)	(2		)	—			—			3			—			—			—
Deferred pension and postretirement obligation	1,463			(205		)	(285		)	(15		)	(29		)	(130		)	(78		)	(51		)	(18		)
Nuclear decommissioning activities	(553		)	(553		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	217			26			(8		)	(1		)	(3		)	203			(4		)	(2		)	(1		)
Regulatory assets and liabilities	(688		)	—			489			(90		)	136			(184		)	39			88			86
Tax loss carryforward	344			76			33			9			11			156			40			68			35
Tax credit carryforward	861			868			1			—			—			6			—			—			—
Investment in partnerships	(434		)	(416		)	—			—			—			—			—			—			—
Other, net	746			78			141			71			13			193			94			14			16
Deferred income tax liabilities (net)	$	(10,469	)	$	(3,077	)	$	(3,456	)	$	(1,788	)	$	(1,240	)	$	(2,058	)	$	(1,061	)	$	(600	)	$	(489	)
Unamortized investment tax credits	(732		)	(705		)	(13		)	(1		)	(4		)	(8		)	(2		)	(3		)	(4		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,201	)	$	(3,782	)	$	(3,469	)	$	(1,789	)	$	(1,244	)	$	(2,066	)	$	(1,063	)	$	(603	)	$	(493	)

__________


(a)	Includes remeasurement impacts related to the TCJA.

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2018:



										Successor
	Exelon		Generation		ComEd	PECO		BGE		PHI		Pepco		DPL		ACE
Federal
Federal general business credits carryforwards	811	^(a)	816		—	—		—		—		—		—		—
State
State net operating losses	4,103	^(b)	1,544	^(b)	—	224	^(c)	395	^(d)	1,492	^(e)	192	^(f)	772	^(g)	365	^(h)
Deferred taxes on state tax attributes (net)	272		104		—	18		26		102		12		52		26
Valuation allowance on state tax attributes	35		26		—	—		1		6		—		—		—

__________


(a)	Exelon’s federal general business credit carryforwards will begin expiring in 2033.


(b)	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2019.


(c)	PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.


(d)	BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026.


(e)	PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2036.


(f)	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2033.


(g)	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2030.


(h)	ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.

Tabular Reconciliation of Unrecognized Tax Benefits

The following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2018, 2017 and 2016:



	Exelon			Generation			ComEd		PECO		BGE			PHI			Pepco			DPL			ACE
Unrecognized tax benefits at January 1, 2018	$	743		$	468		$	2	$	—	$	120		$	125		$	59		$	21		$	14
Change to positions that only affect timing	15			15			—		—		—			—			—			—			—
Increases based on tax positions prior to 2018	30			21			—		—		—			8			7			1			—
Decreases based on tax positions prior to 2018	(251		)	(36		)	—		—		(120		)	(88		)	(66		)	(22		)	—
Decrease from settlements with taxing authorities	(53		)	(53		)	—		—		—			—			—			—			—
Decreases from expiration of statute of limitations	(7		)	(7		)	—		—		—			—			—			—			—
Unrecognized tax benefits at December 31, 2018	$	477		$	408		$	2	$	—	$	—		$	45		$	—		$	—		$	14



	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco			DPL			ACE
Unrecognized tax benefits at January 1, 2017	$	916		$	490		$	(12	)	$	—	$	120	$	172		$	80		$	37		$	22
Increases based on tax positions prior to 2017	28			—			14			—		—		14			—			—			14
Decreases based on tax positions prior to 2017	(196		)	(17		)	—			—		—		(61		)	(21		)	(16		)	(22		)
Decrease from settlements with taxing authorities	(5		)	(5		)	—			—		—		—			—			—			—
Unrecognized tax benefits at December 31, 2017	$	743		$	468		$	2		$	—	$	120	$	125		$	59		$	21		$	14



	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco		DPL		ACE
Unrecognized tax benefits at January 1, 2016	$	1,078		$	534		$	142		$	—	$	120	$	22		$	8	$	3	$	—
Merger balance transfer	22			5			—			—		—		(5		)	—		—		—
Increases based on tax positions related to 2016	108			10			—			—		—		59			21		16		22
Change to positions that only affect timing	(332		)	(12		)	(154		)	—		—		—			—		—		—
Increases based on tax positions prior to 2016	88			—			—			—		—		96			51		18		—
Decreases based on tax positions prior to 2016	(21		)	(20		)	—			—		—		—			—		—		—
Decreases from settlements with taxing authorities	(27		)	(27		)	—			—		—		—			—		—		—
Unrecognized tax benefits at December 31, 2016	$	916		$	490		$	(12	)	$	—	$	120	$	172		$	80	$	37	$	22

As a result of a court decision issued in July 2018 to an unrelated taxpayer, Exelon's and Generation’s unrecognized federal and state tax benefits increased in the third quarter of 2018 by approximately $71 million. Approximately $20 million of this increase impacted Exelon's and Generation’s effective tax rate and resulted in a charge to earnings in the third quarter of 2018. Exelon’s and Generation’s unrecognized federal and state tax benefits decreased in the fourth quarter of 2018 by approximately $90 million due to the settlement of a federal audit issue with IRS Appeals. The recognition of these tax benefits decreased the effective tax rate at Exelon and Generation resulting in an income tax benefit of approximately $9 million.

In the fourth quarter of 2018, Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits by $241 million, $33 million, $120 million, $88 million, $66 million, and $22 million, respectively, due to the receipt of favorable guidance with respect to the deductibility of certain depreciable fixed assets. The recognition of these tax benefits decreased the effective tax rate at Exelon and Generation resulting in an income tax benefit of approximately $26 million. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities and that portion had no immediate impact to their effective tax rate.

Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the acquisitions of Constellation in 2012 and PHI in 2016. In the first quarter 2017, as a part of its examination of Exelon's return, the IRS National Office issued guidance concurring with Exelon's position that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146 million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, in the first quarter of 2017 resulting in a benefit to Income taxes on Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.

Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017.

Unrecognized tax benefits that if recognized would affect the effective tax rate

Exelon, Generation, ComEd and PHI have $463 million, $408 million, $2 million and $31 million, respectively, of unrecognized tax benefits at December 31, 2018 that, if recognized, would decrease the effective tax rate. PHI has $21 million of unrecognized state tax benefits at December 31, 2018 that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances. PHI and ACE have $14 million of unrecognized tax benefits at December 31, 2018 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Exelon, Generation, ComEd and PHI had $523 million, $461 million, $2 million and $32 million, respectively, of unrecognized tax benefits at December 31, 2017 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, DPL, and ACE have $120 million, $94 million, $59 million, $21 million and $14 million of unrecognized tax benefits at December 31, 2017 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Exelon, Generation, PHI, Pepco, DPL, and ACE had $633 million, $483 million, $93 million, $21 million, $16 million, and $22 million, respectively, of unrecognized tax benefits at December 31, 2016 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco and DPL had $120 million, $80 million, $59 million, and $21 million of unrecognized tax benefits at December 31, 2016 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Unrecognized tax benefits that if recognized would affect only the timing of tax payments

There are no unrecognized tax benefits as of December 31, 2018 that affect only the timing of tax payments.

Exelon and Generation had $7 million of unrecognized tax benefits at December 31, 2017 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.

Exelon, Generation and ComEd had $83 million, $7 million and $(12) million of unrecognized tax benefits at December 31, 2016 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits.

The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.

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 December 31, 2018, Exelon and ComEd have approximately $33 million and $2 million, respectively, of unrecognized federal and state income tax benefits related to the like-kind exchange litigation described further below. If Exelon does not appeal the October 2018 U.S. Court of Appeals for the Seventh Circuit's decision to the U.S. Supreme Court, Exelon's and ComEd's unrecognized tax benefits will decrease in the first quarter of 2019. See below for further details.

Settlement of Income Tax Audits, Refund Claims, and Litigation

As of December 31, 2018, Exelon, Generation, PHI and ACE have approximately $425 million, $411 million, $14 million, and $14 million respectively, of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to PHI and ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Total amounts of interest and penalties recognized

The following tables represent the net interest and penalties receivable (payable), including interest and penalties related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.



Net interest receivable (payable) as of	Exelon		Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2018	$	236	$	(2	)	$	4	$	—	$	—	$	1	$	—	$	—	$	—
December 31, 2017	233		(3		)	4		—		—		2		—		—		—



Net penalties payable as of	Exelon			Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2018	$	(17	)	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2017	(17		)	—		—		—		—		—		—		—		—

The following tables set forth the net interest and penalty expense, including interest and penalties related to tax positions, recognized in Interest expense, net and Other, net in Other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.



Net interest expense (income) for the years ended	Exelon			Generation			ComEd		PECO		BGE		Pepco		DPL		ACE
December 31, 2018	$	(3	)	$	—		$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2017	37			(1		)	11		—		—		—		—		—
December 31, 2016	165			(13		)	117		—		—		6		—		(1		)



Net penalty expense (income) for the years ended	Exelon			Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
December 31, 2018	$	—		$	—	$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2017	(2		)	—		—		—		—		—		—		—
December 31, 2016	106			—		86		—		—		—		—		—



	Successor							Predecessor
PHI	December 31, 2018		December 31, 2017		March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
Net interest expense	$	—	$	—	$	(2	)	$	—

Description of tax years open to assessment by major jurisdiction



Taxpayer	Open Years
Exelon (and predecessors) and subsidiaries consolidated federal income tax returns	1999, 2001-2017
PHI Holdings and subsidiaries consolidated federal income tax returns	2013, 2015-2016
Exelon and subsidiaries Illinois unitary income tax returns	2010-2017
Constellation combined New York corporate income tax returns	2010-March 2012
Exelon combined New York corporate income tax returns	2011-2017
Exelon New Jersey corporate income tax returns	2013-2017
Exelon Pennsylvania corporate net income tax returns	2011-2017
PECO Pennsylvania separate company returns	2015-2017
DPL Delaware separate company returns	Same as federal
ACE New Jersey separate company returns	2014-2017
Exelon and subsidiaries District of Columbia corporate income tax returns	2015-2017
PHI Holdings and subsidiaries District of Columbia corporate income tax returns	2015-2016
Various separate company Maryland corporate net income tax returns	Same as federal

Other Tax Matters

Like-Kind Exchange

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. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December 2018. Exelon has until March 5, 2019 to seek a further review by the U.S. Supreme Court.

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 in by 2022.

In the second quarter of 2018, Exelon, Generation, PHI, Pepco and DPL recorded a one-time increase to deferred income taxes of approximately $16 million, $5 million, $17 million, $16 million and $1 million, respectively. At PHI, Pepco and DPL, the increase to the Maryland deferred income tax liability was 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, Pepco's or DPL's future results of operations.

Long-Term Marginal State Income Tax Rate (Exelon, Generation, PHI and Pepco)

In the third quarter of 2018, Exelon reviewed and updated its marginal state income tax rates based on 2017 state apportionment rates. As a result of the rate changes, in the third quarter of 2018, Exelon, Generation, PHI and DPL recorded a one-time decrease to deferred income taxes of approximately $50 million, $53 million, $4 million and $2 million respectively. Pepco recorded a one-time increase to deferred income taxes of approximately $1 million. Exelon, PHI and DPL recorded a corresponding regulatory liability of approximately $1 million, $1 million and $2 million respectively. Pepco recorded a corresponding regulatory asset of approximately $1 million. Further, Exelon, Generation and PHI recorded a decrease to income tax expense (net of federal taxes) of approximately $50 million, $53 million and $3 million.

Allocation of Tax Benefits (All Registrants)

Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2018, Generation, PECO, BGE, PHI and ComEd recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $155 million, $48 million, $26 million, $2 million and $1 million respectively. Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

During 2017, Generation, PECO, BGE, and PHI recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $102 million, $16 million, $10 million and $7 million respectively. ComEd, Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

During 2016, Generation, PECO and BGE recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $94 million, $18 million and $8 million respectively. ComEd did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. PHI, Pepco, DPL and ACE did not record an allocation of federal tax benefits from Exelon as they were not a part of Exelon's 2015 consolidated tax return.

Asset Retirement Obligations (All Registrants)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations (All Registrants)

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 in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2017 to December 31, 2018:



Nuclear decommissioning ARO at January 1, 2017	$	8,734
Accretion expense	458
Acquisition of FitzPatrick	444
Net increase due to changes in, and timing of, estimated future cash flows	34
Costs incurred related to decommissioning plants	(8		)
Nuclear decommissioning ARO at December 31, 2017^(a)	9,662
Accretion expense	478
Net decrease due to changes in, and timing of, estimated future cash flows	(77		)
Costs incurred related to decommissioning plants	(58		)
Nuclear decommissioning ARO at December 31, 2018^{(a) (b)}	$	10,005

__________


(a)	Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.


(b)	Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.

The net $77 million decrease in the ARO during 2018 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include a $203 million decrease primarily due to lower estimated costs for the construction of interim spent fuel storage at TMI and a net decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated cost studies. These adjustments also include a decrease due to changes in decommissioning scenarios and their probabilities. These decreases were partially offset by a $116 million increase for the impact of the early retirement and the announced pending sale of Oyster Creek and a $122 million increase for estimated cost escalation rates, primarily for labor, energy and waste burial costs. See Note 5 — Mergers, Acquisitions and Dispositions and Note 8—Early Plant Retirements for additional information regarding Oyster Creek.

The net $34 million increase in the ARO during 2017 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include a $178 million increase due to higher assumed probabilities of early retirement of Salem and a $138 million increase in TMI’s ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30, 2019. The increase in TMI's ARO liability incorporates the early shutdown date, increases in the probabilities of longer term decommissioning scenarios, and an increase in the estimated costs to decommission based on an updated decommissioning cost study. See Note 8—Early Plant Retirements for additional information regarding Salem and TMI. These increases in the ARO were partially offset by a $180 million decrease for refinements in estimated fleet wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as net decreases resulting from updates to the cost studies of Clinton, Quad Cities and Dresden.

NDT Funds

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. On March 31, 2017, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became effective January 1, 2018.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.

At December 31, 2018 and 2017, Exelon and Generation had NDT funds totaling $12,695 million and $13,349 million, respectively. Included within the December 31, 2018 balance is the $890 million reclassification of Oyster Creek NDT as Assets held for sale in Exelon's and Generation's Consolidated Balance Sheets. See Note 5 — Mergers, Acquisitions and Dispositions for additional information regarding the announced pending sale of Oyster Creek. The NDT funds include $144 million and $77 million for the current portion of the NDT at December 31, 2018 and 2017, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 11—Fair Value of Financial Assets and Liabilities for additional information related to the NDT funds.

The following table provides unrealized (losses) gains on NDT funds of Exelon and Generation for the years ended 2018, 2017 and 2016:



	2018			2017		2016
Net unrealized (losses) gains on NDT funds—Regulatory Agreement Units ^(a)	$	(715	)	$	455	$	216
Net unrealized (losses) gains on NDT funds—Non-Regulatory Agreement Units ^(b)	(483		)	521		194

__________


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


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

Realized earnings, including interest and dividends on the NDT funds, for the non-Regulatory Agreement Units investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income whereas the Regulatory Agreement Units are eliminated within Other, net.

Accounting Implications of the Regulatory Agreements with ComEd and PECO

Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. For the former ComEd units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income as long as the NDT funds are expected to exceed the total estimated decommissioning obligation. For the former PECO units, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation. ComEd and PECO have recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s financial statements could be material. As of December 31, 2018, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s financial statements could be material.

The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 4—Regulatory Matters and Note 25—Related Party Transactions for additional 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

In 2010, Generation completed an Asset Sale Agreement (ASA) under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. Pursuant to the ASA, ZionSolutions will periodically request reimbursement, subject to certain restrictions, from the Zion Station-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. As the transfer of the Zion Station assets did not qualify for asset sale accounting treatment, the related NDT funds were reclassified as pledged assets for Zion Station decommissioning, which are recorded within Other current assets 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, and the transferred ARO for decommissioning was replaced with a payable for Zion Station decommissioning, which is recorded in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT fund 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 $120 million, which is included within the nuclear decommissioning ARO at December 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 Exelon's and Generation's pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2018 and 2017:



	2018		2017
Carrying value of Zion Station pledged assets	$	9	$	39
Current payable to ZionSolutions ^(a)	9		37
Cumulative withdrawals by ZionSolutions to pay decommissioning costs ^(b)	965		942

_______


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


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

ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and constructed a dry cask storage facility on the land and has loaded the SNF from the SNF pools onto the dry cask storage facility at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. In accordance with the terms of the ASA, the letter of credit was reduced to $45 million in May 2018 due to the completion of key decommissioning milestones. EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.

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. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded in Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2018 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for TMI); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2018 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.0% to 6.2% (as compared to a historical 5-year annual average pre-tax return of approximately 4.9%).

Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.

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) and FitzPatrick which is still owned by Entergy as of the NRC reporting period. This 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. See NDT Funds section above for additional information.

On March 28, 2018, Generation submitted its annual decommissioning funding status report with the NRC for shutdown reactors, reactors within five years of shutdown 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.

Generation will file its next decommissioning funding status report for all units with the NRC by March 31, 2019. This report will reflect the status of decommissioning funding assurance as of December 31, 2018. A shortfall at any unit could necessitate that Generation address the shortfall by, among other things, obtaining a parental guarantee for Generation's share of the funding assurance. However, the amount of any guarantee or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the decommissioning trust fund investment performance going forward.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

Non-Nuclear Asset Retirement Obligations (All Registrants)

Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1—Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2017 to December 31, 2018:



	Exelon			Generation			ComEd			PECO			BGE			PHI		Pepco		DPL		ACE
Non-nuclear AROs at January 1, 2017	$	393		$	199		$	121		$	28		$	24		$	14	$	2	$	9	$	3
Net (decrease) increase due to changes in, and timing of, estimated future cash flows	(11		)	(1		)	(13		)	(1		)	2			2		1		1		—
Development projects	1			1			—			—			—			—		—		—		—
Accretion expense^(a)	18			10			7			1			—			—		—		—		—
Deconsolidation of EGTP	(7		)	(7		)	—			—			—			—		—		—		—
Payments	(10		)	(5		)	(2		)	(1		)	(2		)	—		—		—		—
Non-nuclear AROs at December 31, 2017	384			197			113			27			24			16		3		10		3
Net increase due to changes in, and timing of, estimated future cash flows^(b)	80			35			7			—			2			36		34		1		1
Accretion expense^(a)	16			10			4			1			1			—		—		—		—
Asset divestitures	(3		)	(3		)	—			—			—			—		—		—		—
Payments	(6		)	(1		)	(3		)	—			(2		)	—		—		—		—
Non-nuclear AROs at December 31, 2018	$	471		$	238		$	121		$	28		$	25		$	52	$	37	$	11	$	4

__________


(a)	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.


(b)	In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981.

Retirement Benefits (All Registrants)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Retirement Benefits (All Registrants)

(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, non-craft, 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, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are not eligible for retiree health care benefits.

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

The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2018:

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program^(a)

Exelon Corporation Cash Balance Pension Plan^(a)

Exelon Corporation Pension Plan for Bargaining Unit Employees^(a)

Exelon New England Union Employees Pension Plan^(a)

Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek^(a)

Pension Plan of Constellation Energy Group, Inc.^(b)

Pension Plan of Constellation Energy Nuclear Group, LLC^(c)

Nine Mile Point Pension Plan^(c)

Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B^(b)

Pepco Holdings LLC Retirement Plan^(d)

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan^(a)

Exelon Corporation Supplemental Management Retirement Plan^(a)

Constellation Energy Group, Inc. Senior Executive Supplemental Plan^(b)

Constellation Energy Group, Inc. Supplemental Pension Plan^(b)

Constellation Energy Group, Inc. Benefits Restoration Plan^(b)

Constellation Energy Nuclear Plan, LLC Executive Retirement Plan^(c)

Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan^(c)

Baltimore Gas & Electric Company Executive Benefit Plan^(b)

Baltimore Gas & Electric Company Manager Benefit Plan^(b)

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan^(d)

Conectiv Supplemental Executive Retirement Plan^(d)

Pepco Holdings LLC Combined Executive Retirement Plan ^(d)

Atlantic City Electric Director Retirement Plan ^(d)

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Other Postretirement Benefit Plans



			Exelon
			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2018		2017
Equity securities	47	%	44	%	47	%
Fixed income securities	28	%	28		28
Alternative investments^(a)	25	%	28		25
Total			100	%	100	%

__________


(a)	Alternative investments include private equity, hedge funds, real estate, and private credit.

Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 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 December 31, 2018, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.

Fair Value Measurements

The following tables present pension and other postretirement benefit plan assets measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2018 and 2017:

Exelon



December 31, 2018^(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	350	$	—	$	—	$	—	$	350
Equities^(c)	3,364		—		2		1,980		5,346
Fixed income:
U.S. Treasury and agencies	996		173		—		—		1,169
State and municipal debt	—		59		—		—		59
Corporate debt	—		3,716		216		—		3,932
Other^(c)	—		329		—		613		942
Fixed income subtotal	996		4,277		216		613		6,102
Private equity	—		—		—		1,219		1,219
Hedge funds	—		—		—		1,608		1,608
Real estate	—		—		—		1,029		1,029
Private credit	—		—		268		798		1,066
Pension plan assets subtotal	$	4,710	$	4,277	$	486	$	7,247	$	16,720



December 31, 2018^(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	22	$	—	$	—	$	—	$	22
Equities	537		2		—		508		1,047
Fixed income:
U.S. Treasury and agencies	11		56		—		—		67
State and municipal debt	—		126		—		—		126
Corporate debt	—		48		—		—		48
Other	183		72		—		170		425
Fixed income subtotal	194		302		—		170		666
Hedge funds	—		—		—		411		411
Real estate	—		—		—		132		132
Private credit	—		—		—		132		132
Other postretirement benefit plan assets subtotal	$	753	$	304	$	—	$	1,353	$	2,410
Total pension and other postretirement benefit plan assets^(e)	$	5,463	$	4,581	$	486	$	8,600	$	19,130



December 31, 2017^(a)(b)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	585	$	—	$	—	$	—	$	585
Equities^(c)	3,565		—		2		3,077		6,644
Fixed income:
U.S. Treasury and agencies	1,150		159		—		—		1,309
State and municipal debt	—		64		—		—		64
Corporate debt	—		3,931		232		—		4,163
Other^(c)	—		447		—		756		1,203
Fixed income subtotal	1,150		4,601		232		756		6,739
Private equity	—		—		—		1,034		1,034
Hedge funds	—		—		—		1,770		1,770
Real estate	—		—		—		884		884
Private credit^(d)	—		—		224		695		919
Pension plan assets subtotal	$	5,300	$	4,601	$	458	$	8,216	$	18,575



December 31, 2017^(a)(b)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	29	$	—	$	—	$	—	$	29
Equities	523		2		—		764		1,289
Fixed income:
U.S. Treasury and agencies	13		56		—		—		69
State and municipal debt	—		136		—		—		136
Corporate debt	—		47		—		—		47
Other	225		71		—		185		481
Fixed income subtotal	238		310		—		185		733
Hedge funds	—		—		—		430		430
Real estate	—		—		—		124		124
Private credit	—		—		—		123		123
Other postretirement benefit plan assets subtotal	$	790	$	312	$	—	$	1,626	$	2,728
Total pension and other postretirement benefit plan assets^(e)	$	6,090	$	4,913	$	458	$	9,842	$	21,303

__________


(a)	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.


(b)	Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan obligations.

(c)

Includes derivative instruments of less than $1 million and $6 million, which have a total notional amount of $5,991 million and $3,606 million at December 31, 2018 and 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)	Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.


(e)	Excludes net liabilities of $44 million and net assets of $2 million at December 31, 2018 and 2017, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable.

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2018 and 2017:

Exelon



	Fixed Income			Equities		Private Credit		Total
Pension Assets
Balance as of January 1, 2018	$	232		$	2	$	224	$	458
Actual return on plan assets:
Relating to assets still held at the reporting date	(14		)	—		9		(5		)
Relating to assets sold during the period	(1		)	—		—		(1		)
Purchases, sales and settlements:
Purchases	19			—		35		54
Sales	(8		)	—		—		(8		)
Settlements^(b)	(12		)	—		—		(12		)
Balance as of December 31, 2018	$	216		$	2	$	268	$	486



	Fixed income			Equities		Private Credit ^(a)			Total
Pension Assets
Balance as of January 1, 2017	$	206		$	2	$	229		$	437
Actual return on plan assets:
Relating to assets still held at the reporting date	11			—		29			40
Purchases, sales and settlements:
Purchases	31			—		5			36
Sales	(16		)	—		—			(16		)
Settlements^(b)	—			—		(39		)	(39		)
Balance as of December 31, 2017	$	232		$	2	$	224		$	458

__________


(a)	Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.


(b)	Represents cash settlements only.

There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2018 for the pension and other postretirement benefit plan assets.

Valuation Techniques Used to Determine Fair Value

Cash equivalents. Investments with original maturities of three months or less when purchased, including certain short-term fixed income securities and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

Equities. Equities consist of individually held equity securities, equity mutual funds and equity commingled funds in domestic and foreign markets. 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 Exelon is able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. Equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and certain investments are held in accordance with a stated set of fund objectives, which are consistent with the plans’ overall investment strategy. 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 equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of 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.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors 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. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which 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. 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 fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of 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 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.

Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.

Real estate. Real estate funds are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Private credit. Private credit investments primarily consist of limited partnerships that invest in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator and include unobservable inputs such as cost, operating results, and discounted cash flows. Private credit investments are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. The fair value of private credit funds are determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Defined Contribution Savings Plan (All Registrants)

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 matching contributions to the savings plan for the years ended December 31, 2018, 2017 and 2016:



For the Year Ended December 31,	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		BSC^(b)		Pepco^(c)		DPL^(c)		ACE		PHISCO^(c)(d)
2018	$	179	$	86	$	37	$	9	$	12	$	22	$	3	$	2	$	2	$	6
2017	128		55		31		10		10		9		3		2		2		6
2016	164		79		34		10		12		19		3		2		2		6



	Successor						Predecessor
PHI	For the Year Ended December 31, 2018		For the Year Ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Saving Plan Matching Contributions	$	13	$	13	$	10	$	3

__________


(a)	Includes $13 million related to CENG for the year ended December 31, 2016.


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


(c)	Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016.


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

Severance (All Registrants)

12 Months Ended

Dec. 31, 2018

Restructuring and Related Activities [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.

Severance Liability

Amounts included in the table below represent the severance liability recorded for employees of each Registrant. Exelon's severance liability includes amounts related to BSC that are billed through intercompany allocations.




Severance Liability	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco			DPL		ACE
Balance at December 31, 2016	$	88		$	36		$	3		$	—	$	—	$	29		$	—		$	—	$	—
Severance costs^(a)	35			31			2			—		—		3			—			—		—
Payments	(29		)	(9		)	(2		)	—		—		(12		)	—			—		—
Balance at December 31, 2017	$	94		$	58		$	3		$	—	$	—	$	20		$	—		$	—	$	—
Severance costs^(a)	35			9			1			—		1		5			1			—		—
Payments	(52		)	(20		)	(2		)	—		—		(18		)	(1		)	—		—
Balance at December 31, 2018	$	77		$	47		$	2		$	—	$	1	$	7		$	—		$	—	$	—

__________


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

Severance Costs Related to the PHI Merger

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.

For the years ended December 31, 2018 and December 31, 2017, the PHI Merger severance costs were immaterial. For the year ended December 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:



Severance Benefits	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Severance costs^(a)	$	57	$	9	$	2	$	1	$	1	$	44	$	21	$	13	$	10


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations.

PHI, Pepco, DPL and ACE recorded regulatory assets for merger related integration costs which include a portion of these severance costs. These regulatory assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 4 — Regulatory Matters for additional information.

Shareholder Equity (All Registrants)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

Shareholders' Equity (Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE)

The following table presents common stock authorized and outstanding as of December 31, 2018 and 2017:



				December 31,
				2018	2017
	Par Value		Shares Authorized	Shares Outstanding
Common Stock
Exelon	no par value		2,000,000,000	968,187,955	963,335,888
ComEd	$	12.50	250,000,000	127,021,331	127,021,246
PECO	no par value		500,000,000	170,478,507	170,478,507
BGE	no par value		1,500	1,000	1,000
Pepco	$	0.01	200,000,000	100	100
DPL	$	2.25	1,000	1,000	1,000
ACE	$	3.00	25,000,000	8,546,017	8,546,017

ComEd had 60,285 and 60,584 warrants outstanding to purchase ComEd common stock at December 31, 2018 and 2017, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2018 and 2017, 20,095 and 20,195 shares of common stock, respectively, were reserved for the conversion of warrants.

Equity Securities Offering

In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreement by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. The net proceeds were used to fund the merger with PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS using the treasury stock method.

Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of Exelon common stock from treasury stock. See Note 13 — Debt and Credit Agreements for additional information on the equity units.

Share Repurchases

Share Repurchase Programs

There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the previous share repurchase programs, 2 million shares of common stock were held as treasury stock with a historical cost of $123 million at December 31, 2018 and 2017. During 2017, Exelon issued approximately 33 million shares of Exelon common stock from treasury stock in order to settle the forward purchase contract, which was a component of the June 2014 equity units discussed above. During 2018, 2017, and 2016 Exelon had no common stock repurchases.

Preferred and Preference Securities of Subsidiaries

At December 31, 2018 and 2017, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.

At December 31, 2018 and 2017, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding.

BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends.

Stock-Based Compensation Plans (All Registrants)

12 Months Ended

Dec. 31, 2018

Common Stock [Abstract]

Stock-Based Compensation Plans

Stock-Based Compensation Plans (All Registrants)

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2018, there were approximately 11 million shares authorized for issuance under the LTIP. For the years ended December 31, 2018, 2017 and 2016, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

ComEd, PECO, BGE and PHI grant cash awards. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable authoritative guidance.

In connection with the acquisition of PHI in March 2016, PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

For the years ended December 31, 2018, 2017 and 2016, there were no significant modifications to the granted stock based awards.

The following tables present the stock-based compensation expense included in Exelon's and PHI’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2018, 2017 and 2016 and PHI's predecessor period January 1, 2016 to March 23, 2016:



Exelon	Year Ended December 31,
Components of Stock-Based Compensation Expense	2018			2017			2016^(a)
Performance share awards	$	143		$	107		$	93
Restricted stock units	57			77			75
Stock options	—			—			—
Other stock-based awards	8			7			7
Total stock-based compensation expense included in operating and maintenance expense	208			191			175
Income tax benefit	(54		)	(74		)	(68		)
Total after-tax stock-based compensation expense	$	154		$	117		$	107

__________


(a)	2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

PHI



	Predecessor
	January 1 to March 23,
Components of Stock-Based Compensation Expense	2016
Time-based restricted stock units	$	2
Performance-based restricted stock units	1
Time-based restricted stock awards	—
Total stock-based compensation expense included in operating and maintenance expense	3
Income tax benefit	(1		)
Total after-tax stock-based compensation expense	$	2

The following tables present the Registrants' stock-based compensation expense (pre-tax) for the years ended December 31, 2018, 2017 and 2016, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:



	Year Ended December 31,
Subsidiaries	2018		2017		2016
Exelon	$	208	$	191	$	175
Generation	77		88		78
ComEd	8		7		8
PECO	5		3		3
BGE	3		1		1
BSC^(a)	111		88		81
PHI Successor^(b)(c)	4		4		4



	Predecessor
	January 1 to March 23,
	2016
PHI	$	3

__________


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


(b)	Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 2018 and 2017 was not material.


(c)	These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations.

There were no significant stock-based compensation costs capitalized during the years ended December 31, 2018, 2017 and 2016 for Exelon or PHI, or for PHI during the predecessor period January 1, 2016 to March 23, 2016.

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following tables present information regarding Exelon’s tax benefits for the years ended December 31, 2018, 2017 and 2016.



Exelon	Year Ended December 31,
	2018	2017	2016
Realized tax benefit when exercised/distributed:
Restricted stock units	28	35	27
Performance share awards	16	29	18

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were no stock options granted in 2018, 2017 and 2016. For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years and all stock options will expire no later than ten years from the date of grant.

The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.

The following table presents information with respect to stock option activity for the year ended December 31, 2018:



	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2017	6,723,611		$	47.69	2.65	$	7
Options exercised	(1,522,952	)	36.54
Options forfeited	—		—
Options expired	(1,173,007	)	74.99
Balance of shares outstanding at December 31, 2018	4,027,652		$	43.95	2.90	$	14
Exercisable at December 31, 2018 ^(a)	4,027,652		$	43.95	2.90	$	14

__________


(a)	Includes stock options issued to retirement eligible employees.

The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2018, 2017 and 2016:



	Year Ended December 31,
	2018		2017		2016
Intrinsic value^(a)	$	12	$	15	$	11
Cash received for exercise price	56		107		19

__________


(a)	The difference between the market value on the date of exercise and the option exercise price.

At December 31, 2016, all stock options were vested and at December 31, 2018 there were no unrecognized compensation costs related to nonvested stock options.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2018:

Exelon



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2017^(a)	3,389,503		$	32.24
Granted	1,321,988		38.60
Vested	(1,845,300	)	32.03
Forfeited	(65,046	)	32.96
Undistributed vested awards^(b)	(507,804	)	36.76
Nonvested at December 31, 2018^(a)	2,293,341		$	35.06

__________


(a)	Excludes 1,131,487 and 1,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.


(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2018.

For Exelon, the weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2018, 2017 and 2016 was $38.60, $34.98 and $28.14, respectively. At December 31, 2018 and 2017, Exelon had obligations related to outstanding restricted stock units not yet settled of $83 million and $108 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2018, 2017 and 2016, Exelon settled restricted stock units with fair value totaling $106 million, $88 million and $68 million, respectively. At December 31, 2018, $38 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.5 years.

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership requirements are satisfied.

The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.

Effective January 2017 for nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.

In 2016 and prior, for nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.

Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2018:

Exelon



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2017^(a)	2,956,966		$	32.65
Granted	1,637,542		38.15
Change in performance	1,348,029		30.66
Vested	(848,574	)	36.26
Forfeited	(50,467	)	36.24
Undistributed vested awards ^(b)	(1,640,268	)	33.38
Nonvested at December 31, 2018^(a)	3,403,228		$	33.13

__________


(a)	Excludes 3,586,259 and 2,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.


(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2018.

The following table summarizes the weighted average grant date fair value and the fair value of performance share awards granted and settled for the years ended December 31, 2018, 2017 and 2016:



	Year Ended December 31,
	2018^(a)		2017		2016
Weighted average grant date fair value (per share)	$	38.15	$	35.00	$	28.85
Fair value of performance shares settled	61		72		45
Fair value of performance shares settled in cash	49		56		28

__________


(a)	As of December 31, 2018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.

For PHI, the weighted average grant date fair value (per share) of performance-based restricted stock awards was $26.10 for the year ended December 31, 2016. There were no time-based restricted stock awards granted for the year ended December 31, 2016. There were no time-based share settlements or performance-based share settlements for the year-ended December 31, 2016 or the predecessor period January 1, 2016 to March 23, 2016.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:



	December 31,
	2018		2017
Current liabilities^(a)	$	135	$	57
Deferred credits and other liabilities^(b)	109		100
Common stock	26		26
Total	$	270	$	183

__________


(a)	Represents the current liability related to performance share awards expected to be settled in cash.


(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share (Exelon)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Earnings Per Share (Exelon)

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:



	Year Ended December 31,
	2018		2017		2016
Net income attributable to common shareholders	$	2,010	$	3,786	$	1,121
Weighted average common shares outstanding — basic	967		947		924
Assumed exercise and/or distributions of stock-based awards	2		2		3
Weighted average common shares outstanding — diluted	969		949		927

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 3 million in 2018, 8 million in 2017, and 12 million in 2016. 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 years ended December 31, 2018, 2017, and 2016. See Note 18 — Shareholders' Equity for additional information regarding the equity units and equity forward units.

On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33 million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017 triggered full dilution in the EPS calculation, which prior to settlement were included in the calculation of diluted EPS using the treasury stock method. See Note 18 — Shareholders' Equity for additional information regarding share repurchases.

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

12 Months Ended

Dec. 31, 2018

Changes in Accumulated Other Comprehensive Income [Abstract]

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

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 years ended December 31, 2018 and 2017:



For the Year Ended December 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 Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(14	)	$	10		$	(2,998	)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	11			—			(143		)	(10		)	1			(141		)
Amounts reclassified from AOCI^(b)	1			—			181			—			—			182
Net current-period OCI	12			—			38			(10		)	1			41
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard^(c)	—			(10		)	—			—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,960	)	$	(33	)	$	—		$	(2,995	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—		$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	11			—			—			(10		)	—			1
Amounts reclassified from AOCI^(b)	1			—			—			—			—			1
Net current-period OCI	12			—			—			(10		)	—			2
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard^(c)	—			(3		)	—			—			—			(3		)
Ending balance	$	(4	)	$	—		$	—		$	(33	)	$	(1	)	$	(38	)
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 Financial Liabilities standard^(c)	—			(1		)	—			—			—			(1		)
Ending balance	$	—		$	—		$	—		$	—		$	—		$	—



For the Year Ended December 31, 2017	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan items			Foreign Currency Items			AOCI of Investments Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
OCI before reclassifications	(1		)	6		11			7			6			29
Amounts reclassified from AOCI^(b)	4			—		140			—			—			144
Net current-period OCI	3			6		151			7			6			173
Impact of adoption of Reclassification of Certain Tax Effects from AOCI^(d)	—			—		(539		)	—			—			(539		)
Ending balance	$	(14	)	$	10	$	(2,998	)	$	(23	)	$	(1	)	$	(3,026	)
Generation^(a)
Beginning balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
OCI before reclassifications	(1		)	1		—			7			6			13
Amounts reclassified from AOCI^(b)	4			—		—			—			—			4
Net current-period OCI	3			1		—			7			6			17
Ending balance	$	(16	)	$	3	$	—		$	(23	)	$	(1	)	$	(37	)
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 interests. Amounts in parenthesis represent a decrease in AOCI.


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

(c)

Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial 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 1 — Significant Accounting Policies for additional information.

(d)

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

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

For the Year Ended December 31, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Gains (Losses) on cash flow hedges
Other cash flow hedges	$	(1	)	$	(1	)	Interest expense
	(1		)	(1		)	Total before tax
	—			—			Tax benefit
	$	(1	)	$	(1	)	Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	90		$	—
Actuarial losses^(b)	(333		)	—
	(243		)	—			Total before tax
	62			—			Tax benefit
	$	(181	)	$	—		Net of tax

Total Reclassifications	$	(182	)	$	(1	)	Net of tax

For the Year Ended December 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 (Losses) on cash flow hedges
Other cash flow hedges	$	(5	)	$	(5	)	Interest expense
	(5		)	(5		)	Total before tax
	1			1			Tax benefit
	$	(4	)	$	(4	)	Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	92		$	—
Actuarial losses^(b)	(324		)	—
	(232		)	—			Total before tax
	92			—			Tax benefit
	$	(140	)	$	—		Net of tax

Total Reclassifications	$	(144	)	$	(4	)	Net of tax

__________


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


(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 16 — Retirement Benefits for additional information.

The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2018, 2017 and 2016:



	For the Year Ended December 31,
	2018			2017			2016
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	24		$	36		$	30
Actuarial loss reclassified to periodic benefit cost	(86		)	(128		)	(118		)
Pension and non-pension postretirement benefit plans valuation adjustment	50			13			115
Change in unrealized gains on cash flow hedges	(5		)	(7		)	—
Change in unrealized gains (losses) on investments in unconsolidated affiliates	—			(3		)	3
Change in unrealized gains on marketable securities	—			(1		)	—
Total	$	(17	)	$	(90	)	$	30

Generation
Change in unrealized gains on cash flow hedges	$	(4	)	$	(6	)	$	(2	)
Change in unrealized gains (losses) on investments in unconsolidated affiliates	(1		)	(3		)	3
Change in unrealized gains on marketable securities	—			(1		)	—
Total	$	(5	)	$	(10	)	$	1

Commitments and Contingencies (All Registrants)

12 Months Ended

Dec. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies (All Registrants)

Commitments

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 provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.

The direct investment included the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation's investment in leasehold improvements totaled approximately $90 million. In addition, Generation entered into a 20-year operating lease as the primary lessee of the building.

The direct investment commitment also included $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development of 285 - 300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years after the merger. The MDPSC order contemplated various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation have incurred $458 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date and an additional 10 MW commitment satisfied through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment 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, Exelon and Generation recorded a pre-tax $50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016. The remaining commitment is to be paid on or before January 15, 2023 unless the period is extended by consent of Exelon and the State of Maryland. As of December 31, 2018 and 2017, Exelon's and Generation's Consolidated Balance Sheets include a $50 million liability within Deferred credits and other liabilities for this remaining commitment.

Commercial Commitments (All Registrants). Exelon’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	1,703	$	1,394	$	308	$	1	$	—	$	—	$	—
Surety bonds^(a)	1,402		1,331		33		38		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values^(b)	24		3		3		2		3		3		10
Total commercial commitments	$	3,507	$	2,728	$	344	$	41	$	3	$	3	$	388

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61 million, $19 million of which is a guarantee by Pepco, $26 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.

Generation’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	1,680	$	1,380	$	299	$	1	$	—	$	—	$	—
Surety bonds^(a)	1,220		1,201		19		—		—		—		—
Total commercial commitments	$	2,900	$	2,581	$	318	$	1	$	—	$	—	$	—

__________


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

ComEd’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds^(a)	12		10		—		2		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	214	$	12	$	—	$	2	$	—	$	—	$	200

__________


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

PECO’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Surety bonds^(a)	$	9	$	9	$	—	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	187	$	9	$	—	$	—	$	—	$	—	$	178

__________


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

BGE’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	3	$	2	$	1	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		3		14		—		—		—		—
Total commercial commitments	$	20	$	5	$	15	$	—	$	—	$	—	$	—

__________


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

PHI commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	8	$	—	$	8	$	—	$	—	$	—	$	—
Surety bonds^(a)	$	41	$	41	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	24		3		3		2		3		3		10
Total commercial commitments	$	73	$	44	$	11	$	2	$	3	$	3	$	10

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61 million. 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.

Pepco commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	8	$	—	$	8	$	—	$	—	$	—	$	—
Surety bonds^(a)	$	33	$	33	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	8		1		1		1		1		1		3
Total commercial commitments	$	49	$	34	$	9	$	1	$	1	$	1	$	3

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The 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 $19 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and Pepco believes the likelihood of payments being required under the guarantees is remote.

DPL commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Surety bonds^(a)	$	5	$	5	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	10		1		1		1		1		1		5
Total commercial commitments	$	15	$	6	$	1	$	1	$	1	$	1	$	5

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $26 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and DPL believes the likelihood of payments being required under the guarantees is remote.

ACE commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Surety bonds^(a)	$	3	$	3	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	6		1		1		—		1		1		2
Total commercial commitments	$	9	$	4	$	1	$	—	$	1	$	1	$	2

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $16 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and ACE believes the likelihood of payments being required under the guarantees is remote.

Leases (All Registrants)

Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2018 were:



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

__________


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


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

(c)

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


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


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

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2018, 2017 and 2016:



For the Year Ended December 31,	Exelon		Generation^(a)		ComEd		PECO		BGE		Pepco		DPL		ACE
2018	$	670	$	558	$	7	$	10	$	35	$	10	$	13	$	8
2017	709		578		9		9		32		11		16		14
2016	777		667		15		7		22		8		15		13



	Successor						Predecessor
	For the Year Ended December 31, 2018		For the Year Ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
PHI
Rental expense under operating leases	$	48	$	63	$	49	$	12

__________

(a)

Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $493 million, $508 million and $604 million during 2018, 2017 and 2016, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.

For information regarding capital lease obligations, see Note 13—Debt and Credit Agreements.

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 to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2018, the current liability limit per incident is $14.1 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.6 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $3.1 billion, however any amounts payable under this secondary layer would be capped at $454 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $14.1 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 2 — Variable Interest Entities 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. Generation's portion of the annual distribution declared by NEIL is estimated to be $58 million for 2018, and was $60 million and $21 million for 2017 and 2016, respectively. In addition, in March 2018, NEIL declared a supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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 $345 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 statements.

Spent Nuclear Fuel Obligation (Exelon and Generation)

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the years ended December 31, 2018, 2017 and 2016, Generation did not incur any expense in SNF disposal fees. Until a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to be, delayed significantly.

The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama Administration devised a new strategy for long-term SNF management. The Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s SNF and high-level radioactive waste.

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued delays on the part of the DOE, Generation currently assumes the DOE will begin accepting SNF in 2030 and uses that date for purposes of estimating the nuclear decommissioning asset retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement in place. Calvert Cliffs, Ginna and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2017 to provide for the reimbursement of SNF storage costs through December 31, 2019. Generation submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:



	Total		Net^(a)
Cumulative cash reimbursements^(b)	$	1,274	$	1,100

__________


(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.


(b)	Includes $53 and $49, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.

As of December 31, 2018 and 2017, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:



	December 31, 2018			December 31, 2017
DOE receivable - current^(a)	$	124		$	94
DOE receivable - noncurrent^(b)	15			15
Amounts owed to co-owners^(a)(c)	(17		)	(11		)

__________


(a)	Recorded in Accounts receivable, other.


(b)	Recorded in Deferred debits and other assets, other


(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. A prior owner of FitzPatrick also elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. The amounts were recorded at fair value. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on the FitzPatrick acquisition. As of December 31, 2018 and 2017, the SNF liability for the one-time fee with interest was $1,171 million and $1,147 million, respectively, which is included in Exelon's and Generation's Consolidated Balance Sheets. Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2018 was 2.351% for the deferred amount transferred from ComEd and 2.217% for the deferred FitzPatrick amount. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.

Environmental Remediation Matters

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

MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.


•	ComEd has identified 42 sites, 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2023.


•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.


•	BGE has identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.


•	DPL has identified 3 sites, 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 4 — 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.

During the third quarter of 2018, the Utility Registrants completed a study of their future estimated environmental remediation requirements. The study resulted in a $48 million increase to the environmental liability and related regulatory asset for ComEd. The increase was primarily due to a revised closure strategy at one site, which resulted in an increase in the excavation area and depth of impacted soils from the site. The study did not result in a material change to the environmental liability for PECO, BGE, Pepco, DPL, and ACE.

As of December 31, 2018 and 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:



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



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		—

Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a landfill cover remediation approach. 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 September 27, 2018 the EPA issued its ROD Amendment for the selection of the final remedy for the West Lake Landfill Superfund site. The ROD modifies the EPA’s previously proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD also allows for variation in depths of excavation depending on radiological concentrations. The EPA estimates that the ROD will result in a reduction of both radiological and non-radiological waste excavated, with corresponding reductions in the cost and schedule for the remedy. The next step is the negotiation of a Consent Agreement by the EPA with the PRPs to implement the ROD, a process that is expected to be completed in the first quarter of 2020. The estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost 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 required remediation remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Generation’s associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.

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. In September 2018, the PRPs agreed to an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater RI/FS 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. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities 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 financial statements.

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 which was 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 statements.

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 2019 so that settlement discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.

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

Benning Road Site (Exelon, Generation, PHI and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS) for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation.

Since 2013, Pepco and Pepco Energy Services (now Generation) have been performing RI work and have submitted multiple draft RI reports to the DOEE. Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the RI and FS, and approval by the DOEE, by 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 (Exelon, PHI and Pepco). Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning RI/FS. Pepco responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. In April 2018, DOEE released a draft remedial investigation report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies, governmental officials, community organizations and other key stakeholders. In May 2018 the District of Columbia Council extended the deadline for completion of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred, Pepco cannot estimate the reasonably possible range of loss at this time and no liability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated costs is being prepared by the agencies and is expected to be released in 2019, at which time Pepco will likely be in a better position to estimate the range of loss.

In addition to the activities associated with the remedial process outlined above, there is a complementary statutory program that requires an assessment to determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the federal, state and local Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process it cannot reasonably estimate the range of loss.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon, Generation, ComEd and PECO). Generation maintains estimated liabilities 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 December 31, 2018 and 2017, Generation had recorded estimated liabilities of approximately $79 million and $78 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2018, approximately $24 million of this amount related to 238 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.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material unfavorable impact on Exelon's and Generation’s financial statements.

Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE can pay dividends only from retained, undistributed or current earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE may limit the dividends that these companies can distribute to Exelon.

ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued. No such event has occurred.

PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has occurred.

BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. No such event has occurred.

Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such event has occurred.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid it its equity as a percent of its total capitalization, excluding securitization debt, falls below 30%. No such events have occurred.

Conduit Lease with City of Baltimore (Exelon and BGE). On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a decrease to Operating and maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued as well as the settlement of prior year disputed fee true-up amounts.

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 financial statements.

General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or 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.

Supplemental Financial Information (All Registrants)

12 Months Ended

Dec. 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 years ended December 31, 2018, 2017 and 2016.



	For the year ended December 31, 2018
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	919	$	114	$	243	$	131	$	94	$	337	$	316	$	21	$	—
Property	557		273		30		15		143		94		58		32		3
Payroll	247		130		27		16		17		24		5		3		2
Other	60		39		11		1		—		—		—		—		—
Total taxes other than income	$	1,783	$	556	$	311	$	163	$	254	$	455	$	379	$	56	$	5



	For the year ended December 31, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	898	$	126	$	240	$	125	$	89	$	318	$	300	$	18	$	—
Property	545		269		28		14		132		101		62		32		3
Payroll	230		121		26		15		15		26		6		4		2
Other	58		39		2		—		4		7		3		3		1
Total taxes other than income	$	1,731	$	555	$	296	$	154	$	240	$	452	$	371	$	57	$	6



																		Successor		Predecessor
	For the year ended December 31, 2016																	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd			PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Taxes other than income
Utility^(a)	$	753	$	122	$	242		$	136	$	85	$	312	$	18	$	—	$	253	$	78
Property	483		246		27			13		123		53		31		3		73		18
Payroll	226		117		28			15		17		8		5		3		23		8
Other	114		21		(4		)	—		4		4		1		1		5		1
Total taxes other than income	$	1,576	$	506	$	293		$	164	$	229	$	377	$	55	$	7	$	354	$	105

__________

(a)

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



	For the year ended December 31, 2018
													Successor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	506		$	506		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	302			302			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(715		)	(715		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(483		)	(483		)	—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(8		)	(8		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	171			171			—		—		—		—		—		—		—
Total decommissioning-related activities	(227		)	(227		)	—		—		—		—		—		—		—
Investment income	43			32			—		1		1		4		2		1		—
Interest income related to uncertain income tax positions	5			1			—		—		—		—		—		—		—
AFUDC—Equity	69			—			19		7		18		25		22		2		1
Non-service net periodic benefit cost	(47		)	—			—		—		—		—		—		—		—
Other	45			16			14		—		—		14		7		7		1
Other, net	$	(112	)	$	(178	)	$	33	$	8	$	19	$	43	$	31	$	10	$	2



	For the year ended December 31, 2017
													Successor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	488		$	488		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	209			209			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	455			455			—		—		—		—		—		—		—
Non-regulatory agreement units	521			521			—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(10		)	(10		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(724		)	(724		)	—		—		—		—		—		—		—
Total decommissioning-related activities	939			939			—		—		—		—		—		—		—
Investment income	8			6			—		—		—		2		1		—		—
Interest income (expense) related to uncertain income tax positions	3			(1		)	—		—		—		—		—		—		—
Benefit related to uncertain income tax positions^(c)	2			—			—		—		—		—		—		—		—
AFUDC—Equity	73			—			12		9		16		36		23		7		6
Non-service net periodic benefit cost	(109		)	—			—		—		—		—		—		—		—
Other	31			4			10		—		—		16		8		7		1
Other, net	$	947		$	948		$	22	$	9	$	16	$	54	$	32	$	14	$	7



																					Successor			Predecessor
	For the year ended December 31, 2016																				March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE		Pepco		DPL		ACE		PHI			PHI
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	237		$	237		$	—		$	—		$	—	$	—	$	—	$	—	$	—		$	—
Non-regulatory agreement units	126			126			—			—			—		—		—		—		—			—
Net unrealized gains on NDT funds
Regulatory agreement units	216			216			—			—			—		—		—		—		—			—
Non-regulatory agreement units	194			194			—			—			—		—		—		—		—			—
Net unrealized losses on pledged assets
Zion Station decommissioning	(1		)	(1		)	—			—			—		—		—		—		—			—
Regulatory offset to NDT fund-related activities^(b)	(372		)	(372		)	—			—			—		—		—		—		—			—
Total decommissioning-related activities	400			400			—			—			—		—		—		—		—			—
Investment income (loss)	17			8			—			(1		)	2		1		—		1		1			—
Long-term lease income	4			—			—			—			—		—		—		—		—			—
Interest income (expense) related to uncertain income tax positions	13			—			—			—			—		1		—		—		(1		)	—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—		—		—		—		—			—
AFUDC—Equity	64			—			14			8			19		19		5		6		23			7
Non-service net periodic benefit cost	(116		)	—			—			—			—		—		—		—		—			—
Loss on debt extinguishment	(3		)	(2		)	—			—			—		—		—		—		—			—
Other	24			(5		)	7			1			—		15		8		2		21			(11		)
Other, net	$	297		$	401		$	(65	)	$	8		$	21	$	36	$	13	$	9	$	44		$	(4	)

__________


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


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


(c)	See Note 14—Income Taxes for additional information on the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016.



	For the year ended December 31, 2018
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment	$	3,740	$	1,748	$	820	$	274	$	335	$	480	$	218	$	131	$	94
Regulatory assets	555		—		120		27		148		260		167		51		42
Amortization of intangible assets, net	58		49		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	14		14		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,115		1,115		—		—		—		—		—		—		—
ARO accretion^(c)	489		489		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,971	$	3,415	$	940	$	301	$	483	$	740	$	385	$	182	$	136



	For the year ended December 31, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment	$	3,293	$	1,409	$	777	$	261	$	312	$	457	$	203	$	124	$	89
Regulatory assets	478		—		73		25		161		218		118		43		57
Amortization of intangible assets, net	57		48		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	35		35		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,096		1,096		—		—		—		—		—		—		—
ARO accretion^(c)	468		468		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,427	$	3,056	$	850	$	286	$	473	$	675	$	321	$	167	$	146



																	Successor		Predecessor
	For the year ended December 31, 2016																March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	3,477	$	1,835	$	708	$	244	$	299	$	175	$	110	$	82	$	325	$	94
Regulatory assets	407		—		67		26		124		120		47		83		190		58
Amortization of intangible assets, net	52		44		—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	35		35		—		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,159		1,159		—		—		—		—		—		—		—		—
ARO accretion^(c)	446		446		—		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,576	$	3,519	$	775	$	270	$	423	$	295	$	157	$	165	$	515	$	152

__________


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


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


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



	For the year ended December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	1,421		$	369		$	332		$	125		$	94		$	250		$	123		$	56		$	61
Income taxes (net of refunds)	95			746			(153		)	(2		)	14			(32		)	41			(6		)	(12		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	583		$	204		$	177		$	18		$	59		$	67		$	15		$	6		$	12
Loss (gain) from equity method investments	28			30			—			—			—			(1		)	—			—			—
Provision for uncollectible accounts	159			48			40			33			10			28			11			6			11
Provision for excess and obsolete inventory	24			20			3			—			—			—			—			—			—
Stock-based compensation costs	75			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(2		)	(2		)	—			—			—			—			—			—			—
Energy-related options^(b)	10			10			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	8			—			3			1			—			4			2			1			1
Amortization of rate stabilization deferral	14			—			—			—			—			14			14			—			—
Amortization of debt fair value adjustment	(15		)	(12		)	—			—			—			(3		)	—			—			—
Merger-related commitments^(c)	—			—			—			—			—			5			—			5			—
Severance costs	35			9			—			—			—			—			—			—			—
Asset retirement costs	20			—			—			—			—			20			22			(1		)	(1		)
Amortization of debt costs	36			14			5			2			1			3			2			—			1
Discrete impacts from EIMA and FEJA^(d)	28			—			28			—			—			—			—			—			—
Long-term incentive plan	140			—			—			—			—			—			—			—			—
Other	(19		)	(23		)	(14		)	(3		)	(12		)	6			(6		)	7			—
Total other non-cash operating activities	$	1,124		$	298		$	242		$	51		$	58		$	143		$	60		$	24		$	24
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(69	)	$	(199	)	$	11		$	(12	)	$	50		$	93		$	20		$	22		$	46
Change in PPE related to ARO update	(107		)	(130		)	7			—			1			15			12			2			1
Dividends on stock compensation	6			—			—			—			—			—			—			—			—
Acquisition of land	3			—			—			—			—			3			—			—			3

__________


(a)	Includes the elimination of decommissioning-related activities 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 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 to results of operations.


(c)	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.


(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information.



	For the year ended December 31, 2017
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	2,430		$	391		$	307		$	103		$	96		$	236		$	114		$	49		$	59
Income taxes (net of refunds)	540			337			83			47			(2		)	(144		)	(104		)	(49		)	(2		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	643		$	227		$	176		$	29		$	62		$	94		$	25		$	13		$	13
Loss (gain) from equity method investments	32			33			—			—			—			(1		)	—			—			—
Provision for uncollectible accounts	125			38			34			26			8			19			8			3			8
Provision for excess and obsolete inventory	56			51			3			—			—			2			1			1			—
Stock-based compensation costs	88			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(313		)	(313		)	—			—			—			—			—			—			—
Energy-related options^(b)	7			7			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	9			—			4			1			—			4			2			1			1
Amortization of rate stabilization deferral	(10		)	—			—			—			7			(17		)	(17		)	—			—
Amortization of debt fair value adjustment	(18		)	(12		)	—			—			—			(6		)	—			—			—
Merger-related commitments^(c)	—			—			—			—			—			(8		)	(6		)	(2		)	—
Severance costs	35			31			—			—			—			3			—			—			—
Amortization of debt costs	64			37			5			2			2			4			2			—			1
Discrete impacts from EIMA and FEJA^(d)	(52		)	—			(52		)	—			—			—			—			—			—
Vacation accrual adjustment^(e)	(68		)	(35		)	(12		)	—			—			(8		)	(8		)	—			—
Long-term incentive plan	109			—			—			—			—			—			—			—			—
Change in environmental liabilities	44			44			—			—			—			—			—			—			—
Other	(30		)	4			6			(4		)	(14		)	(28		)	(13		)	(7		)	(6		)
Total other non-cash operating activities	$	721		$	112		$	164		$	54		$	65		$	58		$	(6	)	$	9		$	17
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	42		$	73		$	(61	)	$	22		$	23		$	(12	)	$	5		$	4		$	(13	)
Change in PPE related to ARO update	29			29			—			—			—			—			—			—			—
Non-cash financing of capital projects	16			16			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(f)	—			—			21			—			—			—			—			—			—
Dividends on stock compensation	7			—			—			—			—			—			—			—			—
Dissolution of financing trust due to long-term debt retirement	8			—			—			—			8			—			—			—			—



Fair value adjustment of long-term debt due to retirement	(5	)	—	—	—	—	—	—	—	—
Fair value of pension and OPEB obligation transferred in connection with FitzPatrick	—		33	—	—	—	—	—	—	—

__________


(a)	Includes the elimination of decommissioning-related activities 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 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 to results of operations.


(c)	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.


(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 4 — Regulatory Matters for additional information.

(e)

On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that will now be accrued ratably over the year in 2018.


(f)	See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.



																					Successor			Predecessor
	For the year ended December 31, 2016																				March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO		BGE		Pepco			DPL		ACE		PHI			PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	1,340		$	339		$	298		$	104	$	92	$	118		$	47	$	62	$	209		$	43
Income taxes (net of refunds)	(441		)	435			(444		)	64		31		216			115		200		258			11
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	619		$	218		$	166		$	33	$	67	$	31		$	18	$	15	$	86		$	23
Loss from equity method investments	24			25			—			—		—		—			—		—		—			—
Provision for uncollectible accounts	155			19			41			30		1		29			23		32		65			16
Stock-based compensation costs	111			—			—			—		—		—			—		—		—			3
Other decommissioning-related activity^(a)	(384		)	(384		)	—			—		—		—			—		—		—			—
Energy-related options^(b)	(11		)	(11		)	—			—		—		—			—		—		—			—
Amortization of regulatory asset related to debt costs	9			—			4			1		—		2			1		1		3			1
Amortization of rate stabilization deferral	76			—			—			—		81		(12		)	2		—		(5		)	5
Amortization of debt fair value adjustment	(11		)	(11		)	—			—		—		—			—		—		—			—
Merger-related commitments^(c)(d)	558			53			—			—		—		125			82		110		317			—
Severance costs	99			22			—			—		—		—			—		—		56			—
Discrete impacts from EIMA^(e)	8			—			8			—		—		—			—		—		—			—
Amortization of debt costs	35			17			4			3		1		—			—		—		1			—



Provision for excess and obsolete inventory	12			6			4			—			—			3			1			1			1			1
Lower of cost or market inventory adjustment	37			36			—			1			—			—			—			—			—			—
Baltimore City Conduit Lease Settlement	(28		)	—			—			—			(28		)	—			—			—			—			—
Cash Working Capital Order	(13		)	—			—			—			(13		)	—			—			—			—			—
Asset retirement costs	2			—			—			—			—			—			1			2			2			—
Long-term incentive plan	70			—			—			—			—			—			—			—			—			—
Other	(35		)	25			(12		)	(3		)	(21		)	(3		)	(14		)	(6		)	(11		)	(3		)
Total other non-cash operating activities	$	1,333		$	15		$	215		$	65		$	88		$	175		$	114		$	155		$	515		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(128	)	$	50		$	(91	)	$	(11	)	$	(86	)	$	27		$	(12	)	$	11		$	21		$	11
Change in PPE related to ARO update	191			191			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			158			—			—			—			—			—			—			—
Dividends on stock compensation	6			—			—			—			—			—			—			—			—			—
Non-cash financing of capital projects	95			95			—			—			—			—			—			—			—			—
Sale of Upstream assets^(c)	37			37			—			—			—			—			—			—			—			—
Pending FitzPatrick Acquisition^(h)	(54		)	(54		)	—			—			—			—			—			—			—			—
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash	—			119			—			—			—			—			—			—			—			—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash^(c)(f)	—			—			—			—			—			—			—			—			127			—
Fair value of pension obligation transferred in connection with the PHI Merger, net of cash^(c)(f)	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—

__________


(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 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 to results of operations.


(c)	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.


(d)	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.


(e)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 4 — Regulatory Matters for additional information.


(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


(g)	See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.


(h)	Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 5 - Mergers, Acquisitions and Dispositions for additional information.

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



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



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



																	Successor		Predecessor
	December 31, 2016																December 31, 2016		March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Cash and cash equivalents	$	635	$	290	$	56	$	63	$	23	$	9	$	46	$	101	$	170	$	319
Restricted cash	253		158		2		4		24		33		—		9		43		11
Restricted cash included in other long-term assets	26		—		—		—		3		—		—		23		23		18
Total cash, cash equivalents and restricted cash	$	914	$	448	$	58	$	67	$	50	$	42	$	46	$	133	$	236	$	348



											Predecessor
December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	6,502	$	431	$	67	$	295	$	9	$	26	$	5	$	5	$	3
Restricted cash	205		123		2		3		24		14		2		—		12
Restricted cash included in other long-term assets	5		2		—		—		3		18		—		—		18
Total cash, cash equivalents and restricted cash	$	6,712	$	556	$	69	$	298	$	36	$	58	$	7	$	5	$	33

Supplemental Balance Sheet Information

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



December 31, 2018	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Unbilled customer revenues^(a)	$	1,656		$	965		$	223		$	114		$	168		$	186		$	97		$	59		$	30
Allowance for uncollectible accounts ^(b)	(319		)	(104		)	(81		)	(61		)	(20		)	(53		)	(21		)	(13		)	(19		)



December 31, 2017	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Unbilled customer revenues^(a)	$	1,858		$	1,017		$	242		$	162		$	205		$	232		$	133		$	68		$	31
Allowance for uncollectible accounts^(b)	(322		)	(114		)	(73		)	(56		)	(24		)	(55		)	(21		)	(16		)	(18		)

__________


(a)	Represents unbilled portion of receivables estimated under Exelon’s unbilled critical accounting policy.


(b)	Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable.

The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO and ACE purchase receivables at face value and recover uncollectible accounts expense, including those from alternative retail electric and natural gas supplies, through base distribution rates and a rate rider, respectively. Exelon and the Utility Registrants do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are recorded on a net basis in Exelon’s and the Utility Registrant's Consolidated Statements of Operations and Comprehensive Income and are classified in Other accounts receivable, net in their Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of December 31, 2018 and 2017.



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



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 a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

The following tables provide additional information about Registrants' investments at December 31, 2018 and 2017.



December 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Investments
Equity method investments:
Financing trusts^(a)	$	14	$	—	$	6	$	8	$	—	$	—	$	—	$	—	$	—
Bloom	180		180		—		—		—		—		—		—		—
NET Power	70		70		—		—		—		—		—		—		—
Other equity method investments	3		1		—		—		—		—		—		—		—
Total equity method investments	267		251		6		8		—		—		—		—		—
Other investments:
Employee benefit trusts and investments^(b)	244		49		—		17		5		130		105		—		—
Equity investments without readily determinable fair values	72		72		—		—		—		—		—		—		—
Other available for sale debt security investments	40		40		—		—		—		—		—		—		—
Other	2		2		—		—		—		—		—		—		—
Total investments	$	625	$	414	$	6	$	25	$	5	$	130	$	105	$	—	$	—



December 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Investments
Equity method investments:
Financing trusts^(a)	$	14	$	—	$	6	$	8	$	—	$	—	$	—	$	—	$	—
Bloom	206		206		—		—		—		—		—		—		—
NET Power	76		76		—		—		—		—		—		—		—
Other equity method investments	1		1		—		—		—		—		—		—		—
Total equity method investments	297		283		6		8		—		—		—		—		—
Other investments:
Employee benefit trusts and investments^(b)	244		51		—		17		5		132		102		—		—
Equity investments without readily determinable fair values	62		62		—		—		—		—		—		—		—
Other available for sale debt security investments	37		37		—		—		—		—		—		—		—
Total investments	$	640	$	433	$	6	$	25	$	5	$	132	$	102	$	—	$	—

__________


(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.


(b)	The Registrants’ debt and equity security investments are recorded at fair market value.

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



December 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	1,191	$	479	$	187	$	49	$	68	$	99	$	29	$	19	$	12
Taxes accrued	412		226		71		28		46		74		58		4		5
Interest accrued	334		77		105		33		39		50		25		8		12
Severance accrued	44		26		2		—		—		5		—		—		—
Other accrued expenses	131		90		8		3		2		28		14		8		6
Total accrued expenses	$	2,112	$	898	$	373	$	113	$	155	$	256	$	126	$	39	$	35


December 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	978	$	407	$	158	$	64	$	58	$	106	$	29	$	17	$	11
Taxes accrued	373		444		60		15		71		61		68		4		5
Interest accrued	328		78		102		33		34		48		23		8		12
Severance accrued	58		30		2		—		—		17		—		—		—
Other accrued expenses	100		63		5		2		1		29		17		6		5
Total accrued expenses	$	1,837	$	1,022	$	327	$	114	$	164	$	261	$	137	$	35	$	33

__________


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

Segment Information (All Registrants)

12 Months Ended

Dec. 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 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” and ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income.

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


•	New England represents operations within ISO-NE.


•	New York represents operations within ISO-NY.


•	ERCOT represents operations within Electric Reliability Council of Texas.


•	Other Power Regions:


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


•	West represents operations in the WECC, including California ISO.


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

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

During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing the way that information is reviewed by the CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external information presented to third parties. Information for the New England region will be reviewed by the CODM as part of Other Power Regions. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. Beginning in the first quarter of 2019, Other Power Regions will include:


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


•	West represents operations in the WECC, including California ISO.


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


•	New England represents operations within ISO-NE.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2018, 2017, and 2016 is as follows:



									Successor
	Generation ^(a)		ComEd		PECO		BGE		PHI ^(e)		Other ^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2018
Competitive businesses electric revenues	$	17,411	$	—	$	—	$	—	$	—	$	—	$	(1,256	)	$	16,155
Competitive businesses natural gas revenues	2,718		—		—		—		—		—		(8		)	2,710
Competitive businesses other revenues	308		—		—		—		—		—		(5		)	303
Rate-regulated electric revenues	—		5,882		2,470		2,428		4,609		—		(45		)	15,344
Rate-regulated natural gas revenues	—		—		568		741		181		—		(20		)	1,470
Shared service and other revenues	—		—		—		—		15		1,948		(1,960		)	3
Total operating revenues	$	20,437	$	5,882	$	3,038	$	3,169	$	4,805	$	1,948	$	(3,294	)	$	35,985
2017
Competitive businesses electric revenues	$	15,332	$	—	$	—	$	—	$	—	$	—	$	(1,105	)	$	14,227
Competitive businesses natural gas revenues	2,575		—		—		—		—		—		—			2,575
Competitive businesses other revenues	593		—		—		—		—		—		(1		)	592
Rate-regulated electric revenues	—		5,536		2,375		2,489		4,469		—		(29		)	14,840
Rate-regulated natural gas revenues	—		—		495		687		161		—		(10		)	1,333
Shared service and other revenues	—		—		—		—		49		1,831		(1,880		)	—
Total operating revenues	$	18,500	$	5,536	$	2,870	$	3,176	$	4,679	$	1,831	$	(3,025	)	$	33,567



										Successor
	Generation ^(a)			ComEd		PECO		BGE		PHI ^(e)			Other ^(b)			Intersegment Eliminations			Exelon
2016
Competitive businesses electric revenues	$	15,400		$	—	$	—	$	—	$	—		$	—		$	(1,430	)	$	13,970
Competitive businesses natural gas revenues	2,146			—		—		—		—			—			—			2,146
Competitive businesses other revenues	211			—		—		—		—			—			(4		)	207
Rate-regulated electric revenues	—			5,254		2,531		2,609		3,506			—			(31		)	13,869
Rate-regulated natural gas revenues	—			—		463		624		92			—			(13		)	1,166
Shared service and other revenues	—			—		—		—		45			1,648			(1,686		)	7
Total operating revenues	$	17,757		$	5,254	$	2,994	$	3,233	$	3,643		$	1,648		$	(3,164	)	$	31,365

Intersegment revenues^(d):
2018	$	1,269		$	27	$	8	$	29	$	15		$	1,942		$	(3,289	)	$	1
2017	1,110			15		7		16		50			1,824			(3,020		)	2
2016	1,428			15		8		21		45			1,647			(3,159		)	5
Depreciation and amortization:
2018	$	1,797		$	940	$	301	$	483	$	740		$	92		$	—		$	4,353
2017	1,457			850		286		473		675			87			—			3,828
2016	1,879			775		270		423		515			74			—			3,936
Operating expenses ^(c):
2018	$	19,510		$	4,741	$	2,452	$	2,696	$	4,156		$	1,929		$	(3,341	)	$	32,143
2017	18,001			4,214		2,215		2,562		3,911			1,742			(3,026		)	29,619
2016	16,878			4,056		2,292		2,683		3,549			1,812			(3,164		)	28,106
Interest expense, net:
2018	$	432		$	347	$	129	$	106	$	261		$	279		$	—		$	1,554
2017	440			361		126		105		245			283			—			1,560
2016	364			461		123		103		195			290			—			1,536
Income (loss) before income taxes:
2018	$	365		$	832	$	466	$	387	$	432		$	(249	)	$	(1	)	$	2,232
2017	1,455			984		538		525		578			(296		)	(2		)	3,782
2016	857			679		587		468		(58		)	(555		)	(5		)	1,973
Income taxes:
2018	$	(108	)	$	168	$	6	$	74	$	35		$	(55	)	$	—		$	120
2017	(1,376		)	417		104		218		217			294			—			(126		)
2016	282			301		149		174		3			(156		)	—			753



									Successor
	Generation ^(a)		ComEd		PECO		BGE		PHI ^(e)			Other ^(b)			Intersegment Eliminations			Exelon
Net income (loss):
2018	$	443	$	664	$	460	$	313	$	398		$	(193	)	$	(1	)	$	2,084
2017	2,798		567		434		307		362			(590		)	(2		)	3,876
2016	550		378		438		294		(61		)	(398		)	(5		)	1,196
Capital expenditures:
2018	$	2,242	$	2,126	$	849	$	959	$	1,375		$	43		$	—		$	7,594
2017	$	2,259	$	2,250	$	732	$	882	$	1,396		$	65		$	—		$	7,584
2016	$	3,078	$	2,734	$	686	$	934	$	1,008		$	113		$	—		$	8,553
Total assets:
2018	$	47,556	$	31,213	$	10,642	$	9,716	$	21,984		$	8,355		$	(9,800	)	$	119,666
2017	48,457		29,726		10,170		9,104		21,247			8,618			(10,552		)	116,770

__________


(a)	See Note 25 — Related Party Transactions for additional information on intersegment revenues.


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


(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

(d)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory authoritative guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.


(e)	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2018.

Successor and Predecessor PHI:



	Pepco		DPL		ACE		Other^(b)		Intersegment Eliminations			PHI
Operating revenues^(a):
December 31, 2018 - Successor
Rate-regulated electric revenues	$	2,239	$	1,151	$	1,236	$	—	$	(17	)	$	4,609
Rate-regulated natural gas revenues	—		181		—		—		—			181
Shared service and other revenues	—		—		—		435		(420		)	15
Total operating revenues	$	2,239	$	1,332	$	1,236	$	435	$	(437	)	$	4,805
December 31, 2017 - Successor
Rate-regulated electric revenues	$	2,158	$	1,139	$	1,186	$	—	$	(14	)	$	4,469
Rate-regulated natural gas revenues	—		161		—		—		—			161
Shared service and other revenues	—		—		—		52		(3		)	49
Total operating revenues	$	2,158	$	1,300	$	1,186	$	52	$	(17	)	$	4,679
March 24, 2016 to December 31, 2016 - Successor
Rate-regulated electric revenues	$	1,675	$	850	$	989	$	5	$	(13	)	$	3,506
Rate-regulated natural gas revenues	—		92		—		—		—			92
Shared service and other revenues	—		—		—		45		—			45
Total operating revenues	$	1,675	$	942	$	989	$	50	$	(13	)	$	3,643
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues	$	511	$	279	$	268	$	42	$	(4	)	$	1,096
Rate-regulated natural gas revenues	—		56		—		1		—			57
Shared service and other revenues	—		—		—		—		—			—
Total operating revenues	$	511	$	335	$	268	$	43	$	(4	)	$	1,153

Intersegment revenues:
December 31, 2018 - Successor	$	6	$	8	$	3	$	435	$	(437	)	$	15
December 31, 2017 - Successor	6		8		2		53		(19		)	50
March 24, 2016 to December 31, 2016 - Successor	4		5		2		47		(13		)	45
January 1, 2016 to March 23, 2016 - Predecessor	1		2		1		—		(4		)	—
Depreciation and amortization:
December 31, 2018 - Successor	$	385	$	182	$	136	$	37	$	—		$	740
December 31, 2017 - Successor	321		167		146		42		(1		)	$	675
March 24, 2016 to December 31, 2016 - Successor	224		120		128		43		—			$	515
January 1, 2016 to March 23, 2016 - Predecessor	71		37		37		11		(4		)	$	152
Operating expenses:
December 31, 2018 - Successor	$	1,919	$	1,143	$	1,087	$	442	$	(435	)	$	4,156
December 31, 2017 - Successor	1,760		1,071		1,029		68		(17		)	$	3,911
March 24, 2016 to December 31, 2016 - Successor	1,577		952		1,000		33		(13		)	$	3,549
January 1, 2016 to March 23, 2016 - Predecessor	443		284		251		73		(3		)	$	1,048



	Pepco		DPL			ACE			Other^(b)			Intersegment Eliminations			PHI
Interest expense, net:
December 31, 2018 - Successor	$	128	$	58		$	64		$	11		$	—		$	261
December 31, 2017 - Successor	121		51			61			13			(1		)	$	245
March 24, 2016 to December 31, 2016 - Successor	98		38			47			12			—			$	195
January 1, 2016 to March 23, 2016 - Predecessor	29		12			15			11			(2		)	$	65
Income (loss) before income taxes:
December 31, 2018 - Successor	$	223	$	142		$	87		$	388		$	(408	)	$	432
December 31, 2017 - Successor	310		192			103			377			(404		)	$	578
March 24, 2016 to December 31, 2016 - Successor	36		(30		)	(51		)	(84		)	71			$	(58	)
January 1, 2016 to March 23, 2016 - Predecessor	47		43			5			59			(118		)	$	36
Income taxes:
December 31, 2018 - Successor	$	13	$	22		$	12		$	(10	)	$	(2	)	$	35
December 31, 2017 - Successor	105		71			26			15			—			$	217
March 24, 2016 to December 31, 2016 - Successor	26		5			(5		)	(23		)	—			$	3
January 1, 2016 to March 23, 2016 - Predecessor	15		17			1			(16		)	—			$	17
Net income (loss):
December 31, 2018 - Successor	$	210	$	120		$	75		$	(22	)	$	15		$	398
December 31, 2017 - Successor	205		121			77			(91		)	50			$	362
March 24, 2016 to December 31, 2016 - Successor	10		(35		)	(47		)	(34		)	45			$	(61	)
January 1, 2016 to March 23, 2016 - Predecessor	32		26			5			(44		)	—			$	19
Capital expenditures:
December 31, 2018 - Successor	$	656	$	364		$	335		$	20		$	—		$	1,375
December 31, 2017 - Successor	628		428			312			28			—			$	1,396
March 24, 2016 to December 31, 2016 - Successor	489		277			218			24			—			1,008
January 1, 2016 to March 23, 2016 - Predecessor	97		72			93			11			—			273
Total assets:
December 31, 2018 - Successor	$	8,299	$	4,588		$	3,699		$	10,819		$	(5,421	)	$	21,984
December 31, 2017 - Successor	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 in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation's two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon's disaggregated revenues are consistent with Generation and the Utility Registrants but exclude any intercompany revenues.

Competitive Business Revenues (Generation):



	2018
	Revenues from external customers^(a)
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	5,241	$	233		$	5,474	$	13		$	5,487
Midwest	4,527		190			4,717		(11		)	4,706
New England	2,660		185			2,845		(4		)	2,841
New York	1,723		(36		)	1,687		—			1,687
ERCOT	572		560			1,132		1			1,133
Other Power Regions	870		686			1,556		(62		)	1,494
Total Competitive Businesses Electric Revenues	15,593		1,818			17,411		(63		)	17,348
Competitive Businesses Natural Gas Revenues	1,524		1,194			2,718		62			2,780
Competitive Businesses Other Revenues^(c)	510		(202		)	308		1			309
Total Generation Consolidated Operating Revenues	17,627		2,810			$	20,437	$	—		$	20,437



	2017
	Revenues from external customers^(a)
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	5,523	$	(8	)	$	5,515	$	25		$	5,540
Midwest	3,923		283			4,206		(25		)	4,181
New England	2,064		(54		)	2,010		(8		)	2,002
New York	1,605		(38		)	1,567		(17		)	1,550
ERCOT	641		317			958		4			962
Other Power Regions	594		482			1,076		(27		)	1,049
Total Competitive Businesses Electric Revenues	14,350		982			15,332		(48		)	15,284
Competitive Businesses Natural Gas Revenues	1,658		917			2,575		53			2,628
Competitive Businesses Other Revenues^(c)	744		(151		)	593		(5		)	588
Total Generation Consolidated Operating Revenues	$	16,752	$	1,748		$	18,500	$	—		$	18,500



	2016
	Revenues from external customers^(a)
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	6,182	$	30		$	6,212	$	(33	)	$	6,179
Midwest	4,007		395			4,402		10			4,412
New England	1,953		(175		)	1,778		(9		)	1,769
New York	1,198		10			1,208		(42		)	1,166
ERCOT	810		21			831		6			837
Other Power Regions	670		299			969		(62		)	907
Total Competitive Businesses Electric Revenues	14,820		580			15,400		(130		)	15,270
Competitive Businesses Natural Gas Revenues	1,953		193			2,146		135			2,281
Competitive Businesses Other Revenues^(c)	756		(545		)	211		(5		)	206
Total Generation Consolidated Operating Revenues	$	17,529	$	228		$	17,757	$	—		$	17,757

__________


(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 $38 million and $52 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017 and 2016, respectively, unrealized mark-to-market losses of $262 million, $131 million, and $500 million in 2018, 2017, and 2016, respectively, and elimination of intersegment revenues.

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



	2018							2017							2016
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	3,022	$	51		$	3,073	$	3,105	$	109		$	3,214	$	3,282	$	35		$	3,317
Midwest	3,112		23			3,135		2,810		10			2,820		2,969		2			2,971
New England	368		(14		)	354		538		(24		)	514		467		(29		)	438
New York	1,112		10			1,122		1,007		1			1,008		771		(19		)	752
ERCOT	501		(243		)	258		575		(243		)	332		412		(131		)	281
Other Power Regions	515		(140		)	375		476		(171		)	305		483		(147		)	336
Total Revenues net of purchased power and fuel for Reportable Segments	$	8,630	$	(313	)	$	8,317	$	8,511	$	(318	)	$	8,193	$	8,384	$	(289	)	$	8,095
Other ^(b)	114		313			427		299		318			617		543		289			832
Total Generation Revenues net of purchased power and fuel expense	$	8,744	$	—		$	8,744	$	8,810	$	—		$	8,810	$	8,927	$	—		$	8,927

__________


(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 $54 million and $57 million decrease in RNF for the amortization of intangible assets and liabilities related to commodity contracts in 2017 and 2016, respectively, unrealized mark-to-market losses of $319 million, $175 million, and $41 million in 2018, 2017, and 2016, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 8 - Early Plant Retirements of $57 million, $12 million and $60 million for the year ended December 31, 2018, 2017, and 2016 and the elimination of intersegment RNF.

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



	2018
										Successor
Revenues from contracts with customers	ComEd			PECO			BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,942		$	1,566		$	1,382		$	2,351	$	1,021	$	669	$	661
Small commercial & industrial	1,487			404			257			488		140		186		162
Large commercial & industrial	538			223			429			1,124		846		100		178
Public authorities & electric railroads	47			28			28			58		32		14		12
Other^(a)	867			243			327			593		193		175		227
Total rate-regulated electric revenues^(b)	5,881			2,464			2,423			4,614		2,232		1,144		1,240
Rate-regulated natural gas revenues
Residential	—			395			491			99		—		99		—
Small commercial & industrial	—			143			77			44		—		44		—
Large commercial & industrial	—			1			124			8		—		8		—
Transportation	—			23			—			16		—		16		—
Other^(c)	—			6			63			13		—		13		—
Total rate-regulated natural gas revenues^(d)	—			568			755			180		—		180		—
Total rate-regulated revenues from contracts with customers	5,881			3,032			3,178			4,794		2,232		1,324		1,240

Other revenues
Revenues from alternative revenue programs	(29		)	(7		)	(26		)	—		—		4		(4		)
Other rate-regulated electric revenues^(e)	30			12			13			10		7		3		—
Other rate-regulated natural gas revenues^(e)	—			1			4			1		—		1		—
Total other revenues	1			6			(9		)	11		7		8		(4		)
Total rate-regulated revenues for reportable segments	$	5,882		$	3,038		$	3,169		$	4,805	$	2,239	$	1,332	$	1,236



	2017
							Successor
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,715	$	1,505	$	1,365	$	2,246	$	964	$	663	$	619
Small commercial & industrial	1,363		401		254		490		137		187		166
Large commercial & industrial	455		223		427		1,086		794		103		189
Public authorities & electric railroads	44		30		31		60		33		14		13
Other^(a)	886		204		299		541		199		163		191
Total rate-regulated electric revenues^(b)	5,463		2,363		2,376		4,423		2,127		1,130		1,178
Rate-regulated natural gas revenues
Residential	—		331		437		90		—		90		—
Small commercial & industrial	—		131		75		38		—		38		—
Large commercial & industrial	—		1		119		8		—		8		—
Transportation	—		23		—		15		—		15		—
Other^(c)	—		8		28		9		—		9		—
Total rate-regulated natural gas revenues^(d)	—		494		659		160		—		160		—
Total rate-regulated revenues from contracts with customers	5,463		2,857		3,035		4,583		2,127		1,290		1,178

Other revenues
Revenues from alternative revenue programs	43		—		124		40		26		6		8
Other rate-regulated electric revenues^(e)	30		12		13		8		5		3		—
Other rate-regulated natural gas revenues^(e)	—		1		4		1		—		1		—
Other revenues^(f)	—		—		—		47		—		—		—
Total other revenues	73		13		141		96		31		10		8
Total rate-regulated revenues for reportable segments	$	5,536	$	2,870	$	3,176	$	4,679	$	2,158	$	1,300	$	1,186



															Successor		Predecessor
	2016														March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Revenues from contracts with customers	ComEd			PECO		BGE		Pepco		DPL			ACE		PHI		PHI
Rate-regulated electric revenues
Residential	$	2,603		$	1,631	$	1,504	$	1,004	$	672		$	664	$	1,779	$	561
Small commercial & industrial	1,318			430		276		150		188			183		400		121
Large commercial & industrial	462			234		434		790		99			201		835		255
Public authorities & electric railroads	45			32		35		32		13			13		45		13
Other^(a)	820			192		276		190		160			187		400		169
Total rate-regulated electric revenues^(b)	5,248			2,519		2,525		2,166		1,132			1,248		3,459		1,119
Rate-regulated natural gas revenues
Residential	—			309		432		—		86			—		50		36
Small commercial & industrial	—			121		66		—		35			—		21		14
Large commercial & industrial	—			—		114		—		6			—		4		2
Transportation	—			24		—		—		13			—		10		3
Other^(c)	—			9		28		—		8			—		7		2
Total rate-regulated natural gas revenues^(d)	—			463		640		—		148			—		92		57
Total rate-regulated revenues from contracts with customers	5,248			2,982		3,165		2,166		1,280			1,248		3,551		1,176

Other revenues
Revenues from alternative revenue programs	(24		)	—		53		14		(6		)	9		43		(26		)
Other rate-regulated electric revenues^(e)	30			12		13		6		3			—		6		3
Other rate-regulated natural gas revenues^(e)	—			—		2		—		—			—		—		—
Other revenues^(f)	—			—		—		—		—			—		43		—
Total other revenues	6			12		68		20		(3		)	9		92		(23		)
Total rate-regulated revenues for reportable segments	$	5,254		$	2,994	$	3,233	$	2,186	$	1,277		$	1,257	$	3,643	$	1,153

__________


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

(b)

Includes operating revenues from affiliates of $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2018, $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in 2017, and $15 million, $7 million, $7 million, $2 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2016.


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


(d)	Includes operating revenues from affiliates of $1 million and $21 million at PECO and BGE, respectively, in 2018, $1 million and $11 million at PECO and BGE, respectively, in 2017, and $1 million and $14 million at PECO and BGE, respectively, in 2016.


(e)	Includes late payment charge revenues.


(f)	Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016, respectively.

Related Party Transactions (All Registrants)

12 Months Ended

Dec. 31, 2018

(All Registrants)

Exelon

The financial statements of Exelon include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018			2017			2016
Operating revenues from affiliates:
Generation ^(a)	(2		)	—
PECO ^(a)	—			1			1
BGE ^(a)	—			4			4
ACE ^(a)	—			—			—
Other	1			2			5
Total operating revenues from affiliates	$	(1	)	$	7		$	10
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	14		$	13
PECO Trust III	6			6			6
PECO Trust IV	6			6			6
BGE Capital Trust II	—			10			16
Total interest expense to affiliates, net	$	25		$	36		$	41
Earnings (losses) in equity method investments:
Qualifying facilities and domestic power projects	$	(29	)	$	(33	)	$	(25	)
Other	1			1			1
Total losses in equity method investments	$	(28	)	$	(32	)	$	(24	)



	December 31,
	2018		2017
Payables to affiliates (current):
ComEd Financing III	$	4	$	4
PECO Trust III	1		1
Total payables to affiliates (current)	$	5	$	5
Long-term debt to financing trusts:
ComEd Financing III	$	206	$	205
PECO Trust III	81		81
PECO Trust IV	103		103
Total long-term debt to financing trusts	$	390	$	389

__________

(a)

The intersegment profit associated with the 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 authoritative guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. See Note 4—Regulatory Matters for additional information.

Transactions involving Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are further described in the tables below.

Generation

The financial statements of Generation include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018			2017			2016
Operating revenues from affiliates:
ComEd ^(a)	$	523		$	121		$	47
PECO ^(b)	128			138			290
BGE ^(c)	260			388			608
Pepco ^(d)	206			255			295
DPL ^(e)	120			179			154
ACE^(f)	29			29			37
BSC	2			1			2
Other	—			4			6
Total operating revenues from affiliates	$	1,268		$	1,115		$	1,439
Purchased power and fuel from affiliates:
ComEd	$	(6	)	$	13		$	—
BGE	20			9			12
Other	—			(3		)	—
Total purchased power and fuel from affiliates	$	14		$	19		$	12
Operating and maintenance from affiliates:
ComEd ^(g)	$	7		$	7		$	7
PECO ^(g)	2			1			3
BGE ^(g)	2			1			1
Pepco	1			—			1
PHISCO	1			1			1
BSC ^(h)	652			689			650
Other	(4		)	(2		)	—
Total operating and maintenance from affiliates	$	661		$	697		$	663
Interest expense to affiliates, net:
Exelon Corporate ⁽ⁱ⁾	$	36		$	37		$	39
PCI	—			1			—
PECO	—			1			—
Total interest expense to affiliates, net:	$	36		$	39		$	39
Earnings (losses) in equity method investments
Qualifying facilities and domestic power projects	$	(30	)	$	(33	)	$	(25	)
Capitalized costs
BSC ^(h)	$	67		$	98		$	98
Cash distributions paid to member	$	1,001		$	659		$	922
Contributions from member	$	155		$	102		$	142



	December 31,
	2018		2017
Receivables from affiliates (current):
ComEd ^(a)	$	69	$	28
PECO ^(b)	30		26
BGE ^(c)	24		24
Pepco ^(d)	28		36
DPL ^(e)	7		12
ACE ^(f)	5		6
PHISCO ^(h)	—		1
Other	10		7
Total receivables from affiliates (current)	$	173	$	140
Intercompany money pool (current):
Exelon Corporate	$	100	$	—
PCI	—		54
Total intercompany money pool (current)	$	100	$	54
Payables to affiliates (current):
Exelon Corporate ⁽ⁱ⁾	$	17	$	21
BSC ^(h)	95		74
ComEd	19		12
PECO ^(b)	—		4
Other	8		12
Total payables to affiliates (current)	$	139	$	123
Other liabilities to affiliates (current):
ComEd ^(a)	$	14	$	—
Long-term debt to affiliates (noncurrent):
Exelon Corporate ^(k)	$	898	$	910
Payables to affiliates (noncurrent):
ComEd ^(j)	$	2,217	$	2,528
PECO ^(j)	389		537
Total payables to affiliates (noncurrent)	$	2,606	$	3,065

__________


(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.


(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.


(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.


(d)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.


(e)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.


(f)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.


(g)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.


(h)	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(i)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.


(j)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations for additional information.

(k)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.

ComEd

The financial statements of ComEd include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates
Generation	$	9	$	9	$	7
BSC	7		6		6
PECO	10		—		1
BGE	1		—		1
Total operating revenues from affiliates	$	27	$	15	$	15
Purchased power from affiliates
Generation ^(a)	$	529	$	108	$	47
Operating and maintenance from affiliates
BSC ^(b)	$	265	$	270	$	225
PECO	1		—		1
BGE	1		—		1
Total operating and maintenance from affiliates	$	267	$	270	$	227
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC ^(b)	$	135	$	118	$	112
Cash dividends paid to parent	$	459	$	422	$	369
Contributions from parent	$	500	$	651	$	315



	December 31,
	2018		2017
Prepaid voluntary employee beneficiary association trust ^(c)	$	5	$	2
Receivables from affiliates (current):
Voluntary employee beneficiary association trust	$	1	$	1
Generation	19		12
Total receivables from affiliates (current)	$	20	$	13
Receivables from affiliates (noncurrent):
Generation ^(d)	$	2,217	$	2,528
Payables to affiliates (current):
Generation ^(a)	$	55	$	28
BSC ^(b)	56		39
ComEd Financing III	4		4
Exelon Corporate	4		3
Total payables to affiliates (current)	$	119	$	74
Long-term debt to ComEd financing trust:
ComEd Financing III	$	205	$	205

__________


(a)	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation.


(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.


(d)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.

PECO

The financial statements of PECO include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017			2016
Operating revenues from affiliates:
Generation ^(a)	$	2	$	1		$	3
BSC	3		5			3
ComEd	1		—			1
BGE	1		1			1
ACE	1		—			—
Total operating revenues from affiliates	$	8	$	7		$	8
Purchased power from affiliates
Generation^(b)	$	126	$	135		$	287
Operating and maintenance from affiliates:
BSC ^(c)	$	146	$	146		$	142
Generation	2		2			2
ComEd	7		—			1
BGE	1		1			1
Total operating and maintenance from affiliates	$	156	$	149		$	146
Interest expense to affiliates, net:
PECO Trust III	$	6	$	6		$	6
PECO Trust IV	6		6			6
Exelon Corporate	2		—			—
Generation	—		(1		)	—
Total interest expense to affiliates, net:	$	14	$	11		$	12
Capitalized costs
BSC ^(c)	$	64	$	59		$	57
Cash dividends paid to parent	$	306	$	288		$	277
Contributions from parent	$	89	$	16		$	18



	December 31,
	2018		2017
Prepaid voluntary employee beneficiary association trust ^(d)	$	1	$	—
Receivables from affiliates (noncurrent):
Generation ^(e)	$	389	$	537
Payables to affiliates (current):
Generation^(b)	$	30	$	22
BSC^(c)	26		29
Exelon Corporate	2		1
PECO Trust III	1		1
Total payables to affiliates (current)	$	59	$	53
Long-term debt to financing trusts:
PECO Trust III	$	81	$	81
PECO Trust IV	103		103
Total long-term debt to financing trusts	$	184	$	184

__________


(a)	PECO provides energy to Generation for Generation’s own use.


(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively.


(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.


(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

BGE

The financial statements of BGE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
Generation ^(a)	$	22	$	10	$	13
BSC	5		5		6
ComEd	1		—		1
PECO	1		1		1
Total operating revenues from affiliates	$	29	$	16	$	21
Purchased power from affiliates
Generation ^(b)	$	257	$	384	$	604
Operating and maintenance from affiliates:
BSC ^(c)	$	157	$	152	$	130
Generation	3		—		—
ComEd	1		—		1
PECO	1		1		1
Total operating and maintenance from affiliates	$	162	$	153	$	132
Interest expense to affiliates, net:
BGE Capital Trust II	$	—	$	10	$	16
Capitalized costs
BSC ^(c)	$	79	$	54	$	36
Cash dividends paid to parent	$	209	$	198	$	179
Contributions from parent	$	109	$	184	$	61



	December 31,
	2018		2017
Receivables from affiliates (current):
Other	$	1	$	1
Payables to affiliates (current):
Generation ^(b)	$	24	$	24
BSC ^(c)	38		25
Exelon Corporate	2		1
Other	1		2
Total payables to affiliates (current)	$	65	$	52

__________


(a)	BGE provides energy to Generation for Generation’s own use.


(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.


(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

PHI

The financial statements of PHI include related party transactions as presented in the tables below:



	Successor
	For the Year Ended December 31,		For the Year Ended December 31,		March 24, 2016 to December 31,
	2018		2017		2016
Operating revenues from affiliates:
BSC	$	12	$	48	$	44
PHISCO	1		2		—
Generation	2		—		1
Total operating revenues from affiliates	$	15	$	50	$	45
Purchased power from affiliates
Generation	$	355	$	463	$	486
Operating and maintenance from affiliates:
BSC ^(a)	$	147	$	145	$	86
Other	5		5		3
Total operating and maintenance from affiliates	$	152	$	150	$	89
Earnings (losses) in equity method investments:
Other	$	1	$	—	$	—
Capitalized costs:
BSC ^(a)	$	102	$	—	$	—
PHISCO ^(a)	79		—		—
Total capitalized costs	$	181	$	—	$	—
Cash dividends paid to parent	$	326	$	311	$	273
Contributions from parent	$	385	$	758	$	1,251



	December 31,
	2018		2017
Payables to affiliates (current):
Generation	$	40	$	54
BGE	—		1
BSC^(a)	41		24
Exelon Corporate	6		6
Other	7		5
Total payables to affiliates (current)	$	94	$	90

__________


(a)	PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Pepco

The financial statements of Pepco include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
Generation ^(a)	$	1	$	—	$	1
BSC	1		—		—
PHISCO	4		6		4
Total operating revenues from affiliates	$	6	$	6	$	5
Purchased power from affiliates
Generation ^(b)	$	206	$	255	$	295
Operating and maintenance:
PHISCO ^{(c), (e)}	$	—	$	219	$	263
PES ^(d)	—		29		39
Total operating and maintenance	$	—	$	248	$	302
Operating and maintenance from affiliates:
BSC ^(c)	$	89	$	53	$	31
PHISCO ^{(c), (e)}	137		5		4
Total operating and maintenance from affiliates	$	226	$	58	$	35
Capitalized costs:
BSC ^(c)	$	40	$	—	$	—
PHISCO ^(c)	32		—		—
Total capitalized costs	$	72	$	—	$	—
Cash dividends paid to parent	$	169	$	133	$	136
Contributions from parent	$	166	$	161	$	187



	December 31,
	2018		2017
Receivables from affiliates (current):
DPL	$	1	$	—
Payables to affiliates (current):
Exelon Corporation	$	1	$	—
Generation ^(b)	28		36
BSC ^(c)	19		11
PHISCO ^(c)	14		27
Total payables to affiliates (current)	$	62	$	74

__________


(a)	Pepco provides energy to Generation for Generation’s own use.


(b)	Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs.


(c)	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.


(e)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

DPL

The financial statements of DPL include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
BSC	$	1	$	—	$	—
PHISCO	4		6		5
ComEd	1		—		—
ACE	1		—		—
Other	1		2		2
Total operating revenues from affiliates	$	8	$	8	$	7
Purchased power from affiliates
Generation ^(a)	$	120	$	179	$	154
Operating and maintenance:
PHISCO ^{(b), (d)}	$	—	$	165	$	194
PES ^(c)	—		9		8
Total operating and maintenance	$	—	$	174	$	202
Operating and maintenance from affiliates:
BSC ^(b)	$	51	$	31	$	18
PHISCO ^{(b), (d)}	111		—		—
Other	—		1		1
Total operating and maintenance from affiliates	$	162	$	32	$	19
Capitalized costs:
BSC ^(b)	$	28	$	—	$	—
PHISCO ^(b)	25		—		—
Total capitalized costs	$	53	$	—	$	—
Cash dividends paid to parent	$	96	$	112	$	54
Contributions from parent	$	150	$	—	$	152



	December 31,
	2018		2017
Payables to affiliates (current):
Exelon Corporate	$	1	$	—
Generation ^(a)	7		12
BSC ^(b)	11		7
PHISCO ^(b)	12		27
Pepco	1		—
ACE	1		—
Total payables to affiliates (current)	$	33	$	46

__________


(a)	DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs.


(b)	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(c)	PES performed underground transmission construction services, including services that are treated as capital costs, for DPL.


(d)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

ACE

The financial statements of ACE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
PHISCO	$	2	$	1	$	2
Other	1		1		1
Total operating revenues from affiliates	$	3	$	2	$	3
Purchased power from affiliates
Generation ^(a)	$	29	$	29	$	37
Operating and maintenance:
PHISCO ^{(b), (c)}	$	—	$	135	$	155
Operating and maintenance from affiliates:
BSC ^(b)	$	42	$	25	$	15
PHISCO ^{(b), (c)}	98		—		—
Other	2		3		3
Total operating and maintenance from affiliates	$	142	$	28	$	18
Capitalized costs:
BSC ^(b)	$	20	$	—	$	—
PHISCO ^(b)	21		—		—
Total capitalized costs	$	41	$	—	$	—
Cash dividends paid to parent	$	59	$	68	$	63
Contributions from parent	$	67	$	—	$	139



	December 31,
	2018		2017
Receivable from affiliate (current):
DPL	$	1	$	—
Payables to affiliates (current):
Generation ^(a)	$	5	$	6
BSC ^(b)	8		5
PHISCO ^(b)	13		18
Other	2		—
Total payables to affiliates (current)	$	28	$	29

__________


(a)	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process.


(b)	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(c)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

Quarterly Data (Unaudited) (All Registrants)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Data [Abstract]

Quarterly Data (Unaudited) (All Registrants)

Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income Attributable to Common Shareholders
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	9,693	$	8,747	$	1,101	$	1,308	$	585	$	990
June 30	8,076		7,665		942		300		539		95
September 30	9,403		8,768		1,146		1,499		733		823
December 31	8,814		8,384		708		1,288		152		1,880



	Net Income per Basic Share				Net Income per Diluted Share
	2018		2017		2018		2017
Quarter ended:
March 31	$	0.61	$	1.07	$	0.60	$	1.06
June 30	0.56		0.10		0.56		0.10
September 30	0.76		0.86		0.76		0.85
December 31	0.16		1.95		0.16		1.94

Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income (Loss)					Net Income (Loss) Attributable to Membership Interest
	2018		2017		2018		2017			2018			2017
Quarter ended:
March 31	$	5,512	$	4,878	$	347	$	373		$	136		$	418
June 30	4,579		4,216		282		(427		)	178			(235		)
September 30	5,278		4,750		311		497			234			304
December 31	5,069		4,657		35		504			(178		)	2,224

ComEd

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	1,512	$	1,298	$	292	$	314	$	165	$	141
June 30	1,398		1,357		288		319		164		118
September 30	1,598		1,571		323		404		193		189
December 31	1,373		1,309		242		286		141		120

PECO

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	866	$	796	$	142	$	192	$	113	$	127
June 30	653		630		127		137		96		88
September 30	757		715		154		169		126		112
December 31	765		729		165		157		124		107

BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	977	$	951	$	177	$	228	$	128	$	125
June 30	662		674		85		98		51		45
September 30	731		738		103		124		63		62
December 31	799		813		109		163		71		76

PHI

The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income Attributable to Membership Interest
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	1,251	$	1,175	$	126	$	180	$	65	$	140
June 30	1,076		1,074		153		148		84		66
September 30	1,361		1,310		245		285		187		153
December 31	1,117		1,121		126		159		62		4

Pepco

The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	557	$	530	$	56	$	79	$	31	$	58
June 30	523		514		85		84		54		43
September 30	628		604		112		149		89		87
December 31	531		510		65		87		36		17

DPL

The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	384	$	362	$	49	$	78	$	31	$	57
June 30	289		282		42		41		26		19
September 30	328		327		51		59		33		31
December 31	331		330		48		52		30		14

ACE

The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income (Loss)
	2018		2017		2018		2017		2018			2017
Quarter ended:
March 31	$	310	$	275	$	23	$	25	$	7		$	28
June 30	265		270		25		25		8			8
September 30	406		370		84		79		61			41
December 31	254		271		14		28		(1		)	—

Subsequent Events Subsequent Events (Exelon and Generation)	12 Months Ended
	Dec. 31, 2018
Subsequent Events [Abstract]
Subsequent Events [Text Block]	Subsequent Events (Exelon and Generation) Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to Pacific Gas and Electric Company (PG&E) through a PPA. As of December 31, 2018, Generation had approximately $750 million and $510 million of net long-lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. The nonrecourse debt is guaranteed by the DOE Loan Programs Office. Neither the guarantor nor the lender have recourse against Exelon or Generation in the event of default. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. PG&E’s bankruptcy creates an event of default for Antelope Valley’s nonrecourse debt. As such, Antelope Valley is currently in discussions with the DOE Loan Programs Office, and the debt has not yet been accelerated. Given that the event of default did not occur until January 2019, the debt continued to be classified as non-current on Exelon’s and Generation’s Consolidated Balance Sheets as of December 31, 2018, and may be reclassified to current in 2019. Generation has also assessed and determined that Antelope Valley’s long-lived assets are not impaired as of December 31, 2018. Changes in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley. The impairment loss could be substantially all of the net long-lived assets if Antelope Valley was valued without the PPA. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the carrying amount of the net long-lived assets of Antelope Valley may not be recoverable. Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,990 million and $830 million of additional net long-lived assets and nonrecourse debt outstanding, respectively, as of December 31, 2018. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. EGR IV is currently not in default, however, an acceleration of Antelope Valley’s debt could impact EGR IV. The lenders do not have recourse against Exelon or Generation in the event of default by EGR IV. See Note 2 - Variable Interest Entities for additional details on EGRP and Note 13 — Debt and Credit Agreements for additional details on Generation's nonrecourse project financings.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)

12 Months Ended

Dec. 31, 2018

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Operations and Other Comprehensive Income



	For the Years Ended December 31,
(In millions)	2018			2017			2016
Operating expenses
Operating and maintenance	$	(5	)	$	10		$	221
Operating and maintenance from affiliates	9			25			51
Other	4			4			4
Total operating expenses	8			39			276
Operating loss	(8		)	(39		)	(276		)
Other income and (deductions)
Interest expense, net	(312		)	(315		)	(312		)
Equity in earnings of investments	2,188			4,414			1,508
Interest income from affiliates, net	42			40			39
Other, net	3			1			7
Total other income	1,921			4,140			1,242
Income before income taxes	1,913			4,101			966
Income taxes	(97		)	315			(155		)
Net income	$	2,010		$	3,786		$	1,121
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs	$	(66	)	$	(56	)	$	(48	)
Actuarial loss reclassified to periodic cost	247			197			184
Pension and non-pension postretirement benefit plan valuation adjustment	(143		)	10			(181		)
Unrealized gain on cash flow hedges	12			3			2
Unrealized gain on marketable securities	—			6			1
Unrealized gain (loss) on equity investments	1			6			(4		)
Unrealized (loss) gain on foreign currency translation	(10		)	7			10
Other comprehensive income (loss)	41			173			(36		)
Comprehensive income	$	2,051		$	3,959		$	1,085

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Cash Flows



	For the Years Ended December 31,
(In millions)	2018			2017			2016
Net cash flows provided by operating activities	$	2,581		$	1,921		$	1,029
Cash flows from investing activities
Changes in Exelon intercompany money pool	1			(129		)	1,390
Investment in affiliates	(1,236		)	(1,717		)	(1,757		)
Acquisition of business	—			—			(6,962		)
Other investing activities	—			(5		)	5
Net cash flows used in investing activities	(1,235		)	(1,851		)	(7,324		)
Cash flows from financing activities
Issuance of long-term debt	—			—			1,800
Proceeds from short-term borrowings with maturities greater than 90 days	—			500			—
Retirement of long-term debt	—			(569		)	(46		)
Common stock issued from treasury stock	—			1,150			—
Dividends paid on common stock	(1,332		)	(1,236		)	(1,166		)
Proceeds from employee stock plans	105			150			55
Other financing activities	(4		)	(9		)	(20		)
Net cash flows (used in) provided by financing activities	(1,231		)	(14		)	623
Increase (Decrease) in cash, cash equivalents and restricted cash	115			56			(5,672		)
Cash, cash equivalents and restricted cash at beginning of period	74			18			5,690
Cash, cash equivalents and restricted cash at end of period	$	189		$	74		$	18

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets



	December 31,
(In millions)	2018		2017
ASSETS
Current assets
Cash and cash equivalents	$	189	$	74
Accounts receivable, net
Other accounts receivable	48		431
Accounts receivable from affiliates	44		33
Notes receivable from affiliates	216		217
Regulatory assets	182		284
Other	4		4
Total current assets	683		1,043
Property, plant and equipment, net	48		50
Deferred debits and other assets
Regulatory assets	3,742		3,697
Investments in affiliates	40,448		39,311
Deferred income taxes	1,455		1,431
Notes receivable from affiliates	898		910
Other	235		234
Total deferred debits and other assets	46,778		45,583
Total assets	$	47,509	$	46,676

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets



	December 31,
(In millions)	2018			2017
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	500		$	500
Accounts payable	1			2
Accrued expenses	184			99
Payables to affiliates	360			360
Regulatory liabilities	15			16
Pension obligations	63			65
Other	14			46
Total current liabilities	1,137			1,088
Long-term debt	7,147			7,161
Deferred credits and other liabilities
Regulatory liabilities	32			15
Pension obligations	7,795			7,792
Non-pension postretirement benefit obligations	199			322
Deferred income taxes	233			220
Other	202			180
Total deferred credits and other liabilities	8,461			8,529
Total liabilities	16,745			16,778
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 968 shares and 963 shares outstanding at December 31, 2018 and 2017, respectively)	19,116			18,966
Treasury stock, at cost (2 shares at December 31, 2018 and 2017)	(123		)	(123		)
Retained earnings	14,766			14,081
Accumulated other comprehensive loss, net	(2,995		)	(3,026		)
Total shareholders’ equity	30,764			29,898
Total liabilities and shareholders’ equity	$	47,509		$	46,676

Basis of Presentation

Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. BGE redeemed all of its outstanding preferred stock in 2016.

Mergers

On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). See Note 5—Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the PHI Merger.

Debt and Credit Agreements

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper borrowings at both December 31, 2018 and December 31, 2017.

Short-Term Loan Agreements

On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement which expired on 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

On May 26, 2016, Exelon Corporate amended its syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2018, Exelon Corporation had available capacity under those commitments of $591 million. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2018 and December 31, 2017:



					Maturity Date	December 31,
	Rates				Maturity Date	2018			2017
Long-term debt
Junior subordinated notes			3.50	%	2022	$	1,150		$	1,150
Senior unsecured notes^(a)	2.45	%	7.60	%	2020 - 2046	5,889			5,889
Total long-term debt						7,039			7,039
Unamortized debt discount and premium, net						(7		)	(8		)
Unamortized debt issuance costs						(47		)	(49		)
Fair value adjustment of consolidated subsidiary						162			179
Long-term debt						$	7,147		$	7,161

__________


(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

The debt maturities for Exelon Corporate for the periods 2019, 2020, 2021, 2022, 2023 and thereafter are as follows:



2019	$	—
2020	1,450
2021	300
2022	1,150
2023	—
Remaining years	4,139
Total long-term debt	$	7,039

Commitments and Contingencies

See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.

Related Party Transactions

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:



	For the Years Ended December 31,
(In millions)	2018			2017			2016
Operating and maintenance from affiliates:
BSC^(a)	$	11		$	23		$	51
Other	(2		)	2			—
Total operating and maintenance from affiliates:	$	9		$	25		$	51
Interest income from affiliates, net:
Generation	$	36		$	37		$	39
BSC	4			3			—
Exelon Energy Delivery Company, LLC^(b)	$	2		$	—		$	—
Total interest income from affiliates, net:	$	42		$	40		$	39
Equity in earnings (losses) of investments:
Exelon Energy Delivery Company, LLC^(b)	$	1,835		$	1,670		$	1,041
PCI	(17		)	1			6
BSC	—			1			1
UII, LLC	—			41			(9		)
Exelon Transmission Company, LLC	1			(10		)	(13		)
Exelon Enterprise	—			1			(1		)
Generation	369			2,710			483
Total equity in earnings of investments:	$	2,188		$	4,414		$	1,508

Cash contributions received from affiliates	$	2,302		$	1,879		$	1,912



	December 31,
(in millions)	2018			2017
Accounts receivable from affiliates (current):
BSC^(a)	$	13		$	1
Generation	17			21
ComEd	4			3
PECO	2			1
BGE	2			1
PHISCO	6			6
Total accounts receivable from affiliates (current):	$	44		$	33
Notes receivable from affiliates (current):
BSC^(a)	$	116		$	217
Generation^(c)	100			—
Total notes receivable from affiliates (current):	$	216		$	217
Investments in affiliates:
BSC^(a)	$	197		$	196
Exelon Energy Delivery Company, LLC^(b)	26,702			25,082
PCI	61			78
UII, LLC	268			268
Exelon Transmission Company, LLC	1			1
Voluntary Employee Beneficiary Association trust	(1		)	(4		)
Exelon Enterprises	22			22
Generation	13,204			13,674
Other	(6		)	(6		)
Total investments in affiliates:	$	40,448		$	39,311
Notes receivable from affiliates (non-current):
Generation^(c)	$	898		$	910
Accounts payable to affiliates (current):
UII, LLC	$	360		$	360

__________


(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.


(b)	Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.

(c)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2018

Valuation and Qualifying Accounts

Exelon Corporation and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts				Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts^(a)	$	322	$	159	$	35		^(c)	$	197	^(e)	$	319
Deferred tax valuation allowance	37		—		5				7			35
Reserve for obsolete materials	174		25		(31		)	^(d)	12			156
For the year ended December 31, 2017
Allowance for uncollectible accounts^(a)	$	334	$	126	$	27		^(c)	$	165	^(e)	$	322
Deferred tax valuation allowance	20		—		17				—			37
Reserve for obsolete materials	113		56		10				5			174
For the year ended December 31, 2016
Allowance for uncollectible accounts^(a)	$	284	$	162	$	99		^(b)(c)	$	211	^(e)	$	334
Deferred tax valuation allowance	13		—		10			^(b)	3			20
Reserve for obsolete materials	105		12		1			^(b)	5			113

__________


(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, and $23 million for the years ended December 31, 2018, 2017 and 2016, respectively.


(b)	Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger


(c)	Includes charges for late payments and non-service receivables.


(d)	Primarily reflects the reclassification of assets as held for sale.


(e)	Write-off of individual accounts receivable.

Exelon Generation Company, LLC and Subsidiary Companies

(2) Generation



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Balance Sheets at December 31, 2018 and 2017

		Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Exelon Generation Company, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C						Column D		Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts				Deductions		Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts	$	114	$	44	$	4			$	58	$	104
Deferred tax valuation allowance	23		—		3				—		26
Reserve for obsolete materials	166		20		(32		)	^(a)	9		145
For the year ended December 31, 2017
Allowance for uncollectible accounts	$	91	$	34	$	—			$	11	$	114
Deferred tax valuation allowance	9		—		14				—		23
Reserve for obsolete materials	106		51		9				—		166
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	77	$	19	$	3			$	8	$	91
Deferred tax valuation allowance	11		—		—				2		9
Reserve for obsolete materials	102		6		—				2		106

__________


(a)	Primarily reflects the reclassification of assets as held for sale.

Commonwealth Edison Company and Subsidiary Companies

(3) ComEd



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Balance Sheets at December 31, 2018 and 2017

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts	$	73	$	44	$	23	^(a)	$	59	^(b)	$	81
Reserve for obsolete materials	5		3		1			3			6
For the year ended December 31, 2017
Allowance for uncollectible accounts	$	70	$	39	$	20	^(a)	$	56	^(b)	$	73
Reserve for obsolete materials	4		3		1			3			5
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	75	$	45	$	23	^(a)	$	73	^(b)	$	70
Reserve for obsolete materials	3		4		1			4			4

__________


(a)	Primarily charges for late payments and non-service receivables.


(b)	Write-off of individual accounts receivable.

PECO Energy Company and Subsidiary Companies

(4) PECO



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Balance Sheets at December 31, 2018 and 2017

		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts^(a)	$	56	$	33	$	3	^(b)	$	31	^(c)	$	61
Reserve for obsolete materials	2		—		—			—			2
For the year ended December 31, 2017
Allowance for uncollectible accounts^(a)	$	61	$	26	$	4	^(b)	$	35	^(c)	$	56
Reserve for obsolete materials	2		—		—			—			2
For the year ended December 31, 2016
Allowance for uncollectible accounts^(a)	$	83	$	32	$	7	^(b)	$	61	^(c)	$	61
Reserve for obsolete materials	1		1		—			—			2

__________


(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million, $15 million, and $23 million for the years ended December 31, 2018, 2017, and 2016, respectively.


(b)	Primarily charges for late payments.


(c)	Write-off of individual accounts receivable.

Baltimore Gas and Electric Company and Subsidiary Companies

(5) BGE



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Balance Sheets at December 31, 2018 and 2017

		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Baltimore Gas and Electric Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts	$	24	$	10	$	(2	)	$	12	^(a)	$	20
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	—		1		—			—			1
For the year ended December 31, 2017
Allowance for uncollectible accounts	$	32	$	8	$	(3	)	$	13	^(a)	$	24
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	—		—		—			—			—
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	49	$	1	$	9		$	27	^(a)	$	32
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	—		—		—			—			—

__________


(a)	Write-off of individual accounts receivable.

Pepco Holdings LLC and Subsidiary Companies

(6) PHI



(i)		Successor Company Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31, 2016

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31, 2016

		Consolidated Balance Sheets at December 31, 2018 and 2017

		Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31, 2016

		Notes to Consolidated Financial Statements

(ii)		Predecessor Company Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Period January 1, 2016 to March 23, 2016

		Consolidated Statements of Cash Flows for the Period January 1, 2016 to March 23, 2016

		Consolidated Statements of Changes in Equity for the Period January 1, 2016 to March 23, 2016

		Notes to Consolidated Financial Statements

(iii)		Successor Financial Statement Schedule:

		Schedule II – Valuation and Qualifying Accounts - For the Years Ended December 31, 2018 and 2017 and the Period March 24, 2016 to December 31, 2016

(iv)		Predecessor Financial Statement Schedule:

		Schedule II – Valuation and Qualifying Accounts - For the Period January 1, 2016 to March 23, 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Pepco Holdings LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C						Column D				Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts				Deductions				Balance at End of Period
	(in millions)
For the Year Ended December 31, 2018 (Successor)
Allowance for uncollectible accounts	$	55	$	28	$	7		^(a)	$	37		^(b)	$	53
Deferred tax valuation allowance	13		—		2				7				8
Reserve for obsolete materials	2		—		—				—				2
For the Year Ended December 31, 2017 (Successor)
Allowance for uncollectible accounts	$	80	$	19	$	6		^(a)	$	50		^(b)	$	55
Deferred tax valuation allowance	10		—		3				—				13
Reserve for obsolete materials	2		2		—				2				2
March 24, 2016 to December 31, 2016 (Successor)
Allowance for uncollectible accounts	$	52	$	65	$	5		^(a)	$	42		^(b)	$	80
Deferred tax valuation allowance	63		—		(53		)		—				10
Reserve for obsolete materials	—		1		—				(1		)		2
January 1, 2016 to March 23, 2016 (Predecessor)
Allowance for uncollectible accounts	$	56	$	16	$	2		^(a)	$	22		^(b)	$	52
Deferred tax valuation allowance	63		—		—				—				63
Reserve for obsolete materials	—		—		—				—				—

__________


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Potomac Electric Power Company

(7) Pepco



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016

		Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Balance Sheets at December 31, 2018 and 2017

		Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Potomac Electric Power Company

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts	$	21	$	11	$	3	^(a)	$	14	^(b)	$	21
Reserve for obsolete materials	1		—		—			—			1
For the year ended December 31, 2017
Allowance for uncollectible accounts	$	29	$	8	$	2	^(a)	$	18	^(b)	$	21
Reserve for obsolete materials	1		1		—			1			1
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	17	$	29	$	3	^(a)	$	20	^(b)	$	29
Reserve for obsolete materials	—		3		—			2			1

__________


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Delmarva Power & Light Company

(8) DPL



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 and 2016

		Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Balance Sheets at December 31, 2018 and 2017

		Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Delmarva Power & Light Company

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts	$	16	$	6	$	2	^(a)	$	11	^(b)	$	13
Reserve for obsolete materials	—		—		—			—			—
For the year ended December 31, 2017
Allowance for uncollectible accounts	$	24	$	3	$	2	^(a)	$	13	^(b)	$	16
Reserve for obsolete materials	—		1		—			1			—
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	17	$	23	$	2	^(a)	$	18	^(b)	$	24
Reserve for obsolete materials	—		1		—			1			—

__________


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Atlantic City Electric Company and Subsidiary Company

(9) ACE



(i)		Financial Statements (Item 8):

		Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016

		Consolidated Balance Sheets at December 31, 2018 and 2017

		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016

		Notes to Consolidated Financial Statements

(ii)		Financial Statement Schedule:

		Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Atlantic City Electric Company and Subsidiary Company

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2018
Allowance for uncollectible accounts	$	18	$	11	$	2	^(a)	$	12	^(b)	$	19
Reserve for obsolete materials	1		—		—			—			1
For the year ended December 31, 2017
Allowance for uncollectible accounts	$	27	$	8	$	2	^(a)	$	19	^(b)	$	18
Reserve for obsolete materials	1		—		—			—			1
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	17	$	32	$	2	^(a)	$	24	^(b)	$	27
Reserve for obsolete materials	—		1		—			—			1

__________


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

Accounting Policies [Abstract]

Description of Business (All Registrants)



Name of Registrant	Business	Service Territories
Exelon Generation Company, LLC	Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation, which sells electricity to both wholesale and retail customers. Generation also sells natural gas, renewable energy and other energy-related products and services.	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)

For financial statement purposes, beginning on March 24, 2016, disclosures related to Exelon also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.

Use Of Estimates (All Registrants)

Use of Estimates (All Registrants)

Reclassifications (Exelon, ComEd, and BGE)

Prior Period Adjustments and Reclassifications (All Registrants)

Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE)

Accounting for the Effects of Regulation (Exelon and the Utility Registrants)

Revenues (All Registrants)

Revenue, Transaction Price Measurement, Tax Exclusion [Policy Text Block]

Income Taxes (All Registrants)

Cash and Cash Equivalents (All Registrants)

The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents (All Registrants)



Registrant	Description
Exelon	Payment of medical, dental, vision and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants.
Generation	Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.
ComEd	Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance payments received from RES pursuant to FEJA and costs for the remediation of an MGP site.
PECO	Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
BGE	Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
PHI	Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts and repayment of transition bonds.
Pepco	Payment of merger commitments and collateral held from energy suppliers.
DPL	Collateral held from energy suppliers.
ACE	Repayment of transition bonds and collateral held from energy suppliers.

Allowance for Uncollectible Accounts (All Registrants)

Variable Interest Entities (All Registrants)

Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:


•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,


•	requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and


•	requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.

Inventories (All Registrants)

Marketable Securities (All Registrants)

Debt and Equity Security Investments (Exelon and Generation)

Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax, are reported in OCI.

Property Plant And Equipment (All Registrants)

Property, Plant and Equipment (All Registrants)

Nuclear Fuel (Exelon and Generation)

Nuclear Outage Costs (Exelon and Generation)

Depreciation, Depletion, and Amortization (All Registrants)

Depreciation and Amortization (All Registrants)

See Note 6 — Property, Plant and Equipment for additional information regarding depreciation.

Asset Retirement Obligations (All Registrants)

Guarantees (All Registrants)

Long-lived Assets (All Registrants)

Goodwill (All Registrants)

Equity Method Investments (All Registrants)

Derivatives Financial Instruments (All Registrants)

Derivative Financial Instruments (All Registrants)

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.

Investment, Policy [Policy Text Block]

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

Prior Period Adjustments and Reclassifications (All Registrants)

New Accounting Pronouncements, Policy [Policy Text Block]

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



														Successor
For the year ended December 31, 2017	Exelon			Generation		ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Operating Revenues - As reported
Competitive business revenues	$	17,360		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	16,171			—		—			—		—			—			—			—			—
Operating revenues	—			17,351		—			—		—			—			—			—			—
Electric operating revenues	—			—		5,521			2,369		2,484			4,468			2,152			1,131			1,184
Natural gas operating revenues	—			—		—			494		676			161			—			161			—
Operating revenues from affiliates	—			1,115		15			7		16			50			6			8			2
Total operating revenues	$	33,531		$	18,466	$	5,536		$	2,870	$	3,176		$	4,679		$	2,158		$	1,300		$	1,186

Operating Revenues - Adjustments
Competitive business revenues	$	34		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(207		)	—		—			—		—			—			—			—			—
Operating revenues	—			34		—			—		—			—			—			—			—
Electric operating revenues	—			—		(43		)	—		(100		)	(40		)	(26		)	(6		)	(8		)
Natural gas operating revenues	—			—		—			—		(24		)	—			—			—			—
Revenues from alternative revenue programs	207			—		43			—		124			40			26			6			8
Operating revenues from affiliates	—			—		—			—					—			—			—			—
Total operating revenues	$	34		$	34	$	—		$	—	$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	17,394		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	15,964			—		—			—		—			—			—			—			—
Operating revenues	—			17,385		—			—		—			—			—			—			—
Electric operating revenues	—			—		5,478			2,369		2,384			4,428			2,126			1,125			1,176
Natural gas operating revenues	—			—		—			494		652			161			—			161			—
Revenues from alternative revenue programs	207			—		43			—		124			40			26			6			8
Operating revenues from affiliates	—			1,115		15			7		16			50			6			8			2
Total operating revenues	$	33,565		$	18,500	$	5,536		$	2,870	$	3,176		$	4,679		$	2,158		$	1,300		$	1,186



																							Successor			Predecessor
																							March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon			Generation		ComEd			PECO		BGE			Pepco			DPL			ACE			PHI			PHI
Operating Revenues - As reported
Competitive business revenues	$	16,324		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	15,036			—		—			—		—			—			—			—			—			—
Operating revenues	—			16,312		—			—		—			—			—			—			—			—
Electric operating revenues	—			—		5,239			2,524		2,603			2,181			1,122			1,254			3,506			1,096
Natural gas operating revenues	—			—		—			462		609			—			148			—			92			57
Operating revenues from affiliates	—			1,439		15			8		21			5			7			3			45			—
Total operating revenues	$	31,360		$	17,751	$	5,254		$	2,994	$	3,233		$	2,186		$	1,277		$	1,257		$	3,643		$	1,153

Operating Revenues - Adjustments
Competitive business revenues	$	6		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	(48		)	—		—			—		—			—			—			—			—			—
Operating revenues	—			6		—			—		—			—			—			—			—			—
Electric operating revenues	—			—		24			—		(72		)	(14		)	6			(9		)	(43		)	26
Natural gas operating revenues	—			—		—			—		19			—			—			—			—			—
Revenues from alternative revenue programs	48			—		(24		)	—		53			14			(6		)	9			43			(26		)
Operating revenues from affiliates	—			—		—			—		—			—			—			—			—			—
Total operating revenues	$	6		$	6	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—

Operating Revenues - Retrospective application
Competitive business revenues	$	16,330		$	—	$	—		$	—	$	—		$	—		$	—		$	—		$	—		$	—
Rate-regulated utility revenues	14,988			—		—			—		—			—			—			—			—			—
Operating revenues	—			16,318		—			—		—			—			—			—			—			—
Electric operating revenues	—			—		5,263			2,524		2,531			2,167			1,128			1,245			3,463			1,122
Natural gas operating revenues	—			—		—			462		628			—			148			—			92			57
Revenues from alternative revenue programs	48			—		(24		)	—		53			14			(6		)	9			43			(26		)
Operating revenues from affiliates	—			1,439		15			8		21			5			7			3			45			—
Total operating revenues	$	31,366		$	17,757	$	5,254		$	2,994	$	3,233		$	2,186		$	1,277		$	1,257		$	3,643		$	1,153

The new standard provides a number of transition practical expedients, which the Registrants have elected, including:


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


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


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

The Registrants have assessed the lease standard and executed a detailed implementation plan in preparation for adoption, which included the following key activities:


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


•	Evaluated the transition practical expedients available under the standard.


•	Identified, assessed and documented technical accounting issues, policy considerations and financial reporting implications.


•	Identified and implemented changes to processes and controls to ensure all impacts of the new standard are effectively addressed.



	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
ROU Assets	$1,400-$1,500	$1,000-$1,100	$5-$10	$1-$5	$100-$120	$250-$270	$60-$65	$70-$75	$20-$25
Lease Liabilities	$1,600-$1,700	$1,200-$1,300	$5-$10	$1-$5	$100-$120	$300-$320	$60-$65	$75-$80	$20-$25

The impact of adopting the new standard on retained earnings as of January 1, 2019 is expected to be immaterial.

Earnings Per Share Earnings Per Share (Policies)	12 Months Ended
Earnings Per Share Earnings Per Share (Policies)	Dec. 31, 2018
Earnings Per Share [Abstract]
Earnings Per Share, Policy [Policy Text Block]	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.

Significant Accounting Policies (Tables)	12 Months Ended
Significant Accounting Policies (Tables)	Dec. 31, 2017	Dec. 31, 2016
Accounting Policies [Abstract]
Cumulative Effect of New Accounting Pronouncement Adoption Revenue from Contract with Customer [Table Text Block]	.	.

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2018

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at December 31, 2018 and 2017 are as follows:



	December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	938	$	931	$	7	4
Noncurrent assets	9,071		9,045		26		19
Total assets	$	10,009	$	9,976	$	33	$	23
Current liabilities	$	274	$	252	$	22	19
Noncurrent liabilities	3,280		3,233		47		40
Total liabilities	$	3,554	$	3,485	$	69	$	59



	December 31, 2017
	Exelon^(a)		Generation		PHI^(a)		ACE
Current assets	$	662	$	652	$	10	$	6
Noncurrent assets	9,317		9,286		31		23
Total assets	$	9,979	$	9,938	$	41	$	29
Current liabilities	$	308	$	272	$	36	$	32
Noncurrent liabilities	3,316		3,250		66		58
Total liabilities	$	3,624	$	3,522	$	102	$	90

__________


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

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



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



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 in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.

(b)

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



	December 31, 2018
	Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	414	$	414	$	—	$	—
Restricted cash and cash equivalents	66		62		4		4
Accounts receivable, net
Customer	146		146		—		—
Other	23		23		—		—
Inventory
Materials and supplies	212		212		—		—
Other current assets	52		49		3		—
Total current assets	913		906		7		4

Property, plant and equipment, net	6,145		6,145		—		—
Nuclear decommissioning trust funds	2,351		2,351		—		—
Other noncurrent assets	258		232		26		19
Total noncurrent assets	8,754		8,728		26		19
Total assets	$	9,667	$	9,634	$	33	$	23

Long-term debt due within one year	$	87	$	66	$	21	$	18
Accounts payable	96		96		—		—
Accrued expenses	72		72		1		1
Unamortized energy contract liabilities	15		15		—		—
Other current liabilities	3		3		—		—
Total current liabilities	273		252		22		19

Long-term debt	1,072		1,025		47		40
Asset retirement obligations	2,160		2,160		—		—
Unamortized energy contract liabilities	1		1		—		—
Other noncurrent liabilities	42		42		—		—
Total noncurrent liabilities	3,275		3,228		47		40
Total liabilities	$	3,548	$	3,480	$	69	$	59

__________


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



	December 31, 2017
	Exelon^(a)		Generation		PHI^(a)		ACE
Cash and cash equivalents	$	126	$	126	$	—	$	—
Restricted cash and cash equivalents	64		58		6		6
Accounts receivable, net
Customer	170		170		—		—
Other	25		25		—		—
Inventory
Materials and supplies	205		205		—		—
Other current assets	45		41		4		—
Total current assets	635		625		10		6

Property, plant and equipment, net	6,186		6,186		—		—
Nuclear decommissioning trust funds	2,502		2,502		—		—
Other noncurrent assets	274		243		31		23
Total noncurrent assets	8,962		8,931		31		23
Total assets	$	9,597	$	9,556	$	41	$	29

Long-term debt due within one year	$	102	$	67	$	35	$	31
Accounts payable	114		114		—		—
Accrued expenses	67		66		1		1
Unamortized energy contract liabilities	18		18		—		—
Other current liabilities	7		7		—		—
Total current liabilities	308		272		36		32

Long-term debt	1,154		1,088		66		58
Asset retirement obligations	2,035		2,035		—		—
Other noncurrent liabilities	121		121		—		—
Total noncurrent liabilities	3,310		3,244		66		58
Total liabilities	$	3,618	$	3,516	$	102	$	90

__________


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

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.

Revenue from Contract with Customer (All Registrants) [Abstract]

Revenue Recognition Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2018

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

he following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 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	50
Amounts reclassified to receivables	(146		)
Balance at December 31, 2018	$	187

The Utility Registrants do not have any contract assets.

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



Contract Liabilities	Exelon			Generation
Balance as of January 1, 2018	$	35		$	35
Increases as a result of additional cash received or due	179			465
Amounts recognized into revenues	(187		)	(458		)
Balance at December 31, 2018	$	27		$	42

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



	2019		2020		2021		2022		2023 and thereafter		Total
Exelon	$	631	$	329	$	119	$	47	$	138	$	1,264
Generation	631		329		119		47		138		1,264

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Public Utilities General Disclosures [Table Text Block]



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

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 Asset Impairments [Table Text Block]



	For the year ended December 31, 2017
Exelon	$	35
ComEd	3
BGE	5
PHI	27
Pepco	14
DPL	6
ACE	7



	PJM Receivable		PJM Payable		Regulatory Asset		Regulatory Liability
Exelon	$	220	$	176	$	136	$	221
Generation^(a)	—		41		—		—
ComEd	122		—		—		122
PECO	85		—		—		85
BGE	—		51		51		—
PHI	13		84		85		14
Pepco	—		84		84		—
DPL	10		—		—		10
ACE	3		—		1		4

__________


(a)

Schedule of Regulatory Assets

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of December 31, 2018 and December 31, 2017:



December 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	2,553	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and other postretirement benefits - Merger related	1,266		—		—		—		—		—		—		—
Deferred income taxes	414		—		404		—		10		10		—		—
AMI programs - Deployment Costs	202		—		—		113		89		50		39		—
AMI programs - Legacy Meters	328		136		24		48		120		90		30		—
AMI programs - Post-test year costs	32		—		—		32		—		—		—		—
Electric distribution formula rate annual reconciliations	158		158		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	81		81		—		—		—		—		—		—
Energy efficiency costs	472		472		—		—		—		—		—		—
Fair value of long-term debt	702		—		—		—		569		—		—		—
Fair value of PHI's unamortized energy contracts	561		—		—		—		561		—		—		—
Asset retirement obligations	118		79		22		16		1		1		—		—
MGP remediation costs	326		309		17		—		—		—		—		—
Renewable energy	249		249		—		—		—		—		—		—
Electric Energy and Natural Gas Costs	193		—		49		51		93		84		—		9
Transmission formula rate annual reconciliations	41		6		—		4		31		10		14		7
Energy efficiency and demand response programs	545		—		1		289		255		188		67		—
Merger integration costs	42		—		—		3		39		18		11		10
Under-recovered revenue decoupling	59		—		—		2		57		57		—		—
Securitized stranded costs	50		—		—		—		50		—		—		50
Removal costs	564		—		—		—		564		158		97		309
DC PLUG charge	159		—		—		—		159		159		—		—
Deferred storm costs	41		—		—		—		41		9		4		28
Other	303		110		24		17		162		79		28		13
Total regulatory assets	9,459		1,600		541		575		2,801		913		290		426
Less: current portion	1,222		293		81		177		489		270		59		40
Total noncurrent regulatory assets	$	8,237	$	1,307	$	460	$	398	$	2,312	$	643	$	231	$	386



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	2,455	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Pension and other postretirement benefits - Merger related	1,393		—		—		—		—		—		—		—
Deferred income taxes	306		—		297		—		9		9		—		—
AMI programs - Deployment costs	385		—		—		129		101		58		43		—
AMI programs - Legacy meters	223		155		36		53		134		100		34		—
AMI programs - Post-test year costs	32		—		—		32		—		—		—		—
Electric distribution formula rate annual reconciliations	186		186		—		—		—		—		—		—
Electric distribution formula rate significant one-time events	58		58		—		—		—		—		—		—
Energy efficiency costs	166		166		—		—		—		—		—		—
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		—		—		—		—		—
Renewable energy	258		256		—		—		2		—		1		1
Electric energy and natural gas costs	47		—		1		16		30		8		7		15
Transmission formula rate annual reconciliations	35		6		—		7		22		3		8		11
Energy efficiency and demand response programs	596		—		1		285		310		229		81		—
Merger integration costs	45		—		—		6		39		20		10		9
Under-recovered revenue decoupling	55		—		—		14		41		38		3		—
Securitized stranded costs	79		—		—		—		79		—		—		79
Removal costs	529		—		—		—		529		150		93		286
DC PLUG charge	190		—		—		—		190		190		—		—
Deferred storm costs	27		—		—		—		27		7		5		15
Other	311		106		31		15		165		79		29		14
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
Deferred income taxes	$	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		—
Electric Energy and Natural Gas Costs	111		47		60		—		4		—		1		3
Other	399		185		94		26		64		3		14		8
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

Schedule of Regulatory Liabilities



December 31, 2017	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	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		—
Electric Energy and Natural Gas Costs	111		47		60		—		4		—		1		3
Other	399		185		94		26		64		3		14		8
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



December 31, 2018	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Deferred income taxes	$	5,228	$	2,394	$	—	$	1,132	$	1,702	$	798	$	510	$	394
Nuclear decommissioning	2,606		2,217		389		—		—		—		—		—
Removal costs	1,547		1,368		—		52		127		20		107		—
Electric Energy and Natural Gas Costs	294		137		132		6		19		—		18		1
Other	528		227		75		79		100		11		30		25
Total regulatory liabilities	10,203		6,343		596		1,269		1,948		829		665		420
Less: current portion	644		293		175		77		84		7		59		18
Total noncurrent regulatory liabilities	$	9,559	$	6,050	$	421	$	1,192	$	1,864	$	822	$	606	$	402

Mergers, Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2016

Business Combinations [Abstract]

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

The following table summarizes the final 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 22-Commitments and Contingencies for additional information regarding SNF obligations to the DOE.

Business Combination, Separately Recognized Transactions [Table Text Block]

The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the merger date:



	Expected Payment Period			Successor
Description	Expected Payment Period	Exelon		PHI		Pepco		DPL		ACE
Rate credits	2016 - 2021	$	259	$	264	$	91	$	72	$	101
Energy efficiency	2016 - 2021	117		—		—		—		—
Charitable contributions	2016 - 2026	50		50		28		12		10
Delivery system modernization	Q2 2017	22		—		—		—		—
Green sustainability fund	Q2 2017	14		—		—		—		—
Workforce development	2016 - 2020	17		—		—		—		—
Other		29		6		1		5		—
Total commitments		$	508	$	320	$	120	$	89	$	111
Remaining commitments as of December 31, 2018		$	128	$	92	$	73	$	12	$	7

Business Acquisition, Pro Forma Information [Table Text Block]



	For the Years Ended December 31,
	2018	2017	2016
Operating Revenues	4,670	4,829	3,785
Net Income (Loss)	453	364	(66	)

Restructuring and Related Costs [Table Text Block]

For the periods ended December 31, 2018, 2017 and 2016, the Registrants have recognized costs to achieve the PHI merger as follows:



	For the Year Ended December 31,
Acquisition, Integration and Financing Costs^(a)	2018		2017			2016
Exelon	$	7	$	16		$	143
Generation	5		22			37
ComEd^(b)	—		1			(6		)
PECO	1		4			5
BGE^(b)	1		4			(1		)
Pepco^(b)	—		(6		)	28
DPL^(b)	—		(7		)	20
ACE^(b)	—		(6		)	19



	Successor							Predecessor
	For the Year Ended December 31,					March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Acquisition, Integration and Financing Costs^(a)	2018		2017			March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
PHI^(b)	$	—	$	(18	)	$	69	$	29

______________


(a)	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

(b)

For the year ended December 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:



Severance Benefits	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Severance costs^(a)	$	57	$	9	$	2	$	1	$	1	$	44	$	21	$	13	$	10


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations.

Business Acquisition, Pro Forma Information, Nonrecurring Adjustments [Table Text Block]



	Year Ended December 31,
	2016^(a)		2015^(b)
Total operating revenues	$	32,342	$	33,823
Net income attributable to common shareholders	1,562		2,618

Basic earnings per share	$	1.69	$	2.85
Diluted earnings per share	1.69		2.84

______________


(a)	The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31, 2016.


(b)	The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015.

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2018

Property, Plant and Equipment

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-90	$	53,090	$	49,506
Electric—generation	1-56	29,170		29,019
Gas—transportation and distribution	5-90	5,530		5,050
Common—electric and gas	5-75	1,627		1,447
Nuclear fuel ^(a)	1-8	5,957		6,420
Construction work in progress	N/A	3,377		2,825
Other property, plant and equipment ^(b)	1-50	858		999
Total property, plant and equipment		99,609		95,266
Less: accumulated depreciation ^(c)		22,902		21,064
Property, plant and equipment, net		$	76,707	$	74,202

__________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2018 and 2017, of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017. Includes land held for future use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $39 million, $19 million, $25 million, $61 million, $17 million and $28 million, respectively, at December 31, 2018.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively.

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—generation	1-56	$	29,170	$	29,019
Nuclear fuel ^(a)	1-8	5,957		6,420
Construction work in progress	N/A	997		838
Other property, plant and equipment ^(b)	1-8	63		57
Total property, plant and equipment		36,187		36,334
Less: accumulated depreciation ^(c)		12,206		11,428
Property, plant and equipment, net		$	23,981	$	24,906

__________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017, respectively.


(b)	Includes buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017, respectively. The original cost basis of the buildings was $47 million as of both December 31, 2018 and 2017, and total accumulated amortization was $42 million and $40 million, as of December 31, 2018 and 2017, respectively.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million and $3,159 million as of December 31, 2018 and 2017, respectively.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-80	$	25,991	$	24,423
Construction work in progress	N/A	705		517
Other property, plant and equipment ^{(a), (b)}	35-50	46		52
Total property, plant and equipment		26,742		24,992
Less: accumulated depreciation		4,684		4,269
Property, plant and equipment, net		$	22,058	$	20,723

__________


(a)	Includes buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017.


(b)	Represents land held for future use and non-utility property.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-65	$	8,359	$	7,975
Gas—transportation and distribution	5-70	2,694		2,504
Common—electric and gas	5-50	756		710
Construction work in progress	N/A	343		254
Other property, plant and equipment ^(a)	50	19		21
Total property, plant and equipment		12,171		11,464
Less: accumulated depreciation		3,561		3,411
Property, plant and equipment, net		$	8,610	$	8,053

__________


(a)	Represents land held for future use and non-utility property.

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-90	$	7,951	$	7,464
Gas—distribution	5-90	2,630		2,379
Common—electric and gas	5-40	860		771
Construction work in progress	N/A	410		367
Other property, plant and equipment ^(a)	20	25		26
Total property, plant and equipment		11,876		11,007
Less: accumulated depreciation		3,633		3,405
Property, plant and equipment, net		$	8,243	$	7,602

__________


(a)	Represents plant held for future use and non-utility property.

PHI

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-75	$	12,664	$	11,517
Gas—distribution	5-75	486		449
Common—electric and gas	5-75	126		82
Construction work in progress	N/A	912		835
Other property, plant and equipment ^(a)	3-43	99		102
Total property, plant and equipment		14,287		12,985
Less: accumulated depreciation		841		487
Property, plant and equipment, net		$	13,446	$	12,498

__________


(a)	Represents plant held for future use and non-utility property.

Pepco

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-75	$	9,217	$	8,646
Construction work in progress	N/A	536		473
Other property, plant and equipment^(a)	25-33	61		59
Total property, plant and equipment		9,814		9,178
Less: accumulated depreciation		3,354		3,177
Property, plant and equipment, net		$	6,460	$	6,001

__________


(a)	Represents plant held for future use and non-utility property.

DPL

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-70	$	4,195	$	3,875
Gas—distribution	5-75	651		614
Common—electric and gas	5-75	136		117
Construction work in progress	N/A	151		205
Other property, plant and equipment ^(a)	10-43	17		15
Total property, plant and equipment		5,150		4,826
Less: accumulated depreciation		1,329		1,247
Property, plant and equipment, net		$	3,821	$	3,579

__________


(a)	Represents plant held for future use and non-utility property.

ACE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017:



	Average Service Life (years)	2018		2017
Asset Category
Electric—transmission and distribution	5-60	$	3,866	$	3,607
Construction work in progress	N/A	209		138
Other property, plant and equipment ^(a)	13-15	28		27
Total property, plant and equipment		4,103		3,772
Less: accumulated depreciation		1,137		1,066
Property, plant and equipment, net		$	2,966	$	2,706

__________


(a)	Represents plant held for future use and non-utility property.

Property Plant And Equipment Average Service Life Percentage By Asset Category Table

Exelon

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.73	%	2.75	%	2.73	%
Electric—generation^(a)	5.37	%	4.36	%	5.94	%
Gas	2.07	%	2.10	%	2.17	%
Common—electric and gas	6.98	%	7.05	%	7.41	%

__________


(a)	See Note 8 — Early Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.

PECO

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.35	%	2.37	%	2.32	%
Gas	1.90	%	1.89	%	1.82	%
Common—electric and gas	5.44	%	5.47	%	5.11	%

BGE

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.61	%	2.58	%	2.56	%
Gas	2.36	%	2.33	%	2.45	%
Common—electric and gas	8.50	%	8.64	%	9.45	%

PHI

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.61	%	2.63	%	2.52	%
Gas	1.59	%	2.07	%	2.57	%
Common—electric and gas	6.30	%	6.50	%	8.12	%

DPL

The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.



Average Service Life Percentage by Asset Category	2018		2017		2016
Electric—transmission and distribution	2.77	%	2.75	%	2.49	%
Gas	1.59	%	2.07	%	2.57	%
Common—electric and gas	3.70	%	4.14	%	4.99	%

Schedule Of Capitalized Software

Capitalized Software Costs (All Registrants)

The following tables presents net unamortized capitalized software costs and amortization of capitalized software costs by year.



Net unamortized software costs	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2018	$	810	$	164	$	206	$	98	$	166	$	165	$	26	$	21	$	14
December 31, 2017	834		173		227		111		179		133		2		1		1



Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
2018	$	282	$	78	$	79	$	37	$	48	$	2	$	2	$	1
2017	270		73		73		39		46		—		—		—
2016	255		72		62		33		44		—		—		—



	Successor						Predecessor
PHI	For the year ended December 31, 2018		For the year ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Amortization of capitalized software costs	$	33	$	34	$	29	$	8

Schedule Of Capitalized Interest And AFUDC

Capitalized Interest and AFUDC (All Registrants)

The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:



		Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
2018	Total incurred interest^(a)	$	1,695	$	464	$	377	$	141	$	130	$	162	$	62	$	68
	Capitalized interest	31		31		—		—		—		—		—		—
	Credits to AFUDC debt and equity	109		—		30		12		24		34		4		4
2017	Total incurred interest^(a)	$	1,658	$	502	$	369	$	130	$	111	$	133	$	54	$	64
	Capitalized interest	63		63		—		—		—		—		—		—
	Credits to AFUDC debt and equity	108		—		20		12		22		34		10		9
2016	Total incurred interest^(a)	$	1,678	$	472	$	469	$	127	$	114	$	137	$	52	$	65
	Capitalized interest	108		107		—		—		—		—		—		—
	Credits to AFUDC debt and equity	98		—		22		11		30		29		7		9



	Successor						Predecessor
PHI	For the year ended December 31, 2018		For the year ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Total incurred interest^(a)	$	305	$	263	$	207	$	68
Credits to AFUDC debt and equity	44		54		35		10

__________


(a)	Includes interest expense to affiliates.

Early Plant Retirements Early Plant Retirements (Tables)

12 Months Ended

Dec. 31, 2018

Implications of Potential Early Plant Retirements [Abstract]

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

The total annual impact of these charges by year are summarized in the table below.



Income statement expense (pre-tax)	2018^(a)		2017^(b)		2016^(c)
Depreciation and Amortization
Accelerated depreciation^(d)	$	539	$	250	$	712
Accelerated nuclear fuel amortization	57		12		60
Operating and Maintenance
One-time charges^(e,f)	32		77		26
Change in ARO accretion, net of any contractual offset^(g)	—		—		2
Contractual offset for ARC depreciation^(g)	—		—		(86		)
Total	$	628	$	339	$	714

_________


(a)	Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.


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

(c)


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


(e)	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.


(f)	In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially recorded in June 2016.

(g)

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



	December 31, 2018
Asset Balances
Materials and supplies inventory	$	30
Fuel inventory	20
Completed plant, net	901
Construction work in progress	9
Liability Balances
Asset retirement obligation	(1		)



	December 31, 2018
Asset Balances
Materials and supplies inventory	$	45
Nuclear fuel inventory, net	118
Completed plant, net	538
Construction work in progress	44
Liability Balances
Asset retirement obligation	(395		)

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

Jointly Owned Electric Utility Plant (Tables)

12 Months Ended

Dec. 31, 2018

Public Utilities, Property, Plant and Equipment [Abstract]

Schedule of Jointly Owned Utility Plants



	Nuclear Generation												Fossil-Fuel Generation			Transmission				Other
	Quad Cities			Peach Bottom			Salem^(a)			Nine Mile Point Unit 2			Wyman			PA^(b)		NJ/ DE^(c)		Other^(d)
Operator	Generation			Generation			PSEG Nuclear			Generation			FP&L			First Energy		PSEG/ DPL		various
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	5.89		%	various		various		various
Exelon’s share at December 31, 2018:
Plant^(e)	$	1,131		$	1,451		$	648		$	910		$	4		$	28	$	103	$	15
Accumulated depreciation^(e)	587			523			227			126			3			16		53		13
Construction work in progress	13			15			44			56			—			1		—		—
Exelon’s share at December 31, 2017:
Plant^(e)	$	1,074		$	1,417		$	631		$	839		$	3		$	27	$	102	$	15
Accumulated depreciation^(e)	550			461			205			97			3			15		52		13
Construction work in progress	35			18			33			55			—			—		—		—

__________


(a)	Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2018 and 2017.


(b)	PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.


(c)	PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching substation.


(d)	Generation, DPL and ACE own a 44.24%, 11.91% and 4.83% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center.


(e)	Excludes asset retirement costs and general plant.

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2018

Schedule of Finite-Lived Intangible Assets

Schedule Of Goodwill

Exelon’s, ComEd’s and PHI's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2018 and 2017 were as follows:



	Balance at January 1, 2017		Impairment losses		Balance at December 31, 2017		Impairment losses		Balance at December 31, 2018
Exelon
Gross amount	$	8,660	$	—	$	8,660	$	—	$	8,660
Accumulated impairment loss	1,983		—		1,983		—		1,983
Carrying amount	6,677		—		6,677		—		6,677
ComEd^(a)
Gross amount	4,608		—		4,608		—		4,608
Accumulated impairment loss	1,983		—		1,983		—		1,983
Carrying amount	2,625		—		2,625		—		2,625
PHI^(b)
Gross amount	4,005		—		4,005		—		4,005
Carrying amount	4,005		—		4,005		—		4,005

__________


(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

^[1],[2]



	December 31, 2018									December 31, 2017
	Gross			Accumulated Amortization			Net			Gross			Accumulated Amortization			Net
Generation
Unamortized Energy Contracts^(b)	1,957			(1,588		)	369			1,938			(1,574		)	364
Customer Relationships	325			(162		)	163			305			(133		)	172
Trade Name	243			(171		)	72			243			(148		)	95
ComEd
Chicago Settlement Agreements^(c)	162			(148		)	14			162			(141		)	21
PHI
Unamortized Energy Contracts^(b)	(1,515		)	954			(561		)	(1,515		)	766			(749		)
Exelon Corporate
Software License^(a)	95			(34		)	61			95			(25		)	70
Exelon	$	1,267		$	(1,149	)	$	118		$	1,228		$	(1,255	)	$	(27	)

__________


(a)	On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.


(b)	Includes unamortized energy contract assets and liabilities in Exelon's, Generations and PHI's Consolidated Balance Sheets.


(c)	In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement.

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]

The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2018:



For the Years Ending December 31,	Exelon			Generation		ComEd		PHI
2019	$	(32	)	$	70	$	7	$	(119	)
2020	(20		)	78		7		(115		)
2021	(4		)	78		—		(92		)
2022	(23		)	56		—		(89		)
2023	(21		)	50		—		(81		)

Schedule Of Finite-Lived Intangible Assets Amortization Expense

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2018, 2017 and 2016:



For the Years Ended December 31,	Exelon ^(a)(b)			Generation ^(a)		ComEd		PHI^(b)
2018	$	(109	)	$	63	$	7	$	(188	)
2017	(237		)	83		7		(336		)
2016	(336		)	79		7		(430		)

__________


(a)	At Exelon and Generation, amortization of unamortized energy contracts totaling $14 million, $35 million and $35 million for the years ended December 31, 2018, 2017 and 2016, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income

Schedule of Alternative or Renewable Energy Credits [Table Text Block]

The following table summarizes the current and noncurrent Renewable and Alternative Energy Credits as of December 31, 2018 and 2017:



	As of December 31, 2018
	Exelon		Generation		PECO		PHI		DPL		ACE
Current AEC's	$	2	$	—	$	2	$	—	$	—	$	—
Current REC's	279		270		—		9		8		1
Noncurrent REC's	52		52		—		—		—		—
	As of December 31, 2017
	Exelon		Generation		PECO		PHI		DPL		ACE
Current AEC's	$	1	$	—	$	1	$	—	$	—	$	—
Current REC's	321		312		—		9		8		1
Noncurrent REC's	27		27		—		—		—		—

[1]	(b)Reflects goodwill recorded in 2016 from the PHI merger.
[2]	Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2018

Fair Value Disclosures [Abstract]

Fair value of financial liabilities recorded at the carrying amount

Exelon



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



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

Generation



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



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

ComEd



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



	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)^(a)	$	7,601	$	—	$	8,418	$	—	$	8,418
Long-term debt to financing trusts^(b)	205		—		—		227		227

PECO



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



	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)^(a)	$	2,903	$	—	$	3,194	$	—	$	3,194
Long-term debt to financing trusts	184		—		—		204		204

BGE



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



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

PHI



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



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

Pepco



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



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

DPL



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



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

ACE



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



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

__________

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



	Generation										Exelon
As of December 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	581	$	—	$	—	$	—	$	581	$	1,243	$	—	$	—	$	—	$	1,243
NDT fund investments
Cash equivalents^(b)	252		86		—		—		338		252		86		—		—		338
Equities	2,918		1,591		—		1,381		5,890		2,918		1,591		—		1,381		5,890
Fixed income
Corporate debt	—		1,593		230		—		1,823		—		1,593		230		—		1,823
U.S. Treasury and agencies	2,081		99		—		—		2,180		2,081		99		—		—		2,180
Foreign governments	—		50		—		—		50		—		50		—		—		50
State and municipal debt	—		149		—		—		149		—		149		—		—		149
Other^(c)	—		30		—		846		876		—		30		—		846		876
Fixed income subtotal	2,081		1,921		230		846		5,078		2,081		1,921		230		846		5,078
Middle market lending	—		—		313		367		680		—		—		313		367		680
Private equity	—		—		—		329		329		—		—		—		329		329
Real estate	—		—		—		510		510		—		—		—		510		510
NDT fund investments subtotal^(d)	5,251		3,598		543		3,433		12,825		5,251		3,598		543		3,433		12,825



	Generation									Exelon
As of December 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
Pledged assets for Zion Station decommissioning
Cash equivalents	9		—		—		—	9		9		—		—		—	9
Equities	—		—		—		—	—		—		—		—		—	—
Middle market lending	—		—		—		—	—		—		—		—		—	—
Pledged assets for Zion Station decommissioning subtotal	9		—		—		—	9		9		—		—		—	9
Rabbi trust investments
Cash equivalents	5		—		—		—	5		48		—		—		—	48
Mutual funds	24		—		—		—	24		72		—		—		—	72
Fixed income	—		—		—		—	—		—		15		—		—	15
Life insurance contracts	—		22		—		—	22		—		70		38		—	108
Rabbi trust investments subtotal^(f)	29		22		—		—	51		120		85		38		—	243
Commodity derivative assets
Economic hedges	541		2,760		1,470		—	4,771		541		2,760		1,470		—	4,771
Proprietary trading	—		69		77		—	146		—		69		77		—	146
Effect of netting and allocation of collateral^(e)	(582	)	(2,357	)	(732	)	—	(3,671	)	(582	)	(2,357	)	(732	)	—	(3,671	)
Commodity derivative assets subtotal	(41	)	472		815		—	1,246		(41	)	472		815		—	1,246
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—		—		—		—	—		—		—		—		—	—
Economic hedges	—		13		—		—	13		—		13		—		—	13
Effect of netting and allocation of collateral	—		(3	)	—		—	(3	)	—		(3	)	—		—	(3	)
Interest rate and foreign currency derivative assets subtotal	—		10		—		—	10		—		10		—		—	10
Other investments	—		—		42		—	42		—		—		42		—	42
Total assets	5,829		4,102		1,400		3,433	14,764		6,582		4,165		1,438		3,433	15,618



	Generation														Exelon
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)	(2,963		)	(1,027		)	—		(4,632		)	(642		)	(2,963		)	(1,276		)	—		(4,881		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(e)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(240		)	—		(698		)	(3		)	(455		)	(489		)	—		(947		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(4		)	—			—		(4		)
Economic hedges	—			(6		)	—			—		(6		)	—			(6		)	—			—		(6		)
Effect of netting and allocation of collateral	—			3			—			—		3			—			3			—			—		3
Interest rate and foreign currency derivative liabilities subtotal	—			(3		)	—			—		(3		)	—			(7		)	—			—		(7		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(137		)	—			—		(137		)
Total liabilities	(3		)	(493		)	(240		)	—		(736		)	(3		)	(599		)	(489		)	—		(1,091		)
Total net assets	$	5,826		$	3,609		$	1,160		$	3,433	$	14,028		$	6,579		$	3,566		$	949		$	3,433	$	14,527



	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



	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
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	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^(e)	(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
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



	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
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^(e)	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 $50 million and $77 million of cash received from outstanding repurchase agreements at December 31, 2018 and 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 less than $1 million at December 31, 2018 and 2017. 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 years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017, respectively.

(g)

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



	Generation										Exelon
As of December 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents^(a)	$	581	$	—	$	—	$	—	$	581	$	1,243	$	—	$	—	$	—	$	1,243
NDT fund investments
Cash equivalents^(b)	252		86		—		—		338		252		86		—		—		338
Equities	2,918		1,591		—		1,381		5,890		2,918		1,591		—		1,381		5,890
Fixed income
Corporate debt	—		1,593		230		—		1,823		—		1,593		230		—		1,823
U.S. Treasury and agencies	2,081		99		—		—		2,180		2,081		99		—		—		2,180
Foreign governments	—		50		—		—		50		—		50		—		—		50
State and municipal debt	—		149		—		—		149		—		149		—		—		149
Other^(c)	—		30		—		846		876		—		30		—		846		876
Fixed income subtotal	2,081		1,921		230		846		5,078		2,081		1,921		230		846		5,078
Middle market lending	—		—		313		367		680		—		—		313		367		680
Private equity	—		—		—		329		329		—		—		—		329		329
Real estate	—		—		—		510		510		—		—		—		510		510
NDT fund investments subtotal^(d)	5,251		3,598		543		3,433		12,825		5,251		3,598		543		3,433		12,825



	Generation									Exelon
As of December 31, 2018	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
Pledged assets for Zion Station decommissioning
Cash equivalents	9		—		—		—	9		9		—		—		—	9
Equities	—		—		—		—	—		—		—		—		—	—
Middle market lending	—		—		—		—	—		—		—		—		—	—
Pledged assets for Zion Station decommissioning subtotal	9		—		—		—	9		9		—		—		—	9
Rabbi trust investments
Cash equivalents	5		—		—		—	5		48		—		—		—	48
Mutual funds	24		—		—		—	24		72		—		—		—	72
Fixed income	—		—		—		—	—		—		15		—		—	15
Life insurance contracts	—		22		—		—	22		—		70		38		—	108
Rabbi trust investments subtotal^(f)	29		22		—		—	51		120		85		38		—	243
Commodity derivative assets
Economic hedges	541		2,760		1,470		—	4,771		541		2,760		1,470		—	4,771
Proprietary trading	—		69		77		—	146		—		69		77		—	146
Effect of netting and allocation of collateral^(e)	(582	)	(2,357	)	(732	)	—	(3,671	)	(582	)	(2,357	)	(732	)	—	(3,671	)
Commodity derivative assets subtotal	(41	)	472		815		—	1,246		(41	)	472		815		—	1,246
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—		—		—		—	—		—		—		—		—	—
Economic hedges	—		13		—		—	13		—		13		—		—	13
Effect of netting and allocation of collateral	—		(3	)	—		—	(3	)	—		(3	)	—		—	(3	)
Interest rate and foreign currency derivative assets subtotal	—		10		—		—	10		—		10		—		—	10
Other investments	—		—		42		—	42		—		—		42		—	42
Total assets	5,829		4,102		1,400		3,433	14,764		6,582		4,165		1,438		3,433	15,618



	Generation														Exelon
As of December 31, 2018	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Liabilities
Commodity derivative liabilities
Economic hedges	(642		)	(2,963		)	(1,027		)	—		(4,632		)	(642		)	(2,963		)	(1,276		)	—		(4,881		)
Proprietary trading	—			(73		)	(21		)	—		(94		)	—			(73		)	(21		)	—		(94		)
Effect of netting and allocation of collateral^(e)	639			2,581			808			—		4,028			639			2,581			808			—		4,028
Commodity derivative liabilities subtotal	(3		)	(455		)	(240		)	—		(698		)	(3		)	(455		)	(489		)	—		(947		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			—			—			—		—			—			(4		)	—			—		(4		)
Economic hedges	—			(6		)	—			—		(6		)	—			(6		)	—			—		(6		)
Effect of netting and allocation of collateral	—			3			—			—		3			—			3			—			—		3
Interest rate and foreign currency derivative liabilities subtotal	—			(3		)	—			—		(3		)	—			(7		)	—			—		(7		)
Deferred compensation obligation	—			(35		)	—			—		(35		)	—			(137		)	—			—		(137		)
Total liabilities	(3		)	(493		)	(240		)	—		(736		)	(3		)	(599		)	(489		)	—		(1,091		)
Total net assets	$	5,826		$	3,609		$	1,160		$	3,433	$	14,028		$	6,579		$	3,566		$	949		$	3,433	$	14,527



	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



	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
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	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^(e)	(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
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



	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
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^(e)	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 $50 million and $77 million of cash received from outstanding repurchase agreements at December 31, 2018 and 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 less than $1 million at December 31, 2018 and 2017. 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 years ended December 31, 2018 and 2017, respectively. The amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017, respectively.

(g)

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Text Block]

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2018 and 2017:



	Generation																ComEd				PHI					Exelon
For the year ended December 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 January 1, 2018	$	648		$	12		$	552			$	37		$	1,249		$	(256	)		$	22	$	—		$	1,015
Total realized / unrealized gains (losses)
Included in net income	—			—			(105		)	^(a)	3			(102		)	—				4		—			(98		)
Included in noncurrent payables to affiliates	(1		)	—			—				—			(1		)	—				—		1			—
Included in payable for Zion Station decommissioning	—			7			—				—			7			—				—		—			7
Included in regulatory assets/liabilities	—			—			—				—			—			7			^(b)	—		(1		)	6
Change in collateral	—			—			(5		)		—			(5		)	—				—		—			(5		)
Purchases, sales, issuances and settlements
Purchases	36			1			190			^(e)	4			231			—				—		—			231
Sales	—			(20		)	(4		)		—			(24		)	—				—		—			(24		)
Issuances	—			—			—				—			—			—				—		—			—
Settlements	(140		)	—			5				—			(135		)	—				12		—			(123		)
Transfers into Level 3	—			—			(22		)	^(d)	—			(22		)	—				—		—			(22		)
Transfers out of Level 3	—			—			(36		)	^(d)	(2		)	(38		)	—				—		—			(38		)
Other miscellaneous	—			—			—							—			—				—		—			—
Balance as of December 31, 2018	$	543		$	—		$	575			$	42		$	1,160		$	(249	)		$	38	$	—		$	949
The amount of total (losses) gains included in income attributed to the change in unrealized (losses) gains related to assets and liabilities held as of December 31, 2018	$	(5	)	$	—		$	165			$	3		$	163		$	—			$	—	$	—		$	163



	Generation																ComEd				PHI						Exelon
For the year ended December 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 January 1, 2017	$	677		$	19		$	493			$	42		$	1,231		$	(258	)		$	20		$	—		$	993
Total realized / unrealized gains (losses)
Included in net income	3			—			(90		)	^(a)	3			(84		)	—				3			—			(81		)
Included in noncurrent payables to affiliates	6			—			—				—			6			—				—			(6		)	—
Included in payable for Zion Station decommissioning	—			(8		)	—				—			(8		)	—							—			(8		)
Included in regulatory assets/liabilities	—			—			—				—			—			2			^(b)	—			6			8
Change in collateral	—			—			20				—			20			—				—			—			20
Purchases, sales, issuances and settlements
Purchases	64			1			178				5			248			—				—			—			248
Sales	—			—			(16		)		—			(16		)	—				—			—			(16		)
Issuances	—			—			—				—			—			—				(1		)	—			(1		)
Settlements	(102		)	—			(8		)		—			(110		)	—				—			—			(110		)
Transfers into Level 3	—			—			(6		)	^(d)	—			(6		)	—				—			—			(6		)
Transfers out of Level 3	—			—			(50		)	^(d)	(11		)	(61		)	—				—			—			(61		)
Other miscellaneous	$	—		$	—		$	31			$	(2	)	$	29		$	—			$	—		$	—		$	29
Balance as of December 31, 2017	$	648		$	12		$	552			$	37		$	1,249		$	(256	)		$	22		$	—		$	1,015
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2017	$	1		$	—		$	254			$	3		$	258		$	—			$	3		$	—		$	261

__________


(a)	Includes a reduction for the reclassification of $265 million and $352 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2018 and 2017, respectively.

(b)


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


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


(e)	Includes $(19) million of fair value from contracts acquired as a result of the Everett Marine Terminal acquisition

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

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 years ended December 31, 2018 and 2017:



	Generation									PHI		Exelon
	Operating Revenues			Purchased Power and Fuel			Other, net			Operating and Maintenance		Operating Revenues			Purchased Power and Fuel			Operating and Maintenance		Other, net
Total (losses) gains included in net income for the year ended December 31, 2018	$	(7	)	$	(93	)	$	3		$	4	$	(7	)	$	(93	)	$	4	$	3
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2018	144			21			(2		)	—		144			21			—		(2		)



	Generation							PHI		Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net		Operating and Maintenance		Operating Revenues		Purchased Power and Fuel			Operating and Maintenance		Other, net
Total gains (losses) included in net income for the year ended December 31, 2017	$	28	$	(126	)	$	6	$	3	$	28	$	(126	)	$	3	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2017	290		(36		)	4		3		290		(36		)	3		4

Val

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

December 31, 2018:



	Generation										Exelon Corporate			Exelon
Description		Economic Hedges			Collateral and Netting^(a)			Subtotal			Economic Hedges			Total
Mark-to-market derivative assets (current assets)		$	5		$	(2	)	$	3		$	—		$	3
Mark-to-market derivative assets (noncurrent assets)		8			(1		)	7			—			7
Total mark-to-market derivative assets		13			(3		)	10			—			10
Mark-to-market derivative liabilities (current liabilities)		(4		)	2			(2		)	—			(2		)
Mark-to-market derivative liabilities (noncurrent liabilities)		(2		)	1			(1		)	(4		)	(5		)
Total mark-to-market derivative liabilities		(6		)	3			(3		)	(4		)	(7		)
Total mark-to-market derivative net assets (liabilities)		$	7		$	—		$	7		$	(4	)	$	3

__________

(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)

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 derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2018:



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

__________

(a)


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


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


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

The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31, 2017:



	Generation												ComEd			Exelon
Description	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)(d)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,061		$	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		)	(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		)	(637		)
Total mark-to-market derivative net assets (liabilities)	$	442		$	15		$	466		$	923		$	(256	)	$	667

__________

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

Derivative Instruments, Gain (Loss)



		For the Years Ended December 31,
		2018			2017			2016
	Income Statement Location	Gain (Loss)
Generation	Operating Revenues	$	7		$	(6	)	$	(10	)
Generation	Purchased Power and Fuel	(9		)	—			—
Generation	Interest Expense	(7		)	(3		)	—
Total Generation		$	(9	)	$	(9	)	$	(10	)



		For the Years Ended December 31,
		2018			2017			2016
	Income Statement Location	Gain (Loss)
Exelon	Operating Revenues	$	7		$	(6	)	$	(10	)
Exelon	Purchased Power and Fuel	(9		)	—			—
Exelon	Interest Expense	(4		)	(3		)	—
Total Exelon		$	(6	)	$	(9	)	$	(10	)

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:



		Year Ended December 31,
	Income Statement Location	2018			2017			2016			2018		2017		2016
	Income Statement Location	Loss on Swaps									Gain on Borrowings
Exelon	Interest expense	$	(11	)	$	(13	)	$	(9	)	$	20	$	28	$	23

For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows.



	For the Years Ended December 31,
	2018			2017			2016
Income Statement Location	Gain (Loss)
Operating revenues	$	(270	)	$	(126	)	$	(490	)
Purchased power and fuel	(47		)	(43		)	459
Total Exelon and Generation	$	(317	)	$	(169	)	$	(31	)

The activity of accumulated OCI related to cash flow hedges



		Total Cash Flow Hedge AOCI Activity, Net of Income Tax
		Generation			Exelon
For the Year Ended December 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		11			11
Reclassifications from AOCI to net income	Interest expense	1			1
AOCI derivative loss at December 31, 2018		$	(4	)	$	(2	)



		Total Cash Flow Hedge AOCI Activity, Net of Income Tax
		Generation				Exelon
For the Year Ended December 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		(1		)		(1		)
Reclassifications from AOCI to net income	Interest expense	4			^(a)	4			^(a)
AOCI derivative loss at December 31, 2017		$	(16	)		$	(14	)

__________


(a)	Amount is net of related income tax expense of $1 million for the year ended December 31, 2017.

Change in fair value of derivative contracts

For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses).



	For the Years Ended December 31,
	2018		2017			2016
Income Statement Location	Loss
Operating revenues	$	—	$	(1	)	$	(1	)

For the years ended December 31, 2018, 2017 and 2016, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.



	For the Years Ended December 31,
	2018		2017		2016
Income Statement Location	Gain
Operating revenues	$	17	$	6	$	2

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

The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2018 related to interest rate swaps and foreign currency exchange rate swaps.



	Generation		Exelon Corporate		Exelon
Foreign currency exchange rate swaps	$	268	$	—	$	268
Interest rate swaps	620		800		1,420
Total	$	888	$	800	$	1,688

The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 related to interest rate swaps and foreign currency exchange rate swaps.



	Generation		Exelon Corporate		Exelon
Foreign currency exchange rate swaps	$	94	$	—	$	94
Interest rate swaps^(a)	1		—		1
Total	$	95	$	—	$	95

__________


(a)	On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017.

Disclosure of Credit Derivatives [Table Text Block]

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 $43 million, $30 million, $24 million, $28 million, $7 million and $5 million as of December 31, 2018, respectively.



Rating as of December 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	$	795	$	—	$	795	1	$	153
Non-investment grade	133		45		88		—	—
No external ratings
Internally rated — investment grade	181		1		180		—	—
Internally rated — non-investment grade	92		6		86		—	—
Total	$	1,201	$	52	$	1,149	1	$	153



Net Credit Exposure by Type of Counterparty	December 31, 2018
Financial institutions	$	12
Investor-owned utilities, marketers, power producers	737
Energy cooperatives and municipalities	324
Other	76
Total	$	1,149

__________


(a)	As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 million of letters of credit. The credit collateral does not include non-liquid collateral.

Fair Value, Concentration of Risk [Table Text Block]



	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2018			2017
Gross fair value of derivative contracts containing this feature^(a)	$	(1,723	)	$	(926	)
Offsetting fair value of in-the-money contracts under master netting arrangements^(b)	1,105			577
Net fair value of derivative contracts containing this feature^(c)	$	(618	)	$	(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.

Tabular disclosure of credit derivatives which includes information by sellers of credit derivatives, about each credit derivative, or each group of similar credit derivatives, including (a) the nature of the credit derivative - its term, how it arose, the events or circumstances that would require the seller to perform under the credit derivative, and the current status of the payment/performance risk of the credit derivative; (b) the maximum potential amount of future payments (undiscounted) the seller could be required to make under the credit derivative; (c) the current fair value of the credit derivative; and (d) the nature of any recourse provisions under the credit derivative, and any assets held either as collateral or by third parties. A credit derivative is a derivative instrument (1) in which one or more of its underlyings are related to the credit risk of a specified entity (or a group of entities) or an index based on the credit risk of a group of entities and (2) that exposes the seller to potential loss from credit-risk-related events specified in the contract. Examples of credit derivatives within the scope of this paragraph include, but are not limited to, credit default swaps, credit spread options, and credit index products; also includes a hybrid instrument that has an embedded credit derivative (for example, but not limited to, a credit-linked note).

Tabular disclosure of all significant concentrations of risk, including credit risk and market risk, arising from all financial instruments (as defined), whether from an individual counterparty or groups of counterparties. The disclosure concerning concentrations of risk may consist of the following information: (1) for concentrations of credit risk disclosure may include: (a) information about the (shared) activity, region, or economic characteristic that identifies the concentration, (b) the maximum amount of loss due to credit risk that, based on the gross fair value of the financial instrument, the entity would incur if parties to the financial instruments that make up the concentration failed completely to perform according to the terms of the contracts and the collateral or other security, if any, for the amount due proved to be of no value to the entity, (c) the policy of requiring collateral or other security to support financial instruments subject to credit risk, information about the entity's access to that collateral or other security, and the nature and a brief description of the collateral or other security supporting those financial instruments, and (d) the policy of entering into master netting arrangements to mitigate the credit risk of financial instruments, information about the arrangements for which the entity is a party, and a brief description of the terms of those arrangements, including the extent to which they would reduce the entity's maximum amount of loss due to credit risk and (2) for disclosure of quantitative information about the market risks of financial instruments that is consistent with the way the company manages or adjusts those risks, disclosure may include: (a) more details about current positions and perhaps activity during the period, (b) the hypothetical effects on comprehensive income (or net assets), or annual income, of several possible changes in market prices, (c) a gap analysis of interest rate re-pricing or maturity dates, (d) the duration of the financial instruments, (e) the entity's value at risk from derivatives and from other positions at the end of the reporting period and the average value at risk during the year, or (f) other ways of reporting quantitative information as internally developed.

Schedule of Short-term Debt

Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2018 and 2017:



	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer	2018^(a)(b)(c)		2017^(a)(b)(c)		2018		2017		2018		2017
Exelon Corporate	$	600	$	600	$	—	$	—	1.93	%	1.16	%
Generation	5,300		5,300		—		—		1.96	%	1.23	%
ComEd	1,000		1,000		—		—		2.14	%	1.24	%
PECO	600		600		—		—		2.24	%	1.13	%
BGE	600		600		35		77		2.18	%	1.28	%
Pepco	300		500		40		26		2.24	%	1.06	%
DPL	300		500		—		216		2.07	%	1.48	%
ACE	300		350		14		108		2.21	%	1.43	%
Total	$	9,000	$	9,450	$	89	$	427

__________


(a)	Excludes $545 million and $480 million in bilateral credit facilities at December 31, 2018 and 2017, respectively, and $159 million and $179 million in credit facilities for project finance at December 31, 2018 and 2017, respectively. These credit facilities do not back Generation's commercial paper program.

(b)

(c)

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2018, 2017 and 2016.



Exelon
	2018			2017			2016
Average borrowings	$	531		$	823		$	1,125
Maximum borrowings outstanding	1,237			2,147			3,076
Average interest rates, computed on a daily basis	2.21		%	1.32		%	0.88		%
Average interest rates, at December 31	2.15		%	1.24		%	1.12		%

Generation
	2018			2017			2016
Average borrowings	$	37		$	405		$	536
Maximum borrowings outstanding	583			1,455			1,735
Average interest rates, computed on a daily basis	1.96		%	1.23		%	0.94		%
Average interest rates, at December 31	1.96		%	1.23		%	1.14		%



ComEd
	2018			2017			2016
Average borrowings	$	154		$	200		$	256
Maximum borrowings outstanding	520			470			755
Average interest rates, computed on a daily basis	2.14		%	1.24		%	0.77		%
Average interest rates, at December 31	2.14		%	1.24		%	N/A

PECO
	2018			2017			2016
Average borrowings	$	68		$	2		$	—
Maximum borrowings outstanding	350			60			—
Average interest rates, computed on a daily basis	2.24		%	1.13		%	N/A
Average interest rates, at December 31	2.24		%	1.13		%	N/A

BGE
	2018			2017			2016
Average borrowings	$	65		$	54		$	143
Maximum borrowings outstanding	239			165			369
Average interest rates, computed on a daily basis	2.18		%	1.28		%	0.77		%
Average interest rates, computed at December 31	2.18		%	1.28		%	0.95		%



PHI Corporate
	2018			2017			2016
Average borrowings	N/A			N/A			$	153
Maximum borrowings outstanding	N/A			N/A			559
Average interest rates, computed on a daily basis	N/A			N/A			1.03		%
Average interest rates, computed at December 31	N/A			N/A			N/A

Pepco
	2018			2017			2016
Average borrowings	$	22		$	51		$	4
Maximum borrowings outstanding	90			197			73
Average interest rates, computed on a daily basis	2.24		%	1.06		%	0.71		%
Average interest rates, computed at December 31	2.24		%	1.06		%	0.90		%

DPL
	2018			2017			2016
Average borrowings	$	87		$	40		$	33
Maximum borrowings outstanding	245			216			116
Average interest rates, computed on a daily basis	2.07		%	1.48		%	0.68		%
Average interest rates, computed at December 31	2.07		%	1.48		%	N/A

ACE
	2018			2017			2016
Average borrowings	$	95		$	30		$	—
Maximum borrowings outstanding	210			133			5
Average interest rates, computed on a daily basis	2.21		%	1.43		%	0.65		%
Average interest rates, computed at December 31	2.21		%	1.43		%	N/A

Schedule of Line of Credit Facilities

At December 31, 2018, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:



								Available Capacity at December 31, 2018
Borrower	Facility Type	Aggregate Bank Commitment^(a)		Facility Draws		Outstanding Letters of Credit		Actual		To Support Additional Commercial Paper^(b)
Exelon Corporate	Syndicated Revolver	$	600	$	—	$	9	$	591	$	591
Generation	Syndicated Revolver	5,300		—		1,203		4,097		4,097
Generation	Bilaterals	545		—		353		192		—
Generation	Project Finance	159		—		119		40		—
ComEd	Syndicated Revolver	1,000		—		2		998		998
PECO	Syndicated Revolver	600		—		—		600		600
BGE	Syndicated Revolver	600		—		1		599		564
Pepco	Syndicated Revolver	300		—		8		292		252
DPL	Syndicated Revolver	300		—		1		299		299
ACE	Syndicated Revolver	300		—		—		300		286
Total		$	9,704	$	—	$	1,696	$	8,008	$	7,687

__________

(a)

Schedule Of Credit Agreement Covenants

The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2018:

Exelon

Generation

ComEd

PECO

BGE

Pepco

DPL

ACE

Credit agreement threshold

2.50 to 1

3.00 to 1

2.00 to 1

At December 31, 2018, the interest coverage ratios at the Registrants were as follows:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Interest coverage ratio	7.34	10.99	7.34	8.14	9.77	5.98	7.03	5.06

Schedule of Long-term Debt Instruments



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.70	%	-	5.95	%	2021 - 2048	$	3,075		$	2,925
Loan Agreement				2.00	%	2023	50			0
Total long-term debt							3,125			2,925
Unamortized debt discount and premium, net							(18		)	(5		)
Unamortized debt issuance costs							(23		)	(17		)
Long-term debt due within one year							—			(500		)
Long-term debt							$	3,084		$	2,403
Long-term debt to financing trusts^(b)
Subordinated debentures to PECO Trust III	7.38	%	-	7.50	%	2028	$	81		$	81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103			103
Long-term debt to financing trusts							$	184		$	184

__________


(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.


(b)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

BGE



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	3.38	%	-	6.80	%	2021 - 2036	$	1,137		$	1,037
Transition bonds^(b)				5.55	%	2023	59			90
Total long-term debt							1,196			1,127
Unamortized debt discount and premium, net							(1		)	(1		)
Unamortized debt issuance costs							(7		)	(5		)
Long-term debt due within one year							(18		)	(281		)
Long-term debt							$	1,170		$	840

__________


(a)	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.


(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021.



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.81	%	-	7.90	%	2021 - 2048	$	5,242		$	4,743
Senior unsecured notes				7.45	%	2032	185			185
Unsecured Tax-Exempt Bonds	1.74	%	-	5.40	%	2024 - 2031	112			112
Medium-terms notes (unsecured)	7.61	%	-	7.72	%	2019 - 2027	22			26
Transition bonds^(b)				5.55	%	2023	59			90
Notes payable and other^(c)	7.28	%	-	8.88	%	2019 - 2022	16			33
Total long-term debt							5,636			5,189
Unamortized debt discount and premium, net							4			5
Unamortized debt issuance costs							(14		)	(6		)
Fair value adjustment							633			686
Long-term debt due within one year							(125		)	(396		)
Long-term debt							$	6,134		$	5,478

__________


(a)	Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.


(b)	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.


(c)	Includes Pepco's capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively.

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2018 and 2017:

Exelon



							Maturity Date	December 31,
	Rates						Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.70	%	-	7.90	%		2019 - 2048	16,496			15,197
Senior unsecured notes	2.45	%	-	7.60	%		2019 - 2046	11,285			11,285
Unsecured notes	2.40	%	-	6.35	%		2021 - 2048	2,900			2,600
Pollution control notes	2.50	%	-	2.70	%		2025 - 2036	435			435
Nuclear fuel procurement contracts				3.15	%		2020	39			82
Notes payable and other^(b)(c)	2.85	%	-	8.88	%		2019 - 2053	188			405
Junior subordinated notes				3.50	%		2022	1,150			1,150
Long-term software licensing agreement				3.95	%		2024	73			79
Unsecured Tax-Exempt Bonds	1.74	%	-	5.40	%	—	2024 - 2031	112			112
Medium-Terms Notes (unsecured)	7.61	%	-	7.72	%		2019 - 2027	22			26
Transition bonds				5.55	%		2023	59			90
Loan Agreement				2.00	%		2023	50			—
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%		2031 - 2037	1,253			1,331
Variable rates^(f)				5.81	%		2019 - 2024	849			865
Total long-term debt								34,911			33,657
Unamortized debt discount and premium, net								(66		)	(57		)
Unamortized debt issuance costs								(216		)	(201		)
Fair value adjustment								795			865
Long-term debt due within one year^(e)								(1,349		)	(2,088		)
Long-term debt								$	34,075		$	32,176
Long-term debt to financing trusts^(d)
Subordinated debentures to ComEd Financing III				6.35	%		2033	$	206		$	206
Subordinated debentures to PECO Trust III	7.38	%	-	7.50	%		2028	81			81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103			103
Total long-term debt to financing trusts								390			390
Unamortized debt issuance costs								—			(1		)
Long-term debt to financing trusts								$	390		$	389

__________


(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.


(b)	Includes capital lease obligations of $36 million and $53 million at December 31, 2018 and 2017, respectively. Lease payments of $21 million, $5 million, $1 million, $1 million, less than $1 million, and $8 million will be made in 2019, 2020, 2021, 2022, 2023, and thereafter, respectively.


(c)	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.


(d)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.


(e)	In January 2019, $300 million of ComEd long-term debt due within one year was paid in full.


(f)	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
Unsecured notes	2.40	%	-	6.35	%	2021 - 2048	2,900			2,600
Total long-term debt							2,900			2,600
Unamortized debt discount and premium, net							(6		)	(6		)
Unamortized debt issuance costs							(18		)	(17		)
Long-term debt							$	2,876		$	2,577

PHI



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	2.15	%	-	6.45	%	2019 - 2048	$	8,179		$	7,529
Notes payable and other^(b)				7.49	%	2053	8			147
Total long-term debt							8,187			7,676
Unamortized debt discount and premium, net							(23		)	(23		)
Unamortized debt issuance costs							(63		)	(52		)
Long-term debt due within one year^(d)							(300		)	(840		)
Long-term debt							$	7,801		$	6,761
Long-term debt to financing trust^(c)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Total long-term debt to financing trusts							206			206
Unamortized debt issuance costs							(1		)	(1		)
Long-term debt to financing trusts							$	205		$	205

__________


(a)	Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.


(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2018 and 2017, respectively. Lease payments of less than $1 million annually will be made from 2019 through expiration at 2053.


(c)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.


(d)

ration



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
Senior unsecured notes	2.95	%	-	7.60	%	2019 - 2042	$	6,019		$	6,019
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			435
Nuclear fuel procurement contracts				3.15	%	2020	39			82
Notes payable and other^(a)(b)	2.85	%	-	7.83	%	2019 - 2024	164			223
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,253			1,331
Variable rates^(c)				5.81	%	2019 - 2024	849			865
Total long-term debt							8,759			8,955
Unamortized debt discount and premium, net							(6		)	(8		)
Unamortized debt issuance costs							(51		)	(60		)
Fair value adjustment							91			103
Long-term debt due within one year							(906		)	(346		)
Long-term debt							$	7,887		$	8,644

__________


(a)	Includes Generation’s capital lease obligations of $14 million and $18 million at December 31, 2018 and 2017, respectively. Generation will make lease payments of $7 million, $5 million, $1 million, and $1 million in 2019, 2020, 2021, and 2022, respectively. Lease payments of less than $1 million annually will be made from 2023 through expiration of the final capital lease in 2024.



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	1.81	%	-	4.27	%	2023 - 2048	$	1,370		$	1,171
Unsecured Tax-Exempt Bonds	1.74	%	-	5.40	%	2024 - 2031	112			112
Medium-terms notes (unsecured)	7.61	%	-	7.72	%	2019 - 2027	22			26
Total long-term debt							1,504			1,309
Unamortized debt discount and premium, net							2			2
Unamortized debt issuance costs							(12		)	(11		)
Long-term debt due within one year							(91		)	(83		)
Long-term debt							$	1,403		$	1,217

___



						Maturity Date	December 31,
	Rates					Maturity Date	2018			2017
Long-term debt
First mortgage bonds^(a)	3.05	%	-	7.90	%	2022 - 2048	$	2,735		$	2,535
Notes payable and other^(b)	7.28	%	-	8.88	%	2019 - 2022	16			35
Total long-term debt							2,751			2,570
Unamortized debt discount and premium, net							2			2
Unamortized debt issuance costs							(34		)	(32		)
Long-term debt due within one year							(15		)	(19		)
Long-term debt							$	2,704		$	2,521

___

Schedule of Maturities of Long-term Debt

-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2019 through 2023 and thereafter are as follows:



Year	Exelon			Generation		ComEd			PECO			BGE		PHI		Pepco		DPL		ACE
2019	$	1,349		$	906	$	300		$	—		$	—	$	125	$	15	$	91	$	18
2020	3,528			2,108		500			—			—		20		—		—		20
2021	1,511			1		350			300			300		261		1		—		260
2022	3,084			1,024		—			350			250		310		310		—		—
2023	850			—		—			50			300		500		—		500		—
Thereafter	24,979		^(a)	4,720		7,243		^(b)	2,609		^(c)	2,050		4,420		2,425		913		898
Total	$	35,301		$	8,759	$	8,393		$	3,309		$	2,900	$	5,636	$	2,751	$	1,504	$	1,196

__________


(a)	Includes $390 million due to ComEd and PECO financing trusts.


(b)	Includes $206 million due to ComEd financing trust.


(c)	Includes $184 million due to PECO financing trusts.

Jun

Schedule Of Remeasurements Of Deferred Income Taxes Due To Tax Reform [Table Text Block]

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
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

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:



						Successor
	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



						Successor
	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



						Successor
	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 remained in an overall net regulatory asset position as of December 31, 2017 after recording the impacts related to the TCJA.

ScheduleOfCategorizationOfNetRegulatoryLiabilitiesDueToTaxReform [Table Text Block]

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.



					Successor
	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)

Schedule of Components of Income Tax Expense (Benefit)

Income tax expense (benefit) from continuing operations is comprised of the following components:



	For the Year Ended December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Included in operations:
Federal
Current	$	226		$	337		$	(63	)	$	11		$	(5	)	$	(4	)	$	28		$	(3	)	$	(14	)
Deferred	(98		)	(347		)	145			10			47			24			(21		)	13			18
Investment tax credit amortization	(24		)	(21		)	(2		)	—			—			(1		)	—			—			—
State
Current	(1		)	6			(29		)	1			—			7			—			—			—
Deferred	17			(83		)	117			(16		)	32			9			6			12			8
Total	$	120		$	(108	)	$	168		$	6		$	74		$	35		$	13		$	22		$	12



	For the Year Ended December 31, 2017^(a)
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Included in operations:
Federal
Current	$	194		$	584		$	(191	)	$	71		$	74		$	(60	)	$	(20	)	$	(24	)	$	(12	)
Deferred	(471		)	(2,005		)	523			28			101			250			114			82			34
Investment tax credit amortization	(25		)	(21		)	(2		)	—			(1		)	(1		)	—			—			—
State
Current	14			65			(49		)	14			(5		)	(4		)	(2		)	—			—
Deferred	162			1			136			(9		)	49			32			13			13			4
Total	$	(126	)	$	(1,376	)	$	417		$	104		$	218		$	217		$	105		$	71		$	26



																								Successor			Predecessor
	For the Year Ended December 31, 2016^(a)																							March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO		BGE			Pepco			DPL			ACE			PHI			PHI
Included in operations:
Federal
Current	$	60		$	513		$	(135	)	$	63	$	51		$	(118	)	$	(88	)	$	(26	)	$	(281	)	$	—
Deferred	600			(254		)	379			72		88			136			97			22			283			10
Investment tax credit amortization	(24		)	(20		)	(2		)	—		(1		)	—			—			—			(1		)	—
State
Current	39			45			(4		)	9		5			7			1			—			(11		)	—
Deferred	78			(2		)	63			5		31			16			12			—			13			7
Total	$	753		$	282		$	301		$	149	$	174		$	41		$	22		$	(4	)	$	3		$	17



Net interest receivable (payable) as of	Exelon		Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2018	$	236	$	(2	)	$	4	$	—	$	—	$	1	$	—	$	—	$	—
December 31, 2017	233		(3		)	4		—		—		2		—		—		—



Net penalties payable as of	Exelon			Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2018	$	(17	)	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2017	(17		)	—		—		—		—		—		—		—		—

Effective Income Tax Rate Reconciliation

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



	For the Year Ended December 31, 2018
											Successor
	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	0.6		(16.6	)	8.3		(2.6	)	6.6		3.0		2.2		6.7		7.4
Qualified NDT fund income	(1.9	)	(11.8	)	—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)	(6.5	)	(0.2	)	(0.1	)	(0.1	)	(0.2	)	(0.1	)	(0.3	)	(0.4	)
Plant basis differences	(3.5	)	—		(0.2	)	(14.1	)	(1.3	)	(1.6	)	(2.7	)	(0.3	)	(0.5	)
Production tax credits and other credits	(2.2	)	(13.5	)	—		—		—		—		—		—		—
Noncontrolling interests	(1.0	)	(6.1	)	—		—		—		—		—		—		—
Excess deferred tax amortization	(8.3	)	—		(9.1	)	(3.2	)	(8.0	)	(14.5	)	(14.8	)	(12.0	)	(14.9	)
Tax Cuts and Jobs Act of 2017	0.9		2.7		(0.1	)	—		—		0.1		—		—		—
Other	1.0		1.3		0.5		0.3		0.9		0.3		0.2		0.4		1.2
Effective income tax rate	5.4	%	(29.5	)%	20.2	%	1.3	%	19.1	%	8.1	%	5.8	%	15.5	%	13.8	%



	For the Year Ended December 31, 2017^(a)
											Successor
	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	2.3		2.9		5.7		0.6		5.4		4.8		3.2		5.4		5.6
Qualified NDT fund income	3.8		9.9		—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9	)	(2.1	)	(0.2	)	(0.1	)	(0.1	)	(0.2	)	(0.1	)	(0.2	)	(0.4	)
Plant basis differences^(b)	(1.7	)	—		0.3		(13.8	)	0.1		1.1		(0.4	)	2.0		3.6
Production tax credits and other credits	(1.8	)	(4.7	)	—		—		—		—		—		—		—
Like-kind exchange	(1.2	)	—		1.3		—		—		—		—		—		—
Merger expenses	(3.6	)	(1.2	)	—		—		—		(9.5	)	(6.3	)	(7.8	)	(19.8	)
FitzPatrick bargain purchase gain	(2.2	)	(5.6	)	—		—		—		—		—		—		—
Tax Cuts and Jobs Act of 2017^(c)	(33.1	)	(128.3	)	0.1		(2.3	)	0.9		6.4		2.7		2.5		1.6
Other	0.1		(0.5	)	0.2		(0.1	)	0.2		(0.1	)	(0.2	)	0.1		(0.4	)
Effective income tax rate	(3.3	)%	(94.6	)%	42.4	%	19.3	%	41.5	%	37.5	%	33.9	%	37.0	%	25.2	%



																	Successor		Predecessor
	For the Year Ended December 31, 2016^(a)																March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL ^(d)		ACE ^(d)		PHI ^(d)		PHI
U.S. Federal statutory rate	35.0	%	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 ^(e)	3.3		3.2		5.6		1.3		5.0		15.7		52.7		6.2		5.8		11.9
Qualified NDT fund income	3.4		7.9		—		—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)	(2.3	)	(0.3	)	(0.1	)	(0.1	)	(0.2	)	(3.7	)	0.8		1.4		(0.9	)
Plant basis differences	(4.9	)	—		(0.6	)	(9.6	)	(2.7	)	(22.8	)	(25.5	)	10.3		39.0		(13.5	)
Production tax credits and other credits	(3.6	)	(8.3	)	—		—		—		—		—		—		—		—
Noncontrolling interests	(0.2	)	(0.6	)	—		—		—		—		—		—		—		—
Statute of limitations expiration	(0.4	)	(1.7	)	—		—		—		—		—		—		—		—
Penalties	1.9		—		4.5		—		—		—		—		—		(0.7	)	—
Merger Expenses	5.6		1.1		—		—		—		23.5		112.9		(44.9	)	(89.0	)	11.1
Other ^(f)	(0.7	)	(1.4	)	0.1		(1.2	)	—		(1.8	)	(2.2	)	1.3		3.3		3.6
Effective income tax rate	38.2	%	32.9	%	44.3	%	25.4	%	37.2	%	49.4	%	169.2	%	8.7	%	(5.2	)%	47.2	%

__________


(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 the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 4 - Regulatory Matters for additional information.


(c)	Included are impacts for TCJA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives, the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback.


(d)	DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.


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


(f)	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and accepted in 2017. No change to the results recorded as of December 31, 2016.

Tax Effects of Temporary Differences

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2018 and 2017 are presented below:



	As of December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Plant basis differences	$	(12,533	)	$	(2,495	)	$	(4,059	)	$	(1,862	)	$	(1,399	)	$	(2,577	)	$	(1,148	)	$	(743	)	$	(645	)
Accrual based contracts	117			(44		)	—			—			—			161			—			—			—
Derivatives and other financial instruments	89			35			69			—			—			3			—			—			—
Deferred pension and postretirement obligation	1,435			(188		)	(255		)	(26		)	(26		)	(102		)	(78		)	(46		)	(14		)
Nuclear decommissioning activities	(351		)	(351		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	234			23			(7		)	—			(3		)	187			(4		)	(2		)	(1		)
Regulatory assets and liabilities	(749		)	—			300			(129		)	172			(90		)	58			96			83
Tax loss carryforward	237			78			—			18			25			96			12			52			26
Tax credit carryforward	811			816			—			—			—			—			—			—			—
Investment in partnerships	(797		)	(775		)	—			—			—			—			—			—			—
Other, net	934			239			151			67			12			196			98			17			19
Deferred income tax liabilities (net)	$	(10,573	)	$	(2,662	)	$	(3,801	)	$	(1,932	)	$	(1,219	)	$	(2,126	)	$	(1,062	)	$	(626	)	$	(532	)
Unamortized investment tax credits	(724		)	(700		)	(12		)	(1		)	(3		)	(8		)	(2		)	(2		)	(3		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,297	)	$	(3,362	)	$	(3,813	)	$	(1,933	)	$	(1,222	)	$	(2,134	)	$	(1,064	)	$	(628	)	$	(535	)



	As of December 31, 2017 ^(a)
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Plant basis differences	$	(12,490	)	$	(2,819	)	$	(3,825	)	$	(1,762	)	$	(1,368	)	$	(2,521	)	$	(1,152	)	$	(717	)	$	(607	)
Accrual based contracts	150			(66		)	—			—			—			216			—			—			—
Derivatives and other financial instruments	(85		)	(66		)	(2		)	—			—			3			—			—			—
Deferred pension and postretirement obligation	1,463			(205		)	(285		)	(15		)	(29		)	(130		)	(78		)	(51		)	(18		)
Nuclear decommissioning activities	(553		)	(553		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	217			26			(8		)	(1		)	(3		)	203			(4		)	(2		)	(1		)
Regulatory assets and liabilities	(688		)	—			489			(90		)	136			(184		)	39			88			86
Tax loss carryforward	344			76			33			9			11			156			40			68			35
Tax credit carryforward	861			868			1			—			—			6			—			—			—
Investment in partnerships	(434		)	(416		)	—			—			—			—			—			—			—
Other, net	746			78			141			71			13			193			94			14			16
Deferred income tax liabilities (net)	$	(10,469	)	$	(3,077	)	$	(3,456	)	$	(1,788	)	$	(1,240	)	$	(2,058	)	$	(1,061	)	$	(600	)	$	(489	)
Unamortized investment tax credits	(732		)	(705		)	(13		)	(1		)	(4		)	(8		)	(2		)	(3		)	(4		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,201	)	$	(3,782	)	$	(3,469	)	$	(1,789	)	$	(1,244	)	$	(2,066	)	$	(1,063	)	$	(603	)	$	(493	)

Summary of Loss Carryforwards



	As of December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Plant basis differences	$	(12,533	)	$	(2,495	)	$	(4,059	)	$	(1,862	)	$	(1,399	)	$	(2,577	)	$	(1,148	)	$	(743	)	$	(645	)
Accrual based contracts	117			(44		)	—			—			—			161			—			—			—
Derivatives and other financial instruments	89			35			69			—			—			3			—			—			—
Deferred pension and postretirement obligation	1,435			(188		)	(255		)	(26		)	(26		)	(102		)	(78		)	(46		)	(14		)
Nuclear decommissioning activities	(351		)	(351		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	234			23			(7		)	—			(3		)	187			(4		)	(2		)	(1		)
Regulatory assets and liabilities	(749		)	—			300			(129		)	172			(90		)	58			96			83
Tax loss carryforward	237			78			—			18			25			96			12			52			26
Tax credit carryforward	811			816			—			—			—			—			—			—			—
Investment in partnerships	(797		)	(775		)	—			—			—			—			—			—			—
Other, net	934			239			151			67			12			196			98			17			19
Deferred income tax liabilities (net)	$	(10,573	)	$	(2,662	)	$	(3,801	)	$	(1,932	)	$	(1,219	)	$	(2,126	)	$	(1,062	)	$	(626	)	$	(532	)
Unamortized investment tax credits	(724		)	(700		)	(12		)	(1		)	(3		)	(8		)	(2		)	(2		)	(3		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,297	)	$	(3,362	)	$	(3,813	)	$	(1,933	)	$	(1,222	)	$	(2,134	)	$	(1,064	)	$	(628	)	$	(535	)



	As of December 31, 2017 ^(a)
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Plant basis differences	$	(12,490	)	$	(2,819	)	$	(3,825	)	$	(1,762	)	$	(1,368	)	$	(2,521	)	$	(1,152	)	$	(717	)	$	(607	)
Accrual based contracts	150			(66		)	—			—			—			216			—			—			—
Derivatives and other financial instruments	(85		)	(66		)	(2		)	—			—			3			—			—			—
Deferred pension and postretirement obligation	1,463			(205		)	(285		)	(15		)	(29		)	(130		)	(78		)	(51		)	(18		)
Nuclear decommissioning activities	(553		)	(553		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	217			26			(8		)	(1		)	(3		)	203			(4		)	(2		)	(1		)
Regulatory assets and liabilities	(688		)	—			489			(90		)	136			(184		)	39			88			86
Tax loss carryforward	344			76			33			9			11			156			40			68			35
Tax credit carryforward	861			868			1			—			—			6			—			—			—
Investment in partnerships	(434		)	(416		)	—			—			—			—			—			—			—
Other, net	746			78			141			71			13			193			94			14			16
Deferred income tax liabilities (net)	$	(10,469	)	$	(3,077	)	$	(3,456	)	$	(1,788	)	$	(1,240	)	$	(2,058	)	$	(1,061	)	$	(600	)	$	(489	)
Unamortized investment tax credits	(732		)	(705		)	(13		)	(1		)	(4		)	(8		)	(2		)	(3		)	(4		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(11,201	)	$	(3,782	)	$	(3,469	)	$	(1,789	)	$	(1,244	)	$	(2,066	)	$	(1,063	)	$	(603	)	$	(493	)

__________


(a)	Includes remeasurement impacts related to the TCJA.

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2018:



										Successor
	Exelon		Generation		ComEd	PECO		BGE		PHI		Pepco		DPL		ACE
Federal
Federal general business credits carryforwards	811	^(a)	816		—	—		—		—		—		—		—
State
State net operating losses	4,103	^(b)	1,544	^(b)	—	224	^(c)	395	^(d)	1,492	^(e)	192	^(f)	772	^(g)	365	^(h)
Deferred taxes on state tax attributes (net)	272		104		—	18		26		102		12		52		26
Valuation allowance on state tax attributes	35		26		—	—		1		6		—		—		—

__________


(a)	Exelon’s federal general business credit carryforwards will begin expiring in 2033.


(b)	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2019.


(c)	PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.


(d)	BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026.


(e)	PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2036.


(f)	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2033.


(g)	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2030.


(h)	ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.

Reconciliation of Unrecognized Tax Benefits Excluding Amounts Pertaining to Examined Tax Returns Foll Forward

The following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2018, 2017 and 2016:



	Exelon			Generation			ComEd		PECO		BGE			PHI			Pepco			DPL			ACE
Unrecognized tax benefits at January 1, 2018	$	743		$	468		$	2	$	—	$	120		$	125		$	59		$	21		$	14
Change to positions that only affect timing	15			15			—		—		—			—			—			—			—
Increases based on tax positions prior to 2018	30			21			—		—		—			8			7			1			—
Decreases based on tax positions prior to 2018	(251		)	(36		)	—		—		(120		)	(88		)	(66		)	(22		)	—
Decrease from settlements with taxing authorities	(53		)	(53		)	—		—		—			—			—			—			—
Decreases from expiration of statute of limitations	(7		)	(7		)	—		—		—			—			—			—			—
Unrecognized tax benefits at December 31, 2018	$	477		$	408		$	2	$	—	$	—		$	45		$	—		$	—		$	14



	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco			DPL			ACE
Unrecognized tax benefits at January 1, 2017	$	916		$	490		$	(12	)	$	—	$	120	$	172		$	80		$	37		$	22
Increases based on tax positions prior to 2017	28			—			14			—		—		14			—			—			14
Decreases based on tax positions prior to 2017	(196		)	(17		)	—			—		—		(61		)	(21		)	(16		)	(22		)
Decrease from settlements with taxing authorities	(5		)	(5		)	—			—		—		—			—			—			—
Unrecognized tax benefits at December 31, 2017	$	743		$	468		$	2		$	—	$	120	$	125		$	59		$	21		$	14



	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco		DPL		ACE
Unrecognized tax benefits at January 1, 2016	$	1,078		$	534		$	142		$	—	$	120	$	22		$	8	$	3	$	—
Merger balance transfer	22			5			—			—		—		(5		)	—		—		—
Increases based on tax positions related to 2016	108			10			—			—		—		59			21		16		22
Change to positions that only affect timing	(332		)	(12		)	(154		)	—		—		—			—		—		—
Increases based on tax positions prior to 2016	88			—			—			—		—		96			51		18		—
Decreases based on tax positions prior to 2016	(21		)	(20		)	—			—		—		—			—		—		—
Decreases from settlements with taxing authorities	(27		)	(27		)	—			—		—		—			—		—		—
Unrecognized tax benefits at December 31, 2016	$	916		$	490		$	(12	)	$	—	$	120	$	172		$	80	$	37	$	22

Interest Income and Interest Expense Disclosure [Table Text Block]



Net interest expense (income) for the years ended	Exelon			Generation			ComEd		PECO		BGE		Pepco		DPL		ACE
December 31, 2018	$	(3	)	$	—		$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2017	37			(1		)	11		—		—		—		—		—
December 31, 2016	165			(13		)	117		—		—		6		—		(1		)



Net penalty expense (income) for the years ended	Exelon			Generation		ComEd		PECO		BGE		Pepco		DPL		ACE
December 31, 2018	$	—		$	—	$	—	$	—	$	—	$	—	$	—	$	—
December 31, 2017	(2		)	—		—		—		—		—		—		—
December 31, 2016	106			—		86		—		—		—		—		—



	Successor							Predecessor
PHI	December 31, 2018		December 31, 2017		March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
Net interest expense	$	—	$	—	$	(2	)	$	—

Summary of Open Tax Years by Jurisdiction

Description of tax years open to assessment by major jurisdiction



Taxpayer	Open Years
Exelon (and predecessors) and subsidiaries consolidated federal income tax returns	1999, 2001-2017
PHI Holdings and subsidiaries consolidated federal income tax returns	2013, 2015-2016
Exelon and subsidiaries Illinois unitary income tax returns	2010-2017
Constellation combined New York corporate income tax returns	2010-March 2012
Exelon combined New York corporate income tax returns	2011-2017
Exelon New Jersey corporate income tax returns	2013-2017
Exelon Pennsylvania corporate net income tax returns	2011-2017
PECO Pennsylvania separate company returns	2015-2017
DPL Delaware separate company returns	Same as federal
ACE New Jersey separate company returns	2014-2017
Exelon and subsidiaries District of Columbia corporate income tax returns	2015-2017
PHI Holdings and subsidiaries District of Columbia corporate income tax returns	2015-2016
Various separate company Maryland corporate net income tax returns	Same as federal

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Asset Retirement Obligation Disclosure [Abstract]

Nuclear Decommissioning Asset Retirement Obligation Rollforward

The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2017 to December 31, 2018:



	Exelon			Generation			ComEd			PECO			BGE			PHI		Pepco		DPL		ACE
Non-nuclear AROs at January 1, 2017	$	393		$	199		$	121		$	28		$	24		$	14	$	2	$	9	$	3
Net (decrease) increase due to changes in, and timing of, estimated future cash flows	(11		)	(1		)	(13		)	(1		)	2			2		1		1		—
Development projects	1			1			—			—			—			—		—		—		—
Accretion expense^(a)	18			10			7			1			—			—		—		—		—
Deconsolidation of EGTP	(7		)	(7		)	—			—			—			—		—		—		—
Payments	(10		)	(5		)	(2		)	(1		)	(2		)	—		—		—		—
Non-nuclear AROs at December 31, 2017	384			197			113			27			24			16		3		10		3
Net increase due to changes in, and timing of, estimated future cash flows^(b)	80			35			7			—			2			36		34		1		1
Accretion expense^(a)	16			10			4			1			1			—		—		—		—
Asset divestitures	(3		)	(3		)	—			—			—			—		—		—		—
Payments	(6		)	(1		)	(3		)	—			(2		)	—		—		—		—
Non-nuclear AROs at December 31, 2018	$	471		$	238		$	121		$	28		$	25		$	52	$	37	$	11	$	4

__________


(a)	For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.


(b)	In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981.

The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2017 to December 31, 2018:



Nuclear decommissioning ARO at January 1, 2017	$	8,734
Accretion expense	458
Acquisition of FitzPatrick	444
Net increase due to changes in, and timing of, estimated future cash flows	34
Costs incurred related to decommissioning plants	(8		)
Nuclear decommissioning ARO at December 31, 2017^(a)	9,662
Accretion expense	478
Net decrease due to changes in, and timing of, estimated future cash flows	(77		)
Costs incurred related to decommissioning plants	(58		)
Nuclear decommissioning ARO at December 31, 2018^{(a) (b)}	$	10,005

__________


(a)	Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

Unrealized Gains Losses On Nuclear Decommissioning Trust Funds

The following table provides unrealized (losses) gains on NDT funds of Exelon and Generation for the years ended 2018, 2017 and 2016:



	2018			2017		2016
Net unrealized (losses) gains on NDT funds—Regulatory Agreement Units ^(a)	$	(715	)	$	455	$	216
Net unrealized (losses) gains on NDT funds—Non-Regulatory Agreement Units ^(b)	(483		)	521		194

__________


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


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

Nuclear Decommissioning Pledged Assets

The following table provides Exelon's and Generation's pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2018 and 2017:



	2018		2017
Carrying value of Zion Station pledged assets	$	9	$	39
Current payable to ZionSolutions ^(a)	9		37
Cumulative withdrawals by ZionSolutions to pay decommissioning costs ^(b)	965		942

_______


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


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

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2018

Retirement Benefits [Abstract]

Schedule Of Pension And Other Postretirement Participation

The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2018:

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program^(a)

Exelon Corporation Cash Balance Pension Plan^(a)

Exelon Corporation Pension Plan for Bargaining Unit Employees^(a)

Exelon New England Union Employees Pension Plan^(a)

Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek^(a)

Pension Plan of Constellation Energy Group, Inc.^(b)

Pension Plan of Constellation Energy Nuclear Group, LLC^(c)

Nine Mile Point Pension Plan^(c)

Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B^(b)

Pepco Holdings LLC Retirement Plan^(d)

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan^(a)

Exelon Corporation Supplemental Management Retirement Plan^(a)

Constellation Energy Group, Inc. Senior Executive Supplemental Plan^(b)

Constellation Energy Group, Inc. Supplemental Pension Plan^(b)

Constellation Energy Group, Inc. Benefits Restoration Plan^(b)

Constellation Energy Nuclear Plan, LLC Executive Retirement Plan^(c)

Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan^(c)

Baltimore Gas & Electric Company Executive Benefit Plan^(b)

Baltimore Gas & Electric Company Manager Benefit Plan^(b)

Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan^(d)

Conectiv Supplemental Executive Retirement Plan^(d)

Pepco Holdings LLC Combined Executive Retirement Plan ^(d)

Atlantic City Electric Director Retirement Plan ^(d)

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Other Postretirement Benefit Plans



			Exelon
			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2018		2017
Equity securities	47	%	44	%	47	%
Fixed income securities	28	%	28		28
Alternative investments^(a)	25	%	28		25
Total			100	%	100	%

__________


(a)	Alternative investments include private equity, hedge funds, real estate, and private credit

Defined Benefit Plan Fair Value Of Plan Assets [Text Block]

Fair Value Measurements

Exelon



December 31, 2018^(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	350	$	—	$	—	$	—	$	350
Equities^(c)	3,364		—		2		1,980		5,346
Fixed income:
U.S. Treasury and agencies	996		173		—		—		1,169
State and municipal debt	—		59		—		—		59
Corporate debt	—		3,716		216		—		3,932
Other^(c)	—		329		—		613		942
Fixed income subtotal	996		4,277		216		613		6,102
Private equity	—		—		—		1,219		1,219
Hedge funds	—		—		—		1,608		1,608
Real estate	—		—		—		1,029		1,029
Private credit	—		—		268		798		1,066
Pension plan assets subtotal	$	4,710	$	4,277	$	486	$	7,247	$	16,720



December 31, 2018^(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	22	$	—	$	—	$	—	$	22
Equities	537		2		—		508		1,047
Fixed income:
U.S. Treasury and agencies	11		56		—		—		67
State and municipal debt	—		126		—		—		126
Corporate debt	—		48		—		—		48
Other	183		72		—		170		425
Fixed income subtotal	194		302		—		170		666
Hedge funds	—		—		—		411		411
Real estate	—		—		—		132		132
Private credit	—		—		—		132		132
Other postretirement benefit plan assets subtotal	$	753	$	304	$	—	$	1,353	$	2,410
Total pension and other postretirement benefit plan assets^(e)	$	5,463	$	4,581	$	486	$	8,600	$	19,130



December 31, 2017^(a)(b)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	585	$	—	$	—	$	—	$	585
Equities^(c)	3,565		—		2		3,077		6,644
Fixed income:
U.S. Treasury and agencies	1,150		159		—		—		1,309
State and municipal debt	—		64		—		—		64
Corporate debt	—		3,931		232		—		4,163
Other^(c)	—		447		—		756		1,203
Fixed income subtotal	1,150		4,601		232		756		6,739
Private equity	—		—		—		1,034		1,034
Hedge funds	—		—		—		1,770		1,770
Real estate	—		—		—		884		884
Private credit^(d)	—		—		224		695		919
Pension plan assets subtotal	$	5,300	$	4,601	$	458	$	8,216	$	18,575



December 31, 2017^(a)(b)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	29	$	—	$	—	$	—	$	29
Equities	523		2		—		764		1,289
Fixed income:
U.S. Treasury and agencies	13		56		—		—		69
State and municipal debt	—		136		—		—		136
Corporate debt	—		47		—		—		47
Other	225		71		—		185		481
Fixed income subtotal	238		310		—		185		733
Hedge funds	—		—		—		430		430
Real estate	—		—		—		124		124
Private credit	—		—		—		123		123
Other postretirement benefit plan assets subtotal	$	790	$	312	$	—	$	1,626	$	2,728
Total pension and other postretirement benefit plan assets^(e)	$	6,090	$	4,913	$	458	$	9,842	$	21,303

__________


(a)	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.


(b)	Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan obligations.

(c)


(d)	Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.


(e)	Excludes net liabilities of $44 million and net assets of $2 million at December 31, 2018 and 2017, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]

Exelon



	Fixed Income			Equities		Private Credit		Total
Pension Assets
Balance as of January 1, 2018	$	232		$	2	$	224	$	458
Actual return on plan assets:
Relating to assets still held at the reporting date	(14		)	—		9		(5		)
Relating to assets sold during the period	(1		)	—		—		(1		)
Purchases, sales and settlements:
Purchases	19			—		35		54
Sales	(8		)	—		—		(8		)
Settlements^(b)	(12		)	—		—		(12		)
Balance as of December 31, 2018	$	216		$	2	$	268	$	486



	Fixed income			Equities		Private Credit ^(a)			Total
Pension Assets
Balance as of January 1, 2017	$	206		$	2	$	229		$	437
Actual return on plan assets:
Relating to assets still held at the reporting date	11			—		29			40
Purchases, sales and settlements:
Purchases	31			—		5			36
Sales	(16		)	—		—			(16		)
Settlements^(b)	—			—		(39		)	(39		)
Balance as of December 31, 2017	$	232		$	2	$	224		$	458

__________


(a)

Schedule Of Defined Contributions [Table Text Block]

in limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2018, 2017 and 2016:



For the Year Ended December 31,	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		BSC^(b)		Pepco^(c)		DPL^(c)		ACE		PHISCO^(c)(d)
2018	$	179	$	86	$	37	$	9	$	12	$	22	$	3	$	2	$	2	$	6
2017	128		55		31		10		10		9		3		2		2		6
2016	164		79		34		10		12		19		3		2		2		6



	Successor						Predecessor
PHI	For the Year Ended December 31, 2018		For the Year Ended December 31, 2017		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Saving Plan Matching Contributions	$	13	$	13	$	10	$	3

__________


(a)	Includes $13 million related to CENG for the year ended December 31, 2016.


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


(c)	Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016.


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

Severance (Tables)

12 Months Ended

Dec. 31, 2018

Dec. 31, 2016

Restructuring and Related Activities [Abstract]

Severance

For the periods ended December 31, 2018, 2017 and 2016, the Registrants have recognized costs to achieve the PHI merger as follows:



	For the Year Ended December 31,
Acquisition, Integration and Financing Costs^(a)	2018		2017			2016
Exelon	$	7	$	16		$	143
Generation	5		22			37
ComEd^(b)	—		1			(6		)
PECO	1		4			5
BGE^(b)	1		4			(1		)
Pepco^(b)	—		(6		)	28
DPL^(b)	—		(7		)	20
ACE^(b)	—		(6		)	19



	Successor							Predecessor
	For the Year Ended December 31,					March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Acquisition, Integration and Financing Costs^(a)	2018		2017			March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
PHI^(b)	$	—	$	(18	)	$	69	$	29

______________


(a)	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

(b)



Severance Benefits	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Severance costs^(a)	$	57	$	9	$	2	$	1	$	1	$	44	$	21	$	13	$	10


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations.

Severance Liability




Severance Liability	Exelon			Generation			ComEd			PECO		BGE		PHI			Pepco			DPL		ACE
Balance at December 31, 2016	$	88		$	36		$	3		$	—	$	—	$	29		$	—		$	—	$	—
Severance costs^(a)	35			31			2			—		—		3			—			—		—
Payments	(29		)	(9		)	(2		)	—		—		(12		)	—			—		—
Balance at December 31, 2017	$	94		$	58		$	3		$	—	$	—	$	20		$	—		$	—	$	—
Severance costs^(a)	35			9			1			—		1		5			1			—		—
Payments	(52		)	(20		)	(2		)	—		—		(18		)	(1		)	—		—
Balance at December 31, 2018	$	77		$	47		$	2		$	—	$	1	$	7		$	—		$	—	$	—

__________


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

Shareholders' Equity Shareholder Equity (Tables)

12 Months Ended

Dec. 31, 2018

Shareholder [Abstract]

Schedule of Common Stock Outstanding Roll Forward [Table Text Block]

The following table presents common stock authorized and outstanding as of December 31, 2018 and 2017:



				December 31,
				2018	2017
	Par Value		Shares Authorized	Shares Outstanding
Common Stock
Exelon	no par value		2,000,000,000	968,187,955	963,335,888
ComEd	$	12.50	250,000,000	127,021,331	127,021,246
PECO	no par value		500,000,000	170,478,507	170,478,507
BGE	no par value		1,500	1,000	1,000
Pepco	$	0.01	200,000,000	100	100
DPL	$	2.25	1,000	1,000	1,000
ACE	$	3.00	25,000,000	8,546,017	8,546,017

Stock-Based Compensation Plans (All Registrants) (Tables)

12 Months Ended

Dec. 31, 2018

Common Stock [Abstract]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]



Exelon	Year Ended December 31,
Components of Stock-Based Compensation Expense	2018			2017			2016^(a)
Performance share awards	$	143		$	107		$	93
Restricted stock units	57			77			75
Stock options	—			—			—
Other stock-based awards	8			7			7
Total stock-based compensation expense included in operating and maintenance expense	208			191			175
Income tax benefit	(54		)	(74		)	(68		)
Total after-tax stock-based compensation expense	$	154		$	117		$	107

__________


(a)	2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

PHI



	Predecessor
	January 1 to March 23,
Components of Stock-Based Compensation Expense	2016
Time-based restricted stock units	$	2
Performance-based restricted stock units	1
Time-based restricted stock awards	—
Total stock-based compensation expense included in operating and maintenance expense	3
Income tax benefit	(1		)
Total after-tax stock-based compensation expense	$	2

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]



	Year Ended December 31,
Subsidiaries	2018		2017		2016
Exelon	$	208	$	191	$	175
Generation	77		88		78
ComEd	8		7		8
PECO	5		3		3
BGE	3		1		1
BSC^(a)	111		88		81
PHI Successor^(b)(c)	4		4		4



	Predecessor
	January 1 to March 23,
	2016
PHI	$	3

__________


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


(b)	Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 2018 and 2017 was not material.


(c)	These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations.

Stock Based Compensation Tax Benefit

The following tables present information regarding Exelon’s tax benefits for the years ended December 31, 2018, 2017 and 2016.



Exelon	Year Ended December 31,
	2018	2017	2016
Realized tax benefit when exercised/distributed:
Restricted stock units	28	35	27
Performance share awards	16	29	18

Schedule of Share-based Compensation, Stock Options, Activity

The following table presents information with respect to stock option activity for the year ended December 31, 2018:



	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2017	6,723,611		$	47.69	2.65	$	7
Options exercised	(1,522,952	)	36.54
Options forfeited	—		—
Options expired	(1,173,007	)	74.99
Balance of shares outstanding at December 31, 2018	4,027,652		$	43.95	2.90	$	14
Exercisable at December 31, 2018 ^(a)	4,027,652		$	43.95	2.90	$	14

__________


(a)	Includes stock options issued to retirement eligible employees.

Stock Options Exercised

The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2018, 2017 and 2016:



	Year Ended December 31,
	2018		2017		2016
Intrinsic value^(a)	$	12	$	15	$	11
Cash received for exercise price	56		107		19

__________


(a)	The difference between the market value on the date of exercise and the option exercise price.

Schedule of Nonvested Restricted Stock Units Activity

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2018:

Exelon



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2017^(a)	3,389,503		$	32.24
Granted	1,321,988		38.60
Vested	(1,845,300	)	32.03
Forfeited	(65,046	)	32.96
Undistributed vested awards^(b)	(507,804	)	36.76
Nonvested at December 31, 2018^(a)	2,293,341		$	35.06

__________


(a)	Excludes 1,131,487 and 1,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.


(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2018.

Schedule of Nonvested Performance-based Units Activity

The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2018:

Exelon



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2017^(a)	2,956,966		$	32.65
Granted	1,637,542		38.15
Change in performance	1,348,029		30.66
Vested	(848,574	)	36.26
Forfeited	(50,467	)	36.24
Undistributed vested awards ^(b)	(1,640,268	)	33.38
Nonvested at December 31, 2018^(a)	3,403,228		$	33.13

__________


(a)	Excludes 3,586,259 and 2,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.


(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2018.

The following table summarizes the weighted average grant date fair value and the fair value of performance share awards granted and settled for the years ended December 31, 2018, 2017 and 2016:



	Year Ended December 31,
	2018^(a)		2017		2016
Weighted average grant date fair value (per share)	$	38.15	$	35.00	$	28.85
Fair value of performance shares settled	61		72		45
Fair value of performance shares settled in cash	49		56		28

__________


(a)	As of December 31, 2018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.

Not Settled Performance Share Awards Balance Sheet Presentation

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:



	December 31,
	2018		2017
Current liabilities^(a)	$	135	$	57
Deferred credits and other liabilities^(b)	109		100
Common stock	26		26
Total	$	270	$	183

__________


(a)	Represents the current liability related to performance share awards expected to be settled in cash.


(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share



	Year Ended December 31,
	2018		2017		2016
Net income attributable to common shareholders	$	2,010	$	3,786	$	1,121
Weighted average common shares outstanding — basic	967		947		924
Assumed exercise and/or distributions of stock-based awards	2		2		3
Weighted average common shares outstanding — diluted	969		949		927

Changes in Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 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 years ended December 31, 2018 and 2017:



For the Year Ended December 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 Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(14	)	$	10		$	(2,998	)	$	(23	)	$	(1	)	$	(3,026	)
OCI before reclassifications	11			—			(143		)	(10		)	1			(141		)
Amounts reclassified from AOCI^(b)	1			—			181			—			—			182
Net current-period OCI	12			—			38			(10		)	1			41
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard^(c)	—			(10		)	—			—			—			(10		)
Ending balance	$	(2	)	$	—		$	(2,960	)	$	(33	)	$	—		$	(2,995	)
Generation^(a)
Beginning balance	$	(16	)	$	3		$	—		$	(23	)	$	(1	)	$	(37	)
OCI before reclassifications	11			—			—			(10		)	—			1
Amounts reclassified from AOCI^(b)	1			—			—			—			—			1
Net current-period OCI	12			—			—			(10		)	—			2
Impact of adoption of Recognition and Measurement of Financial Assets and Financial Liabilities standard^(c)	—			(3		)	—			—			—			(3		)
Ending balance	$	(4	)	$	—		$	—		$	(33	)	$	(1	)	$	(38	)
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 Financial Liabilities standard^(c)	—			(1		)	—			—			—			(1		)
Ending balance	$	—		$	—		$	—		$	—		$	—		$	—



For the Year Ended December 31, 2017	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan items			Foreign Currency Items			AOCI of Investments Unconsolidated Affiliates			Total
Exelon^(a)
Beginning balance	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
OCI before reclassifications	(1		)	6		11			7			6			29
Amounts reclassified from AOCI^(b)	4			—		140			—			—			144
Net current-period OCI	3			6		151			7			6			173
Impact of adoption of Reclassification of Certain Tax Effects from AOCI^(d)	—			—		(539		)	—			—			(539		)
Ending balance	$	(14	)	$	10	$	(2,998	)	$	(23	)	$	(1	)	$	(3,026	)
Generation^(a)
Beginning balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
OCI before reclassifications	(1		)	1		—			7			6			13
Amounts reclassified from AOCI^(b)	4			—		—			—			—			4
Net current-period OCI	3			1		—			7			6			17
Ending balance	$	(16	)	$	3	$	—		$	(23	)	$	(1	)	$	(37	)
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 interests. Amounts in parenthesis represent a decrease in AOCI.


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

(c)

(d)

Reclassification Out Of Accumulated Other Comprehensive Income

The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2018 and 2017:

For the Year Ended December 31, 2018



Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Gains (Losses) on cash flow hedges
Other cash flow hedges	$	(1	)	$	(1	)	Interest expense
	(1		)	(1		)	Total before tax
	—			—			Tax benefit
	$	(1	)	$	(1	)	Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	90		$	—
Actuarial losses^(b)	(333		)	—
	(243		)	—			Total before tax
	62			—			Tax benefit
	$	(181	)	$	—		Net of tax

Total Reclassifications	$	(182	)	$	(1	)	Net of tax

For the Year Ended December 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 (Losses) on cash flow hedges
Other cash flow hedges	$	(5	)	$	(5	)	Interest expense
	(5		)	(5		)	Total before tax
	1			1			Tax benefit
	$	(4	)	$	(4	)	Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	92		$	—
Actuarial losses^(b)	(324		)	—
	(232		)	—			Total before tax
	92			—			Tax benefit
	$	(140	)	$	—		Net of tax

Total Reclassifications	$	(144	)	$	(4	)	Net of tax

__________


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


(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 16 — Retirement Benefits for additional information.

Schedule of Other Comprehensive Income Loss Tax

The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2018, 2017 and 2016:



	For the Year Ended December 31,
	2018			2017			2016
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	24		$	36		$	30
Actuarial loss reclassified to periodic benefit cost	(86		)	(128		)	(118		)
Pension and non-pension postretirement benefit plans valuation adjustment	50			13			115
Change in unrealized gains on cash flow hedges	(5		)	(7		)	—
Change in unrealized gains (losses) on investments in unconsolidated affiliates	—			(3		)	3
Change in unrealized gains on marketable securities	—			(1		)	—
Total	$	(17	)	$	(90	)	$	30

Generation
Change in unrealized gains on cash flow hedges	$	(4	)	$	(6	)	$	(2	)
Change in unrealized gains (losses) on investments in unconsolidated affiliates	(1		)	(3		)	3
Change in unrealized gains on marketable securities	—			(1		)	—
Total	$	(5	)	$	(10	)	$	1

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

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

Other Commitments

Commercial Commitments (All Registrants). Exelon’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	1,703	$	1,394	$	308	$	1	$	—	$	—	$	—
Surety bonds^(a)	1,402		1,331		33		38		—		—		—
Financing trust guarantees	378		—		—		—		—		—		378
Guaranteed lease residual values^(b)	24		3		3		2		3		3		10
Total commercial commitments	$	3,507	$	2,728	$	344	$	41	$	3	$	3	$	388

__________


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

(b)

Generation’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	1,680	$	1,380	$	299	$	1	$	—	$	—	$	—
Surety bonds^(a)	1,220		1,201		19		—		—		—		—
Total commercial commitments	$	2,900	$	2,581	$	318	$	1	$	—	$	—	$	—

__________


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

ComEd’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds^(a)	12		10		—		2		—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	214	$	12	$	—	$	2	$	—	$	—	$	200

__________


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

PECO’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Surety bonds^(a)	$	9	$	9	$	—	$	—	$	—	$	—	$	—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	187	$	9	$	—	$	—	$	—	$	—	$	178

__________


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

BGE’s commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	3	$	2	$	1	$	—	$	—	$	—	$	—
Surety bonds^(a)	17		3		14		—		—		—		—
Total commercial commitments	$	20	$	5	$	15	$	—	$	—	$	—	$	—

__________


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

PHI commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	8	$	—	$	8	$	—	$	—	$	—	$	—
Surety bonds^(a)	$	41	$	41	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	24		3		3		2		3		3		10
Total commercial commitments	$	73	$	44	$	11	$	2	$	3	$	3	$	10

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61 million. 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.

Pepco commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Letters of credit	$	8	$	—	$	8	$	—	$	—	$	—	$	—
Surety bonds^(a)	$	33	$	33	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	8		1		1		1		1		1		3
Total commercial commitments	$	49	$	34	$	9	$	1	$	1	$	1	$	3

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The 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 $19 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and Pepco believes the likelihood of payments being required under the guarantees is remote.

DPL commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Surety bonds^(a)	$	5	$	5	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	10		1		1		1		1		1		5
Total commercial commitments	$	15	$	6	$	1	$	1	$	1	$	1	$	5

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $26 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and DPL believes the likelihood of payments being required under the guarantees is remote.

ACE commercial commitments as of December 31, 2018, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2019		2020		2021		2022		2023		2024 and beyond
Surety bonds^(a)	$	3	$	3	$	—	$	—	$	—	$	—	$	—
Guaranteed lease residual values^(b)	6		1		1		—		1		1		2
Total commercial commitments	$	9	$	4	$	1	$	—	$	1	$	1	$	2

__________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $16 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and ACE believes the likelihood of payments being required under the guarantees is remot

mum 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 $16 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and ACE believes the likelihood of payments being required under the guarantees is remote.

Leases (All Registrants)



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

__________


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


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

(c)


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


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

Accrued environmental liabilities



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

Schedule of Government Settlement Agreements [Table Text Block]

Under the settlement agreements, Generation has received cumulative cash reimbursements for costs incurred as follows:



	Total		Net^(a)
Cumulative cash reimbursements^(b)	$	1,274	$	1,100

__________


(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.


(b)	Includes $53 and $49, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.

As of December 31, 2018 and 2017, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:



	December 31, 2018			December 31, 2017
DOE receivable - current^(a)	$	124		$	94
DOE receivable - noncurrent^(b)	15			15
Amounts owed to co-owners^(a)(c)	(17		)	(11		)

__________


(a)	Recorded in Accounts receivable, other.


(b)	Recorded in Deferred debits and other assets, other


(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities

Supplemental Financial Information (Tables)

12 Months Ended

Dec. 31, 2018

Supplemental Financial Information [Abstract]

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

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2018, 2017 and 2016.



	For the year ended December 31, 2018
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	919	$	114	$	243	$	131	$	94	$	337	$	316	$	21	$	—
Property	557		273		30		15		143		94		58		32		3
Payroll	247		130		27		16		17		24		5		3		2
Other	60		39		11		1		—		—		—		—		—
Total taxes other than income	$	1,783	$	556	$	311	$	163	$	254	$	455	$	379	$	56	$	5



	For the year ended December 31, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	898	$	126	$	240	$	125	$	89	$	318	$	300	$	18	$	—
Property	545		269		28		14		132		101		62		32		3
Payroll	230		121		26		15		15		26		6		4		2
Other	58		39		2		—		4		7		3		3		1
Total taxes other than income	$	1,731	$	555	$	296	$	154	$	240	$	452	$	371	$	57	$	6



																		Successor		Predecessor
	For the year ended December 31, 2016																	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd			PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Taxes other than income
Utility^(a)	$	753	$	122	$	242		$	136	$	85	$	312	$	18	$	—	$	253	$	78
Property	483		246		27			13		123		53		31		3		73		18
Payroll	226		117		28			15		17		8		5		3		23		8
Other	114		21		(4		)	—		4		4		1		1		5		1
Total taxes other than income	$	1,576	$	506	$	293		$	164	$	229	$	377	$	55	$	7	$	354	$	105

__________

(a)

Schedule of Other Nonoperating Income, by Component [Table Text Block]



	For the year ended December 31, 2018
													Successor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	506		$	506		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	302			302			—		—		—		—		—		—		—
Net unrealized losses on NDT funds
Regulatory agreement units	(715		)	(715		)	—		—		—		—		—		—		—
Non-regulatory agreement units	(483		)	(483		)	—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(8		)	(8		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	171			171			—		—		—		—		—		—		—
Total decommissioning-related activities	(227		)	(227		)	—		—		—		—		—		—		—
Investment income	43			32			—		1		1		4		2		1		—
Interest income related to uncertain income tax positions	5			1			—		—		—		—		—		—		—
AFUDC—Equity	69			—			19		7		18		25		22		2		1
Non-service net periodic benefit cost	(47		)	—			—		—		—		—		—		—		—
Other	45			16			14		—		—		14		7		7		1
Other, net	$	(112	)	$	(178	)	$	33	$	8	$	19	$	43	$	31	$	10	$	2



	For the year ended December 31, 2017
													Successor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	488		$	488		$	—	$	—	$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	209			209			—		—		—		—		—		—		—
Net unrealized gains on NDT funds
Regulatory agreement units	455			455			—		—		—		—		—		—		—
Non-regulatory agreement units	521			521			—		—		—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(10		)	(10		)	—		—		—		—		—		—		—
Regulatory offset to NDT fund-related activities^(b)	(724		)	(724		)	—		—		—		—		—		—		—
Total decommissioning-related activities	939			939			—		—		—		—		—		—		—
Investment income	8			6			—		—		—		2		1		—		—
Interest income (expense) related to uncertain income tax positions	3			(1		)	—		—		—		—		—		—		—
Benefit related to uncertain income tax positions^(c)	2			—			—		—		—		—		—		—		—
AFUDC—Equity	73			—			12		9		16		36		23		7		6
Non-service net periodic benefit cost	(109		)	—			—		—		—		—		—		—		—
Other	31			4			10		—		—		16		8		7		1
Other, net	$	947		$	948		$	22	$	9	$	16	$	54	$	32	$	14	$	7



																					Successor			Predecessor
	For the year ended December 31, 2016																				March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE		Pepco		DPL		ACE		PHI			PHI
Other, Net
Decommissioning-related activities:
Net realized income on NDT funds^(a)
Regulatory agreement units	$	237		$	237		$	—		$	—		$	—	$	—	$	—	$	—	$	—		$	—
Non-regulatory agreement units	126			126			—			—			—		—		—		—		—			—
Net unrealized gains on NDT funds
Regulatory agreement units	216			216			—			—			—		—		—		—		—			—
Non-regulatory agreement units	194			194			—			—			—		—		—		—		—			—
Net unrealized losses on pledged assets
Zion Station decommissioning	(1		)	(1		)	—			—			—		—		—		—		—			—
Regulatory offset to NDT fund-related activities^(b)	(372		)	(372		)	—			—			—		—		—		—		—			—
Total decommissioning-related activities	400			400			—			—			—		—		—		—		—			—
Investment income (loss)	17			8			—			(1		)	2		1		—		1		1			—
Long-term lease income	4			—			—			—			—		—		—		—		—			—
Interest income (expense) related to uncertain income tax positions	13			—			—			—			—		1		—		—		(1		)	—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—		—		—		—		—			—
AFUDC—Equity	64			—			14			8			19		19		5		6		23			7
Non-service net periodic benefit cost	(116		)	—			—			—			—		—		—		—		—			—
Loss on debt extinguishment	(3		)	(2		)	—			—			—		—		—		—		—			—
Other	24			(5		)	7			1			—		15		8		2		21			(11		)
Other, net	$	297		$	401		$	(65	)	$	8		$	21	$	36	$	13	$	9	$	44		$	(4	)

__________


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


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


(c)	See Note 14—Income Taxes for additional information on the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.

Cash Flow Supplemental Disclosures

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2018, 2017 and 2016.



	For the year ended December 31, 2018
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment	$	3,740	$	1,748	$	820	$	274	$	335	$	480	$	218	$	131	$	94
Regulatory assets	555		—		120		27		148		260		167		51		42
Amortization of intangible assets, net	58		49		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	14		14		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,115		1,115		—		—		—		—		—		—		—
ARO accretion^(c)	489		489		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,971	$	3,415	$	940	$	301	$	483	$	740	$	385	$	182	$	136



	For the year ended December 31, 2017
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization and accretion
Property, plant and equipment	$	3,293	$	1,409	$	777	$	261	$	312	$	457	$	203	$	124	$	89
Regulatory assets	478		—		73		25		161		218		118		43		57
Amortization of intangible assets, net	57		48		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	35		35		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,096		1,096		—		—		—		—		—		—		—
ARO accretion^(c)	468		468		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,427	$	3,056	$	850	$	286	$	473	$	675	$	321	$	167	$	146



																	Successor		Predecessor
	For the year ended December 31, 2016																March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	3,477	$	1,835	$	708	$	244	$	299	$	175	$	110	$	82	$	325	$	94
Regulatory assets	407		—		67		26		124		120		47		83		190		58
Amortization of intangible assets, net	52		44		—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	35		35		—		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,159		1,159		—		—		—		—		—		—		—		—
ARO accretion^(c)	446		446		—		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,576	$	3,519	$	775	$	270	$	423	$	295	$	157	$	165	$	515	$	152

__________


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


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


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



	For the year ended December 31, 2018
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	1,421		$	369		$	332		$	125		$	94		$	250		$	123		$	56		$	61
Income taxes (net of refunds)	95			746			(153		)	(2		)	14			(32		)	41			(6		)	(12		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	583		$	204		$	177		$	18		$	59		$	67		$	15		$	6		$	12
Loss (gain) from equity method investments	28			30			—			—			—			(1		)	—			—			—
Provision for uncollectible accounts	159			48			40			33			10			28			11			6			11
Provision for excess and obsolete inventory	24			20			3			—			—			—			—			—			—
Stock-based compensation costs	75			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(2		)	(2		)	—			—			—			—			—			—			—
Energy-related options^(b)	10			10			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	8			—			3			1			—			4			2			1			1
Amortization of rate stabilization deferral	14			—			—			—			—			14			14			—			—
Amortization of debt fair value adjustment	(15		)	(12		)	—			—			—			(3		)	—			—			—
Merger-related commitments^(c)	—			—			—			—			—			5			—			5			—
Severance costs	35			9			—			—			—			—			—			—			—
Asset retirement costs	20			—			—			—			—			20			22			(1		)	(1		)
Amortization of debt costs	36			14			5			2			1			3			2			—			1
Discrete impacts from EIMA and FEJA^(d)	28			—			28			—			—			—			—			—			—
Long-term incentive plan	140			—			—			—			—			—			—			—			—
Other	(19		)	(23		)	(14		)	(3		)	(12		)	6			(6		)	7			—
Total other non-cash operating activities	$	1,124		$	298		$	242		$	51		$	58		$	143		$	60		$	24		$	24
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(69	)	$	(199	)	$	11		$	(12	)	$	50		$	93		$	20		$	22		$	46
Change in PPE related to ARO update	(107		)	(130		)	7			—			1			15			12			2			1
Dividends on stock compensation	6			—			—			—			—			—			—			—			—
Acquisition of land	3			—			—			—			—			3			—			—			3

__________


(a)	Includes the elimination of decommissioning-related activities 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 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 to results of operations.


(c)	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.


(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information.



	For the year ended December 31, 2017
																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	2,430		$	391		$	307		$	103		$	96		$	236		$	114		$	49		$	59
Income taxes (net of refunds)	540			337			83			47			(2		)	(144		)	(104		)	(49		)	(2		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	643		$	227		$	176		$	29		$	62		$	94		$	25		$	13		$	13
Loss (gain) from equity method investments	32			33			—			—			—			(1		)	—			—			—
Provision for uncollectible accounts	125			38			34			26			8			19			8			3			8
Provision for excess and obsolete inventory	56			51			3			—			—			2			1			1			—
Stock-based compensation costs	88			—			—			—			—			—			—			—			—
Other decommissioning-related activity^(a)	(313		)	(313		)	—			—			—			—			—			—			—
Energy-related options^(b)	7			7			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	9			—			4			1			—			4			2			1			1
Amortization of rate stabilization deferral	(10		)	—			—			—			7			(17		)	(17		)	—			—
Amortization of debt fair value adjustment	(18		)	(12		)	—			—			—			(6		)	—			—			—
Merger-related commitments^(c)	—			—			—			—			—			(8		)	(6		)	(2		)	—
Severance costs	35			31			—			—			—			3			—			—			—
Amortization of debt costs	64			37			5			2			2			4			2			—			1
Discrete impacts from EIMA and FEJA^(d)	(52		)	—			(52		)	—			—			—			—			—			—
Vacation accrual adjustment^(e)	(68		)	(35		)	(12		)	—			—			(8		)	(8		)	—			—
Long-term incentive plan	109			—			—			—			—			—			—			—			—
Change in environmental liabilities	44			44			—			—			—			—			—			—			—
Other	(30		)	4			6			(4		)	(14		)	(28		)	(13		)	(7		)	(6		)
Total other non-cash operating activities	$	721		$	112		$	164		$	54		$	65		$	58		$	(6	)	$	9		$	17
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	42		$	73		$	(61	)	$	22		$	23		$	(12	)	$	5		$	4		$	(13	)
Change in PPE related to ARO update	29			29			—			—			—			—			—			—			—
Non-cash financing of capital projects	16			16			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(f)	—			—			21			—			—			—			—			—			—
Dividends on stock compensation	7			—			—			—			—			—			—			—			—
Dissolution of financing trust due to long-term debt retirement	8			—			—			—			8			—			—			—			—



Fair value adjustment of long-term debt due to retirement	(5	)	—	—	—	—	—	—	—	—
Fair value of pension and OPEB obligation transferred in connection with FitzPatrick	—		33	—	—	—	—	—	—	—

__________


(a)	Includes the elimination of decommissioning-related activities 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 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 to results of operations.


(c)	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.


(d)	Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 4 — Regulatory Matters for additional information.

(e)


(f)	See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.



																					Successor			Predecessor
	For the year ended December 31, 2016																				March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO		BGE		Pepco			DPL		ACE		PHI			PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	1,340		$	339		$	298		$	104	$	92	$	118		$	47	$	62	$	209		$	43
Income taxes (net of refunds)	(441		)	435			(444		)	64		31		216			115		200		258			11
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	619		$	218		$	166		$	33	$	67	$	31		$	18	$	15	$	86		$	23
Loss from equity method investments	24			25			—			—		—		—			—		—		—			—
Provision for uncollectible accounts	155			19			41			30		1		29			23		32		65			16
Stock-based compensation costs	111			—			—			—		—		—			—		—		—			3
Other decommissioning-related activity^(a)	(384		)	(384		)	—			—		—		—			—		—		—			—
Energy-related options^(b)	(11		)	(11		)	—			—		—		—			—		—		—			—
Amortization of regulatory asset related to debt costs	9			—			4			1		—		2			1		1		3			1
Amortization of rate stabilization deferral	76			—			—			—		81		(12		)	2		—		(5		)	5
Amortization of debt fair value adjustment	(11		)	(11		)	—			—		—		—			—		—		—			—
Merger-related commitments^(c)(d)	558			53			—			—		—		125			82		110		317			—
Severance costs	99			22			—			—		—		—			—		—		56			—
Discrete impacts from EIMA^(e)	8			—			8			—		—		—			—		—		—			—
Amortization of debt costs	35			17			4			3		1		—			—		—		1			—



Provision for excess and obsolete inventory	12			6			4			—			—			3			1			1			1			1
Lower of cost or market inventory adjustment	37			36			—			1			—			—			—			—			—			—
Baltimore City Conduit Lease Settlement	(28		)	—			—			—			(28		)	—			—			—			—			—
Cash Working Capital Order	(13		)	—			—			—			(13		)	—			—			—			—			—
Asset retirement costs	2			—			—			—			—			—			1			2			2			—
Long-term incentive plan	70			—			—			—			—			—			—			—			—			—
Other	(35		)	25			(12		)	(3		)	(21		)	(3		)	(14		)	(6		)	(11		)	(3		)
Total other non-cash operating activities	$	1,333		$	15		$	215		$	65		$	88		$	175		$	114		$	155		$	515		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(128	)	$	50		$	(91	)	$	(11	)	$	(86	)	$	27		$	(12	)	$	11		$	21		$	11
Change in PPE related to ARO update	191			191			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			158			—			—			—			—			—			—			—
Dividends on stock compensation	6			—			—			—			—			—			—			—			—			—
Non-cash financing of capital projects	95			95			—			—			—			—			—			—			—			—
Sale of Upstream assets^(c)	37			37			—			—			—			—			—			—			—			—
Pending FitzPatrick Acquisition^(h)	(54		)	(54		)	—			—			—			—			—			—			—			—
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash	—			119			—			—			—			—			—			—			—			—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash^(c)(f)	—			—			—			—			—			—			—			—			127			—
Fair value of pension obligation transferred in connection with the PHI Merger, net of cash^(c)(f)	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—

__________


(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 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 to results of operations.


(c)	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.


(d)	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.


(e)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 4 — Regulatory Matters for additional information.


(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


(g)	See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.


(h)	Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 5 - Mergers, Acquisitions and Dispositions for additional information.



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



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



																	Successor		Predecessor
	December 31, 2016																December 31, 2016		March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Cash and cash equivalents	$	635	$	290	$	56	$	63	$	23	$	9	$	46	$	101	$	170	$	319
Restricted cash	253		158		2		4		24		33		—		9		43		11
Restricted cash included in other long-term assets	26		—		—		—		3		—		—		23		23		18
Total cash, cash equivalents and restricted cash	$	914	$	448	$	58	$	67	$	50	$	42	$	46	$	133	$	236	$	348



											Predecessor
December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Cash and cash equivalents	$	6,502	$	431	$	67	$	295	$	9	$	26	$	5	$	5	$	3
Restricted cash	205		123		2		3		24		14		2		—		12
Restricted cash included in other long-term assets	5		2		—		—		3		18		—		—		18
Total cash, cash equivalents and restricted cash	$	6,712	$	556	$	69	$	298	$	36	$	58	$	7	$	5	$	33

Supplemental Balance Sheet Disclosures [Text Block]

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



December 31, 2018	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Unbilled customer revenues^(a)	$	1,656		$	965		$	223		$	114		$	168		$	186		$	97		$	59		$	30
Allowance for uncollectible accounts ^(b)	(319		)	(104		)	(81		)	(61		)	(20		)	(53		)	(21		)	(13		)	(19		)



December 31, 2017	Exelon			Generation			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Unbilled customer revenues^(a)	$	1,858		$	1,017		$	242		$	162		$	205		$	232		$	133		$	68		$	31
Allowance for uncollectible accounts^(b)	(322		)	(114		)	(73		)	(56		)	(24		)	(55		)	(21		)	(16		)	(18		)

__________


(a)	Represents unbilled portion of receivables estimated under Exelon’s unbilled critical accounting policy.


(b)	Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable.



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



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 a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.

The following tables provide additional information about Registrants' investments at December 31, 2018 and 2017.



December 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Investments
Equity method investments:
Financing trusts^(a)	$	14	$	—	$	6	$	8	$	—	$	—	$	—	$	—	$	—
Bloom	180		180		—		—		—		—		—		—		—
NET Power	70		70		—		—		—		—		—		—		—
Other equity method investments	3		1		—		—		—		—		—		—		—
Total equity method investments	267		251		6		8		—		—		—		—		—
Other investments:
Employee benefit trusts and investments^(b)	244		49		—		17		5		130		105		—		—
Equity investments without readily determinable fair values	72		72		—		—		—		—		—		—		—
Other available for sale debt security investments	40		40		—		—		—		—		—		—		—
Other	2		2		—		—		—		—		—		—		—
Total investments	$	625	$	414	$	6	$	25	$	5	$	130	$	105	$	—	$	—



December 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Investments
Equity method investments:
Financing trusts^(a)	$	14	$	—	$	6	$	8	$	—	$	—	$	—	$	—	$	—
Bloom	206		206		—		—		—		—		—		—		—
NET Power	76		76		—		—		—		—		—		—		—
Other equity method investments	1		1		—		—		—		—		—		—		—
Total equity method investments	297		283		6		8		—		—		—		—		—
Other investments:
Employee benefit trusts and investments^(b)	244		51		—		17		5		132		102		—		—
Equity investments without readily determinable fair values	62		62		—		—		—		—		—		—		—
Other available for sale debt security investments	37		37		—		—		—		—		—		—		—
Total investments	$	640	$	433	$	6	$	25	$	5	$	132	$	102	$	—	$	—

__________


(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.


(b)	The Registrants’ debt and equity security investments are recorded at fair market value.

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



December 31, 2018	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	1,191	$	479	$	187	$	49	$	68	$	99	$	29	$	19	$	12
Taxes accrued	412		226		71		28		46		74		58		4		5
Interest accrued	334		77		105		33		39		50		25		8		12
Severance accrued	44		26		2		—		—		5		—		—		—
Other accrued expenses	131		90		8		3		2		28		14		8		6
Total accrued expenses	$	2,112	$	898	$	373	$	113	$	155	$	256	$	126	$	39	$	35


December 31, 2017	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	978	$	407	$	158	$	64	$	58	$	106	$	29	$	17	$	11
Taxes accrued	373		444		60		15		71		61		68		4		5
Interest accrued	328		78		102		33		34		48		23		8		12
Severance accrued	58		30		2		—		—		17		—		—		—
Other accrued expenses	100		63		5		2		1		29		17		6		5
Total accrued expenses	$	1,837	$	1,022	$	327	$	114	$	164	$	261	$	137	$	35	$	33

__________


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

Segment Information (Tables)

12 Months Ended

Dec. 31, 2018

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information



									Successor
	Generation ^(a)		ComEd		PECO		BGE		PHI ^(e)		Other ^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2018
Competitive businesses electric revenues	$	17,411	$	—	$	—	$	—	$	—	$	—	$	(1,256	)	$	16,155
Competitive businesses natural gas revenues	2,718		—		—		—		—		—		(8		)	2,710
Competitive businesses other revenues	308		—		—		—		—		—		(5		)	303
Rate-regulated electric revenues	—		5,882		2,470		2,428		4,609		—		(45		)	15,344
Rate-regulated natural gas revenues	—		—		568		741		181		—		(20		)	1,470
Shared service and other revenues	—		—		—		—		15		1,948		(1,960		)	3
Total operating revenues	$	20,437	$	5,882	$	3,038	$	3,169	$	4,805	$	1,948	$	(3,294	)	$	35,985
2017
Competitive businesses electric revenues	$	15,332	$	—	$	—	$	—	$	—	$	—	$	(1,105	)	$	14,227
Competitive businesses natural gas revenues	2,575		—		—		—		—		—		—			2,575
Competitive businesses other revenues	593		—		—		—		—		—		(1		)	592
Rate-regulated electric revenues	—		5,536		2,375		2,489		4,469		—		(29		)	14,840
Rate-regulated natural gas revenues	—		—		495		687		161		—		(10		)	1,333
Shared service and other revenues	—		—		—		—		49		1,831		(1,880		)	—
Total operating revenues	$	18,500	$	5,536	$	2,870	$	3,176	$	4,679	$	1,831	$	(3,025	)	$	33,567



										Successor
	Generation ^(a)			ComEd		PECO		BGE		PHI ^(e)			Other ^(b)			Intersegment Eliminations			Exelon
2016
Competitive businesses electric revenues	$	15,400		$	—	$	—	$	—	$	—		$	—		$	(1,430	)	$	13,970
Competitive businesses natural gas revenues	2,146			—		—		—		—			—			—			2,146
Competitive businesses other revenues	211			—		—		—		—			—			(4		)	207
Rate-regulated electric revenues	—			5,254		2,531		2,609		3,506			—			(31		)	13,869
Rate-regulated natural gas revenues	—			—		463		624		92			—			(13		)	1,166
Shared service and other revenues	—			—		—		—		45			1,648			(1,686		)	7
Total operating revenues	$	17,757		$	5,254	$	2,994	$	3,233	$	3,643		$	1,648		$	(3,164	)	$	31,365

Intersegment revenues^(d):
2018	$	1,269		$	27	$	8	$	29	$	15		$	1,942		$	(3,289	)	$	1
2017	1,110			15		7		16		50			1,824			(3,020		)	2
2016	1,428			15		8		21		45			1,647			(3,159		)	5
Depreciation and amortization:
2018	$	1,797		$	940	$	301	$	483	$	740		$	92		$	—		$	4,353
2017	1,457			850		286		473		675			87			—			3,828
2016	1,879			775		270		423		515			74			—			3,936
Operating expenses ^(c):
2018	$	19,510		$	4,741	$	2,452	$	2,696	$	4,156		$	1,929		$	(3,341	)	$	32,143
2017	18,001			4,214		2,215		2,562		3,911			1,742			(3,026		)	29,619
2016	16,878			4,056		2,292		2,683		3,549			1,812			(3,164		)	28,106
Interest expense, net:
2018	$	432		$	347	$	129	$	106	$	261		$	279		$	—		$	1,554
2017	440			361		126		105		245			283			—			1,560
2016	364			461		123		103		195			290			—			1,536
Income (loss) before income taxes:
2018	$	365		$	832	$	466	$	387	$	432		$	(249	)	$	(1	)	$	2,232
2017	1,455			984		538		525		578			(296		)	(2		)	3,782
2016	857			679		587		468		(58		)	(555		)	(5		)	1,973
Income taxes:
2018	$	(108	)	$	168	$	6	$	74	$	35		$	(55	)	$	—		$	120
2017	(1,376		)	417		104		218		217			294			—			(126		)
2016	282			301		149		174		3			(156		)	—			753



									Successor
	Generation ^(a)		ComEd		PECO		BGE		PHI ^(e)			Other ^(b)			Intersegment Eliminations			Exelon
Net income (loss):
2018	$	443	$	664	$	460	$	313	$	398		$	(193	)	$	(1	)	$	2,084
2017	2,798		567		434		307		362			(590		)	(2		)	3,876
2016	550		378		438		294		(61		)	(398		)	(5		)	1,196
Capital expenditures:
2018	$	2,242	$	2,126	$	849	$	959	$	1,375		$	43		$	—		$	7,594
2017	$	2,259	$	2,250	$	732	$	882	$	1,396		$	65		$	—		$	7,584
2016	$	3,078	$	2,734	$	686	$	934	$	1,008		$	113		$	—		$	8,553
Total assets:
2018	$	47,556	$	31,213	$	10,642	$	9,716	$	21,984		$	8,355		$	(9,800	)	$	119,666
2017	48,457		29,726		10,170		9,104		21,247			8,618			(10,552		)	116,770

__________


(a)	See Note 25 — Related Party Transactions for additional information on intersegment revenues.


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


(c)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.

(d)


(e)	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2018.

Successor and Predecessor PHI:



	Pepco		DPL		ACE		Other^(b)		Intersegment Eliminations			PHI
Operating revenues^(a):
December 31, 2018 - Successor
Rate-regulated electric revenues	$	2,239	$	1,151	$	1,236	$	—	$	(17	)	$	4,609
Rate-regulated natural gas revenues	—		181		—		—		—			181
Shared service and other revenues	—		—		—		435		(420		)	15
Total operating revenues	$	2,239	$	1,332	$	1,236	$	435	$	(437	)	$	4,805
December 31, 2017 - Successor
Rate-regulated electric revenues	$	2,158	$	1,139	$	1,186	$	—	$	(14	)	$	4,469
Rate-regulated natural gas revenues	—		161		—		—		—			161
Shared service and other revenues	—		—		—		52		(3		)	49
Total operating revenues	$	2,158	$	1,300	$	1,186	$	52	$	(17	)	$	4,679
March 24, 2016 to December 31, 2016 - Successor
Rate-regulated electric revenues	$	1,675	$	850	$	989	$	5	$	(13	)	$	3,506
Rate-regulated natural gas revenues	—		92		—		—		—			92
Shared service and other revenues	—		—		—		45		—			45
Total operating revenues	$	1,675	$	942	$	989	$	50	$	(13	)	$	3,643
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues	$	511	$	279	$	268	$	42	$	(4	)	$	1,096
Rate-regulated natural gas revenues	—		56		—		1		—			57
Shared service and other revenues	—		—		—		—		—			—
Total operating revenues	$	511	$	335	$	268	$	43	$	(4	)	$	1,153

Intersegment revenues:
December 31, 2018 - Successor	$	6	$	8	$	3	$	435	$	(437	)	$	15
December 31, 2017 - Successor	6		8		2		53		(19		)	50
March 24, 2016 to December 31, 2016 - Successor	4		5		2		47		(13		)	45
January 1, 2016 to March 23, 2016 - Predecessor	1		2		1		—		(4		)	—
Depreciation and amortization:
December 31, 2018 - Successor	$	385	$	182	$	136	$	37	$	—		$	740
December 31, 2017 - Successor	321		167		146		42		(1		)	$	675
March 24, 2016 to December 31, 2016 - Successor	224		120		128		43		—			$	515
January 1, 2016 to March 23, 2016 - Predecessor	71		37		37		11		(4		)	$	152
Operating expenses:
December 31, 2018 - Successor	$	1,919	$	1,143	$	1,087	$	442	$	(435	)	$	4,156
December 31, 2017 - Successor	1,760		1,071		1,029		68		(17		)	$	3,911
March 24, 2016 to December 31, 2016 - Successor	1,577		952		1,000		33		(13		)	$	3,549
January 1, 2016 to March 23, 2016 - Predecessor	443		284		251		73		(3		)	$	1,048



	Pepco		DPL			ACE			Other^(b)			Intersegment Eliminations			PHI
Interest expense, net:
December 31, 2018 - Successor	$	128	$	58		$	64		$	11		$	—		$	261
December 31, 2017 - Successor	121		51			61			13			(1		)	$	245
March 24, 2016 to December 31, 2016 - Successor	98		38			47			12			—			$	195
January 1, 2016 to March 23, 2016 - Predecessor	29		12			15			11			(2		)	$	65
Income (loss) before income taxes:
December 31, 2018 - Successor	$	223	$	142		$	87		$	388		$	(408	)	$	432
December 31, 2017 - Successor	310		192			103			377			(404		)	$	578
March 24, 2016 to December 31, 2016 - Successor	36		(30		)	(51		)	(84		)	71			$	(58	)
January 1, 2016 to March 23, 2016 - Predecessor	47		43			5			59			(118		)	$	36
Income taxes:
December 31, 2018 - Successor	$	13	$	22		$	12		$	(10	)	$	(2	)	$	35
December 31, 2017 - Successor	105		71			26			15			—			$	217
March 24, 2016 to December 31, 2016 - Successor	26		5			(5		)	(23		)	—			$	3
January 1, 2016 to March 23, 2016 - Predecessor	15		17			1			(16		)	—			$	17
Net income (loss):
December 31, 2018 - Successor	$	210	$	120		$	75		$	(22	)	$	15		$	398
December 31, 2017 - Successor	205		121			77			(91		)	50			$	362
March 24, 2016 to December 31, 2016 - Successor	10		(35		)	(47		)	(34		)	45			$	(61	)
January 1, 2016 to March 23, 2016 - Predecessor	32		26			5			(44		)	—			$	19
Capital expenditures:
December 31, 2018 - Successor	$	656	$	364		$	335		$	20		$	—		$	1,375
December 31, 2017 - Successor	628		428			312			28			—			$	1,396
March 24, 2016 to December 31, 2016 - Successor	489		277			218			24			—			1,008
January 1, 2016 to March 23, 2016 - Predecessor	97		72			93			11			—			273
Total assets:
December 31, 2018 - Successor	$	8,299	$	4,588		$	3,699		$	10,819		$	(5,421	)	$	21,984
December 31, 2017 - Successor	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 in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

Analysis and reconciliation of reportable segment revenues for Generation

Competitive Business Revenues (Generation):



	2018
	Revenues from external customers^(a)
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	5,241	$	233		$	5,474	$	13		$	5,487
Midwest	4,527		190			4,717		(11		)	4,706
New England	2,660		185			2,845		(4		)	2,841
New York	1,723		(36		)	1,687		—			1,687
ERCOT	572		560			1,132		1			1,133
Other Power Regions	870		686			1,556		(62		)	1,494
Total Competitive Businesses Electric Revenues	15,593		1,818			17,411		(63		)	17,348
Competitive Businesses Natural Gas Revenues	1,524		1,194			2,718		62			2,780
Competitive Businesses Other Revenues^(c)	510		(202		)	308		1			309
Total Generation Consolidated Operating Revenues	17,627		2,810			$	20,437	$	—		$	20,437



	2017
	Revenues from external customers^(a)
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	5,523	$	(8	)	$	5,515	$	25		$	5,540
Midwest	3,923		283			4,206		(25		)	4,181
New England	2,064		(54		)	2,010		(8		)	2,002
New York	1,605		(38		)	1,567		(17		)	1,550
ERCOT	641		317			958		4			962
Other Power Regions	594		482			1,076		(27		)	1,049
Total Competitive Businesses Electric Revenues	14,350		982			15,332		(48		)	15,284
Competitive Businesses Natural Gas Revenues	1,658		917			2,575		53			2,628
Competitive Businesses Other Revenues^(c)	744		(151		)	593		(5		)	588
Total Generation Consolidated Operating Revenues	$	16,752	$	1,748		$	18,500	$	—		$	18,500



	2016
	Revenues from external customers^(a)
	Contracts with customers		Other^(b)			Total		Intersegment Revenues			Total Revenues
Mid-Atlantic	$	6,182	$	30		$	6,212	$	(33	)	$	6,179
Midwest	4,007		395			4,402		10			4,412
New England	1,953		(175		)	1,778		(9		)	1,769
New York	1,198		10			1,208		(42		)	1,166
ERCOT	810		21			831		6			837
Other Power Regions	670		299			969		(62		)	907
Total Competitive Businesses Electric Revenues	14,820		580			15,400		(130		)	15,270
Competitive Businesses Natural Gas Revenues	1,953		193			2,146		135			2,281
Competitive Businesses Other Revenues^(c)	756		(545		)	211		(5		)	206
Total Generation Consolidated Operating Revenues	$	17,529	$	228		$	17,757	$	—		$	17,757

__________


(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):



	2018							2017							2016
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)		Intersegment RNF			Total RNF
Mid-Atlantic	$	3,022	$	51		$	3,073	$	3,105	$	109		$	3,214	$	3,282	$	35		$	3,317
Midwest	3,112		23			3,135		2,810		10			2,820		2,969		2			2,971
New England	368		(14		)	354		538		(24		)	514		467		(29		)	438
New York	1,112		10			1,122		1,007		1			1,008		771		(19		)	752
ERCOT	501		(243		)	258		575		(243		)	332		412		(131		)	281
Other Power Regions	515		(140		)	375		476		(171		)	305		483		(147		)	336
Total Revenues net of purchased power and fuel for Reportable Segments	$	8,630	$	(313	)	$	8,317	$	8,511	$	(318	)	$	8,193	$	8,384	$	(289	)	$	8,095
Other ^(b)	114		313			427		299		318			617		543		289			832
Total Generation Revenues net of purchased power and fuel expense	$	8,744	$	—		$	8,744	$	8,810	$	—		$	8,810	$	8,927	$	—		$	8,927

__________


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

(b)

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

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



	2018
										Successor
Revenues from contracts with customers	ComEd			PECO			BGE			PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,942		$	1,566		$	1,382		$	2,351	$	1,021	$	669	$	661
Small commercial & industrial	1,487			404			257			488		140		186		162
Large commercial & industrial	538			223			429			1,124		846		100		178
Public authorities & electric railroads	47			28			28			58		32		14		12
Other^(a)	867			243			327			593		193		175		227
Total rate-regulated electric revenues^(b)	5,881			2,464			2,423			4,614		2,232		1,144		1,240
Rate-regulated natural gas revenues
Residential	—			395			491			99		—		99		—
Small commercial & industrial	—			143			77			44		—		44		—
Large commercial & industrial	—			1			124			8		—		8		—
Transportation	—			23			—			16		—		16		—
Other^(c)	—			6			63			13		—		13		—
Total rate-regulated natural gas revenues^(d)	—			568			755			180		—		180		—
Total rate-regulated revenues from contracts with customers	5,881			3,032			3,178			4,794		2,232		1,324		1,240

Other revenues
Revenues from alternative revenue programs	(29		)	(7		)	(26		)	—		—		4		(4		)
Other rate-regulated electric revenues^(e)	30			12			13			10		7		3		—
Other rate-regulated natural gas revenues^(e)	—			1			4			1		—		1		—
Total other revenues	1			6			(9		)	11		7		8		(4		)
Total rate-regulated revenues for reportable segments	$	5,882		$	3,038		$	3,169		$	4,805	$	2,239	$	1,332	$	1,236



	2017
							Successor
Revenues from contracts with customers	ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Rate-regulated electric revenues
Residential	$	2,715	$	1,505	$	1,365	$	2,246	$	964	$	663	$	619
Small commercial & industrial	1,363		401		254		490		137		187		166
Large commercial & industrial	455		223		427		1,086		794		103		189
Public authorities & electric railroads	44		30		31		60		33		14		13
Other^(a)	886		204		299		541		199		163		191
Total rate-regulated electric revenues^(b)	5,463		2,363		2,376		4,423		2,127		1,130		1,178
Rate-regulated natural gas revenues
Residential	—		331		437		90		—		90		—
Small commercial & industrial	—		131		75		38		—		38		—
Large commercial & industrial	—		1		119		8		—		8		—
Transportation	—		23		—		15		—		15		—
Other^(c)	—		8		28		9		—		9		—
Total rate-regulated natural gas revenues^(d)	—		494		659		160		—		160		—
Total rate-regulated revenues from contracts with customers	5,463		2,857		3,035		4,583		2,127		1,290		1,178

Other revenues
Revenues from alternative revenue programs	43		—		124		40		26		6		8
Other rate-regulated electric revenues^(e)	30		12		13		8		5		3		—
Other rate-regulated natural gas revenues^(e)	—		1		4		1		—		1		—
Other revenues^(f)	—		—		—		47		—		—		—
Total other revenues	73		13		141		96		31		10		8
Total rate-regulated revenues for reportable segments	$	5,536	$	2,870	$	3,176	$	4,679	$	2,158	$	1,300	$	1,186



															Successor		Predecessor
	2016														March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
Revenues from contracts with customers	ComEd			PECO		BGE		Pepco		DPL			ACE		PHI		PHI
Rate-regulated electric revenues
Residential	$	2,603		$	1,631	$	1,504	$	1,004	$	672		$	664	$	1,779	$	561
Small commercial & industrial	1,318			430		276		150		188			183		400		121
Large commercial & industrial	462			234		434		790		99			201		835		255
Public authorities & electric railroads	45			32		35		32		13			13		45		13
Other^(a)	820			192		276		190		160			187		400		169
Total rate-regulated electric revenues^(b)	5,248			2,519		2,525		2,166		1,132			1,248		3,459		1,119
Rate-regulated natural gas revenues
Residential	—			309		432		—		86			—		50		36
Small commercial & industrial	—			121		66		—		35			—		21		14
Large commercial & industrial	—			—		114		—		6			—		4		2
Transportation	—			24		—		—		13			—		10		3
Other^(c)	—			9		28		—		8			—		7		2
Total rate-regulated natural gas revenues^(d)	—			463		640		—		148			—		92		57
Total rate-regulated revenues from contracts with customers	5,248			2,982		3,165		2,166		1,280			1,248		3,551		1,176

Other revenues
Revenues from alternative revenue programs	(24		)	—		53		14		(6		)	9		43		(26		)
Other rate-regulated electric revenues^(e)	30			12		13		6		3			—		6		3
Other rate-regulated natural gas revenues^(e)	—			—		2		—		—			—		—		—
Other revenues^(f)	—			—		—		—		—			—		43		—
Total other revenues	6			12		68		20		(3		)	9		92		(23		)
Total rate-regulated revenues for reportable segments	$	5,254		$	2,994	$	3,233	$	2,186	$	1,277		$	1,257	$	3,643	$	1,153

__________


(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 $1 million and $21 million at PECO and BGE, respectively, in 2018, $1 million and $11 million at PECO and BGE, respectively, in 2017, and $1 million and $14 million at PECO and BGE, respectively, in 2016.


(e)	Includes late payment charge revenues.


(f)	Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016, respectively.

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2018

The financial statements of PECO include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017			2016
Operating revenues from affiliates:
Generation ^(a)	$	2	$	1		$	3
BSC	3		5			3
ComEd	1		—			1
BGE	1		1			1
ACE	1		—			—
Total operating revenues from affiliates	$	8	$	7		$	8
Purchased power from affiliates
Generation^(b)	$	126	$	135		$	287
Operating and maintenance from affiliates:
BSC ^(c)	$	146	$	146		$	142
Generation	2		2			2
ComEd	7		—			1
BGE	1		1			1
Total operating and maintenance from affiliates	$	156	$	149		$	146
Interest expense to affiliates, net:
PECO Trust III	$	6	$	6		$	6
PECO Trust IV	6		6			6
Exelon Corporate	2		—			—
Generation	—		(1		)	—
Total interest expense to affiliates, net:	$	14	$	11		$	12
Capitalized costs
BSC ^(c)	$	64	$	59		$	57
Cash dividends paid to parent	$	306	$	288		$	277
Contributions from parent	$	89	$	16		$	18

PHI

The financial statements of PHI include related party transactions as presented in the tables below:



	Successor
	For the Year Ended December 31,		For the Year Ended December 31,		March 24, 2016 to December 31,
	2018		2017		2016
Operating revenues from affiliates:
BSC	$	12	$	48	$	44
PHISCO	1		2		—
Generation	2		—		1
Total operating revenues from affiliates	$	15	$	50	$	45
Purchased power from affiliates
Generation	$	355	$	463	$	486
Operating and maintenance from affiliates:
BSC ^(a)	$	147	$	145	$	86
Other	5		5		3
Total operating and maintenance from affiliates	$	152	$	150	$	89
Earnings (losses) in equity method investments:
Other	$	1	$	—	$	—
Capitalized costs:
BSC ^(a)	$	102	$	—	$	—
PHISCO ^(a)	79		—		—
Total capitalized costs	$	181	$	—	$	—
Cash dividends paid to parent	$	326	$	311	$	273
Contributions from parent	$	385	$	758	$	1,251



	December 31,
	2018		2017
Receivables from affiliates (current):
ComEd ^(a)	$	69	$	28
PECO ^(b)	30		26
BGE ^(c)	24		24
Pepco ^(d)	28		36
DPL ^(e)	7		12
ACE ^(f)	5		6
PHISCO ^(h)	—		1
Other	10		7
Total receivables from affiliates (current)	$	173	$	140
Intercompany money pool (current):
Exelon Corporate	$	100	$	—
PCI	—		54
Total intercompany money pool (current)	$	100	$	54
Payables to affiliates (current):
Exelon Corporate ⁽ⁱ⁾	$	17	$	21
BSC ^(h)	95		74
ComEd	19		12
PECO ^(b)	—		4
Other	8		12
Total payables to affiliates (current)	$	139	$	123
Other liabilities to affiliates (current):
ComEd ^(a)	$	14	$	—
Long-term debt to affiliates (noncurrent):
Exelon Corporate ^(k)	$	898	$	910
Payables to affiliates (noncurrent):
ComEd ^(j)	$	2,217	$	2,528
PECO ^(j)	389		537
Total payables to affiliates (noncurrent)	$	2,606	$	3,065

__________


(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.


(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.


(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.


(d)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.


(e)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.


(f)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.


(g)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.


(h)	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(i)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.


(j)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations for additional information.

(k)



	December 31,
	2018		2017
Prepaid voluntary employee beneficiary association trust ^(c)	$	5	$	2
Receivables from affiliates (current):
Voluntary employee beneficiary association trust	$	1	$	1
Generation	19		12
Total receivables from affiliates (current)	$	20	$	13
Receivables from affiliates (noncurrent):
Generation ^(d)	$	2,217	$	2,528
Payables to affiliates (current):
Generation ^(a)	$	55	$	28
BSC ^(b)	56		39
ComEd Financing III	4		4
Exelon Corporate	4		3
Total payables to affiliates (current)	$	119	$	74
Long-term debt to ComEd financing trust:
ComEd Financing III	$	205	$	205

__________


(a)	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation.


(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c)


(d)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.



	December 31,
	2018		2017
Receivables from affiliates (current):
DPL	$	1	$	—
Payables to affiliates (current):
Exelon Corporation	$	1	$	—
Generation ^(b)	28		36
BSC ^(c)	19		11
PHISCO ^(c)	14		27
Total payables to affiliates (current)	$	62	$	74

__________


(a)	Pepco provides energy to Generation for Generation’s own use.


(b)	Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs.


(c)	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.

The financial statements of DPL include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
BSC	$	1	$	—	$	—
PHISCO	4		6		5
ComEd	1		—		—
ACE	1		—		—
Other	1		2		2
Total operating revenues from affiliates	$	8	$	8	$	7
Purchased power from affiliates
Generation ^(a)	$	120	$	179	$	154
Operating and maintenance:
PHISCO ^{(b), (d)}	$	—	$	165	$	194
PES ^(c)	—		9		8
Total operating and maintenance	$	—	$	174	$	202
Operating and maintenance from affiliates:
BSC ^(b)	$	51	$	31	$	18
PHISCO ^{(b), (d)}	111		—		—
Other	—		1		1
Total operating and maintenance from affiliates	$	162	$	32	$	19
Capitalized costs:
BSC ^(b)	$	28	$	—	$	—
PHISCO ^(b)	25		—		—
Total capitalized costs	$	53	$	—	$	—
Cash dividends paid to parent	$	96	$	112	$	54
Contributions from parent	$	150	$	—	$	152



	December 31,
	2018		2017
Payables to affiliates (current):
Generation	$	40	$	54
BGE	—		1
BSC^(a)	41		24
Exelon Corporate	6		6
Other	7		5
Total payables to affiliates (current)	$	94	$	90

__________


(a)	PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.



	December 31,
	2018		2017
Payables to affiliates (current):
Exelon Corporate	$	1	$	—
Generation ^(a)	7		12
BSC ^(b)	11		7
PHISCO ^(b)	12		27
Pepco	1		—
ACE	1		—
Total payables to affiliates (current)	$	33	$	46

The financial statements of ComEd include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates
Generation	$	9	$	9	$	7
BSC	7		6		6
PECO	10		—		1
BGE	1		—		1
Total operating revenues from affiliates	$	27	$	15	$	15
Purchased power from affiliates
Generation ^(a)	$	529	$	108	$	47
Operating and maintenance from affiliates
BSC ^(b)	$	265	$	270	$	225
PECO	1		—		1
BGE	1		—		1
Total operating and maintenance from affiliates	$	267	$	270	$	227
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC ^(b)	$	135	$	118	$	112
Cash dividends paid to parent	$	459	$	422	$	369
Contributions from parent	$	500	$	651	$	315



	December 31,
	2018		2017
Prepaid voluntary employee beneficiary association trust ^(d)	$	1	$	—
Receivables from affiliates (noncurrent):
Generation ^(e)	$	389	$	537
Payables to affiliates (current):
Generation^(b)	$	30	$	22
BSC^(c)	26		29
Exelon Corporate	2		1
PECO Trust III	1		1
Total payables to affiliates (current)	$	59	$	53
Long-term debt to financing trusts:
PECO Trust III	$	81	$	81
PECO Trust IV	103		103
Total long-term debt to financing trusts	$	184	$	184

__________


(a)	PECO provides energy to Generation for Generation’s own use.


(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively.


(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.


(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

The financial statements of BGE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
Generation ^(a)	$	22	$	10	$	13
BSC	5		5		6
ComEd	1		—		1
PECO	1		1		1
Total operating revenues from affiliates	$	29	$	16	$	21
Purchased power from affiliates
Generation ^(b)	$	257	$	384	$	604
Operating and maintenance from affiliates:
BSC ^(c)	$	157	$	152	$	130
Generation	3		—		—
ComEd	1		—		1
PECO	1		1		1
Total operating and maintenance from affiliates	$	162	$	153	$	132
Interest expense to affiliates, net:
BGE Capital Trust II	$	—	$	10	$	16
Capitalized costs
BSC ^(c)	$	79	$	54	$	36
Cash dividends paid to parent	$	209	$	198	$	179
Contributions from parent	$	109	$	184	$	61



	December 31,
	2018		2017
Receivables from affiliates (current):
Other	$	1	$	1
Payables to affiliates (current):
Generation ^(b)	$	24	$	24
BSC ^(c)	38		25
Exelon Corporate	2		1
Other	1		2
Total payables to affiliates (current)	$	65	$	52

__________


(a)	BGE provides energy to Generation for Generation’s own use.


(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.


(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

The financial statements of Generation include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018			2017			2016
Operating revenues from affiliates:
ComEd ^(a)	$	523		$	121		$	47
PECO ^(b)	128			138			290
BGE ^(c)	260			388			608
Pepco ^(d)	206			255			295
DPL ^(e)	120			179			154
ACE^(f)	29			29			37
BSC	2			1			2
Other	—			4			6
Total operating revenues from affiliates	$	1,268		$	1,115		$	1,439
Purchased power and fuel from affiliates:
ComEd	$	(6	)	$	13		$	—
BGE	20			9			12
Other	—			(3		)	—
Total purchased power and fuel from affiliates	$	14		$	19		$	12
Operating and maintenance from affiliates:
ComEd ^(g)	$	7		$	7		$	7
PECO ^(g)	2			1			3
BGE ^(g)	2			1			1
Pepco	1			—			1
PHISCO	1			1			1
BSC ^(h)	652			689			650
Other	(4		)	(2		)	—
Total operating and maintenance from affiliates	$	661		$	697		$	663
Interest expense to affiliates, net:
Exelon Corporate ⁽ⁱ⁾	$	36		$	37		$	39
PCI	—			1			—
PECO	—			1			—
Total interest expense to affiliates, net:	$	36		$	39		$	39
Earnings (losses) in equity method investments
Qualifying facilities and domestic power projects	$	(30	)	$	(33	)	$	(25	)
Capitalized costs
BSC ^(h)	$	67		$	98		$	98
Cash distributions paid to member	$	1,001		$	659		$	922
Contributions from member	$	155		$	102		$	142



	December 31,
	2018		2017
Payables to affiliates (current):
ComEd Financing III	$	4	$	4
PECO Trust III	1		1
Total payables to affiliates (current)	$	5	$	5
Long-term debt to financing trusts:
ComEd Financing III	$	206	$	205
PECO Trust III	81		81
PECO Trust IV	103		103
Total long-term debt to financing trusts	$	390	$	389

__________

(a)

The financial statements of Pepco include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
Generation ^(a)	$	1	$	—	$	1
BSC	1		—		—
PHISCO	4		6		4
Total operating revenues from affiliates	$	6	$	6	$	5
Purchased power from affiliates
Generation ^(b)	$	206	$	255	$	295
Operating and maintenance:
PHISCO ^{(c), (e)}	$	—	$	219	$	263
PES ^(d)	—		29		39
Total operating and maintenance	$	—	$	248	$	302
Operating and maintenance from affiliates:
BSC ^(c)	$	89	$	53	$	31
PHISCO ^{(c), (e)}	137		5		4
Total operating and maintenance from affiliates	$	226	$	58	$	35
Capitalized costs:
BSC ^(c)	$	40	$	—	$	—
PHISCO ^(c)	32		—		—
Total capitalized costs	$	72	$	—	$	—
Cash dividends paid to parent	$	169	$	133	$	136
Contributions from parent	$	166	$	161	$	187

The financial statements of Exelon include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018			2017			2016
Operating revenues from affiliates:
Generation ^(a)	(2		)	—
PECO ^(a)	—			1			1
BGE ^(a)	—			4			4
ACE ^(a)	—			—			—
Other	1			2			5
Total operating revenues from affiliates	$	(1	)	$	7		$	10
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	14		$	13
PECO Trust III	6			6			6
PECO Trust IV	6			6			6
BGE Capital Trust II	—			10			16
Total interest expense to affiliates, net	$	25		$	36		$	41
Earnings (losses) in equity method investments:
Qualifying facilities and domestic power projects	$	(29	)	$	(33	)	$	(25	)
Other	1			1			1
Total losses in equity method investments	$	(28	)	$	(32	)	$	(24	)

ACE

The financial statements of ACE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2018		2017		2016
Operating revenues from affiliates:
PHISCO	$	2	$	1	$	2
Other	1		1		1
Total operating revenues from affiliates	$	3	$	2	$	3
Purchased power from affiliates
Generation ^(a)	$	29	$	29	$	37
Operating and maintenance:
PHISCO ^{(b), (c)}	$	—	$	135	$	155
Operating and maintenance from affiliates:
BSC ^(b)	$	42	$	25	$	15
PHISCO ^{(b), (c)}	98		—		—
Other	2		3		3
Total operating and maintenance from affiliates	$	142	$	28	$	18
Capitalized costs:
BSC ^(b)	$	20	$	—	$	—
PHISCO ^(b)	21		—		—
Total capitalized costs	$	41	$	—	$	—
Cash dividends paid to parent	$	59	$	68	$	63
Contributions from parent	$	67	$	—	$	139



	December 31,
	2018		2017
Receivable from affiliate (current):
DPL	$	1	$	—
Payables to affiliates (current):
Generation ^(a)	$	5	$	6
BSC ^(b)	8		5
PHISCO ^(b)	13		18
Other	2		—
Total payables to affiliates (current)	$	28	$	29

__________


(a)	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process.


(b)	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(c)	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

Quarterly Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2018

Quarterly Financial Data [Abstract]

Quarterly Financial Information

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	977	$	951	$	177	$	228	$	128	$	125
June 30	662		674		85		98		51		45
September 30	731		738		103		124		63		62
December 31	799		813		109		163		71		76

The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income (Loss)
	2018		2017		2018		2017		2018			2017
Quarter ended:
March 31	$	310	$	275	$	23	$	25	$	7		$	28
June 30	265		270		25		25		8			8
September 30	406		370		84		79		61			41
December 31	254		271		14		28		(1		)	—

The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income Attributable to Membership Interest
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	1,251	$	1,175	$	126	$	180	$	65	$	140
June 30	1,076		1,074		153		148		84		66
September 30	1,361		1,310		245		285		187		153
December 31	1,117		1,121		126		159		62		4

The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	384	$	362	$	49	$	78	$	31	$	57
June 30	289		282		42		41		26		19
September 30	328		327		51		59		33		31
December 31	331		330		48		52		30		14

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	1,512	$	1,298	$	292	$	314	$	165	$	141
June 30	1,398		1,357		288		319		164		118
September 30	1,598		1,571		323		404		193		189
December 31	1,373		1,309		242		286		141		120

The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	557	$	530	$	56	$	79	$	31	$	58
June 30	523		514		85		84		54		43
September 30	628		604		112		149		89		87
December 31	531		510		65		87		36		17



	Operating Revenues				Operating Income				Net Income Attributable to Common Shareholders
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	9,693	$	8,747	$	1,101	$	1,308	$	585	$	990
June 30	8,076		7,665		942		300		539		95
September 30	9,403		8,768		1,146		1,499		733		823
December 31	8,814		8,384		708		1,288		152		1,880



	Net Income per Basic Share				Net Income per Diluted Share
	2018		2017		2018		2017
Quarter ended:
March 31	$	0.61	$	1.07	$	0.60	$	1.06
June 30	0.56		0.10		0.56		0.10
September 30	0.76		0.86		0.76		0.85
December 31	0.16		1.95		0.16		1.94

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2018		2017		2018		2017		2018		2017
Quarter ended:
March 31	$	866	$	796	$	142	$	192	$	113	$	127
June 30	653		630		127		137		96		88
September 30	757		715		154		169		126		112
December 31	765		729		165		157		124		107

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income (Loss)					Net Income (Loss) Attributable to Membership Interest
	2018		2017		2018		2017			2018			2017
Quarter ended:
March 31	$	5,512	$	4,878	$	347	$	373		$	136		$	418
June 30	4,579		4,216		282		(427		)	178			(235		)
September 30	5,278		4,750		311		497			234			304
December 31	5,069		4,657		35		504			(178		)	2,224

Significant Accounting Policies - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Significant Accounting Policies Additional Narrative Information [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest	$ 2,306	$ 2,291
Percentage ownership of consolidated subsidiaries	100.00%
Minimum expectation of tax position to be realized	50.00%
Commonwealth Edison Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Stockholders' Equity Attributable to Noncontrolling Interest		$ 1
Percentage ownership of consolidated subsidiaries	99.00%
CENG [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	50.01%
ExGen Renewables [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	51.00%
Minimum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	20.00%
Maximum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	50.00%

Significant Accounting Policies Balance Sheet Classification of Deferred Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Other noncurrent assets	$ 1,575	$ 1,330
Other noncurrent liabilities	2,130	2,097
Commonwealth Edison Co [Member]
Other noncurrent assets	395	238
Other noncurrent liabilities	630	562
Exelon Generation Co L L C [Member]
Other noncurrent assets	755	670
Other noncurrent liabilities	610	658
PECO Energy Co [Member]
Other noncurrent assets	27	12
Other noncurrent liabilities	76	86
Baltimore Gas and Electric Company [Member]
Other noncurrent assets	5	4
Other noncurrent liabilities	$ 73	$ 56

Significant Accounting Policies Expected Right of Use Assets and Lease Obligations (Details)	12 Months Ended
	Dec. 31, 2018
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$1,400-$1,500
Estimated Operating Lease, Lease Liability	$1,600-$1,700
Exelon Generation Co L L C [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$1,000-$1,100
Estimated Operating Lease, Lease Liability	$1,200-$1,300
Commonwealth Edison Co [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$5-$10
Estimated Operating Lease, Lease Liability	$5-$10
PECO Energy Co [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$1-$5
Estimated Operating Lease, Lease Liability	$1-$5
Baltimore Gas and Electric Company [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$100-$120
Estimated Operating Lease, Lease Liability	$100-$120
Pepco Holdings LLC [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$250-$270
Estimated Operating Lease, Lease Liability	$300-$320
Potomac Electric Power Company [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$60-$65
Estimated Operating Lease, Lease Liability	$60-$65
Delmarva Power & Light Company [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$70-$75
Estimated Operating Lease, Lease Liability	$75-$80
Atlantic City Electric Company [Member]
Estimated Right of Use Assets and Lease Liabilities from Operating Leases [Line Items]
Estimated Operating Lease, Right-of-Use Asset	$20-$25
Estimated Operating Lease, Lease Liability	$20-$25

Variable Interest Entities Variable Interest Entities - Narrative (Details) $ in Millions	1 Months Ended				12 Months Ended
	Jul. 31, 2017 USD ($)	Nov. 30, 2015	Jun. 30, 2015	Jul. 30, 2014	Dec. 31, 2018 USD ($) VIE project	Dec. 31, 2017 USD ($) VIE	Dec. 31, 2016 USD ($)	Jul. 18, 2014 USD ($)	Apr. 01, 2014 USD ($)
Variable Interest Entity [Line Items]
Number of variable interest entities consolidated \| VIE					5	5
Number of variable interest entities not consolidated by equity holders \| VIE					7	7
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net					$ 15
Guarantee obligations maximum exposure					61
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount					15
2015 ESA Investco, LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage			99.00%
Payment Guarantee [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Guarantee obligations maximum exposure									$ 245
Financial Guarantee [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Guarantee obligations maximum exposure									165
Equity interest member [Member] \| 2015 ESA Investco, LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage			90.00%
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Nonconsolidated, Carrying Amount, Assets and Liabilities, Net					13
Parental guarantee provided					$ 34
Ownership Percentage Of Consolidated Variable Interest Entities					62.00%
Wind project entities with noncontrolling equity interests \| project					4
Noncontrolling equity interest ownership percentage held by third parties					1.00%
Number of projects with significant economic power \| project					3
Ownership interests in project entities					99.00%
Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount					$ 13
Exelon Generation Co L L C [Member] \| ExGen Renewables Holdings, LLC [Member]
Variable Interest Entity [Line Items]
Proceeds from Sale of Interest in Partnership Unit	$ 400
Exelon Generation Co L L C [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage					100.00%
Ownership Percentage Of Consolidated Variable Interest Entities					100.00%
Exelon Generation Co L L C [Member] \| Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Parental guarantee provided					$ 275
Exelon Generation Co L L C [Member] \| CENG [Member]
Variable Interest Entity [Line Items]
Parental guarantee provided					$ 688
Ownership interest					50.01%
Due from Affiliates					$ 196				$ 400
Exelon Generation Co L L C [Member] \| Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage				90.00%
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests					227			$ 85
Exelon Generation Co L L C [Member] \| Equity interest member [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage		69.00%
Exelon Generation Co L L C [Member] \| Equity interest member [Member] \| ExGen Renewables Holdings, LLC [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	49.00%
Exelon Generation Co L L C [Member] \| Equity interest member [Member] \| Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage				90.00%
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Guarantee obligations maximum exposure					16
Atlantic City Electric Company [Member] \| ATF [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE					$ 30	$ 48	$ 60

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

Dec. 31, 2018

Dec. 31, 2017

Current assets

^[1]

$ 938

$ 662

Noncurrent assets

^[1]

9,071

9,317

^[1]

10,009

9,979

Current liabilities

^[1]

274

308

^[1]

3,280

3,316

^[1]

3,554

3,624

Current assets

931

652

Noncurrent assets

9,045

9,286

9,976

9,938

Current liabilities

252

272

3,233

3,250

3,485

3,522

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

102

$ 59

$ 90

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

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

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

$ 1,349

$ 898

$ 635

$ 6,502

247

207

253

205

4,607

4,445

1,256

1,132

804

976

1,238

1,260

13,360

11,896

76,707

74,202

11,661

13,272

6,677

452

337

1,575

1,330

^[1]

119,666

116,770

1,349

2,088

3,800

3,532

2,112

1,837

475

232

149

231

1,035

1,069

11,404

10,798

34,075

32,176

9,679

10,029

3,988

3,736

463

609

2,130

2,097

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

86,596

84,583

^[2]

414

126

^[2]

^[2]

146

170

^[2]

^[2]

212

205

^[2]

^[2]

913

635

^[2]

6,145

6,186

^[2]

2,351

2,502

^[2]

258

274

^[2]

8,754

8,962

^[2]

9,667

9,597

^[2]

102

^[2]

114

^[2]

^[2]

^[2]

^[2]

273

308

^[2]

1,072

1,154

^[2]

2,160

2,035

^[2]

121

^[2]

3,275

3,310

^[2]

3,548

3,618

750

416

290

431

153

138

158

123

2,941

2,697

562

321

804

976

883

933

8,433

6,882

23,981

24,906

11,661

13,272

452

334

755

670

^[3]

47,556

48,457

906

346

1,847

1,773

898

1,022

449

211

279

265

5,769

4,191

6,989

7,734

9,450

9,844

610

658

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

^[3]

32,048

32,498

414

126

146

170

212

205

906

625

6,145

6,186

2,351

2,502

232

243

8,728

8,931

9,634

9,556

114

252

272

1,025

1,088

2,160

2,035

121

3,228

3,244

3,480

3,516

124

453

486

177

206

1,533

1,551

13,446

12,498

4,005

^[4]

21,984

21,247

125

396

496

348

256

261

119

188

123

1,592

1,931

6,134

5,478

442

561

369

389

^[4]

12,702

12,422

170

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

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

102

101

$ 9

$ 12

240

258

2,966

2,706

^[5]

3,699

3,445

281

154

118

422

619

1,170

840

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

^[5]

2,573

2,402

$ 59

$ 90

[1]	Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities for additional information.
[2]	Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
[3]	Generation’s consolidated assets include $9,634 million and $9,556 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,480 million and $3,516 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities for additional information.
[4]	PHI’s consolidated total assets include $33 million and $41 million at December 31, 2018 and 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 $69 million and $102 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities for additional information.
[5]	ACE’s consolidated assets include $23 million and $29 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $59 million and $90 million at December 31, 2018 and 2017, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities for additional information.

Variable Interest Entities Variable Intereste Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

^[1]

$ 1,069

$ 1,134

Exelon's ownership interest in VIE

^[1]

259

265

^[1]

223

251

Other ownership interests in VIE

^[1]

587

618

Carrying amount of equity method investments

Contract intangible asset

223

251

Net assets pledged for Zion Station decommissioning(b)

Commercial Agreement Variable Interest Entities [Member]

^[2]

597

625

Exelon's ownership interest in VIE

Other ownership interests in VIE

560

588

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

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]

472

509

Exelon's ownership interest in VIE

222

228

223

251

Other ownership interests in VIE

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

Equity Investment VIE [Member] | Contract intangible asset

223

251

Equity Investment VIE [Member] | Net assets pledged for Zion Station decommissioning(b)

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

Held-to-maturity Securities Pledged as Collateral

^[3]

Accounts Payable, Interest-bearing, Noncurrent

$ 9

$ 37

[1]	These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
[2]	These items represent amounts in 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 $9 million and $39 million as of December 31, 2018 and December 31, 2017, respectively; offset by payables to ZionSolutions LLC of $9 million and $37 million as of December 31, 2018 and December 31, 2017, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE.
[3]	(a)Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized gains and losses associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.

Revenue Recognition Revenue Recognition - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Gross	$ 32	$ 26
Capitalized Contract Cost, Amortization	22	30
Exelon Generation Co L L C [Member]
Capitalized Contract Cost [Line Items]
Capitalized Contract Cost, Gross	32	26
Capitalized Contract Cost, Amortization	$ 22	$ 30

Revenue Recognition Contract Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Change in Contract with Customer, Asset and Liability [Abstract]
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	$ 50
Contract with Customer, Asset, Reclassified to Receivable	(146)
Contract with Customer, Asset, Net, Current	187	$ 283
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	179
Contract with Customer, Liability, Current	27	35
Contract with Customer, Liability, Change in Timeframe, Performance Obligation Satisfied, Revenue Recognized	(187)
Exelon Generation Co L L C [Member]
Change in Contract with Customer, Asset and Liability [Abstract]
Contract with Customer, Asset, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	50
Contract with Customer, Asset, Reclassified to Receivable	(146)
Contract with Customer, Asset, Net, Current	187	283
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Measure of Progress	465
Contract with Customer, Liability, Current	42	$ 35
Contract with Customer, Liability, Change in Timeframe, Performance Obligation Satisfied, Revenue Recognized	$ (458)

Regulatory Matters Regulatory Matters- Narrative (Details)

1 Months Ended

3 Months Ended

7 Months Ended

9 Months Ended

12 Months Ended

48 Months Ended

60 Months Ended

78 Months Ended

Jan. 15, 2019

USD ($)

Jan. 04, 2019

USD ($)

Dec. 20, 2018

USD ($)

Dec. 04, 2018

USD ($)

Nov. 19, 2018

USD ($)

Sep. 07, 2018

USD ($)

Aug. 21, 2018

USD ($)

Jul. 01, 2018

USD ($)

Jun. 27, 2018

USD ($)

Jun. 08, 2018

USD ($)

Apr. 20, 2018

USD ($)

^[7]

Apr. 17, 2018

USD ($)

^[7]

Apr. 16, 2018

USD ($)

Mar. 29, 2018

USD ($)

Mar. 08, 2018

USD ($)

^[7]

Mar. 02, 2018

USD ($)

Feb. 09, 2018

USD ($)

Feb. 06, 2018

USD ($)

Jan. 31, 2018

USD ($)

Jan. 18, 2018

USD ($)

Dec. 19, 2017

USD ($)

Dec. 18, 2017

USD ($)

Nov. 16, 2017

USD ($)

Apr. 30, 2016

USD ($)

Dec. 31, 2018

USD ($)

Sep. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2017

USD ($)

Sep. 30, 2018

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2022

USD ($)

Dec. 31, 2023

USD ($)

Dec. 31, 2023

USD ($)

Jul. 21, 2017

USD ($)

Aug. 31, 2010

USD ($)

Regulatory Matters Additional Narrative Information [Line Items]

$ 127,000,000

9,459,000,000

$ 9,288,000,000

9,459,000,000

$ 9,288,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

14,000,000

(10,000,000)

$ 76,000,000

35,000,000

644,000,000

523,000,000

644,000,000

523,000,000

9,559,000,000

9,865,000,000

9,559,000,000

9,865,000,000

8,814,000,000

$ 9,403,000,000

$ 8,076,000,000

$ 9,693,000,000

8,384,000,000

$ 8,768,000,000

$ 7,665,000,000

$ 8,747,000,000

35,985,000,000

33,565,000,000

31,366,000,000

7,000,000

^[1]

16,000,000

^[1]

143,000,000

10,203,000,000

10,388,000,000

10,203,000,000

10,388,000,000

3,800,000,000

3,532,000,000

3,800,000,000

3,532,000,000

7,594,000,000

7,584,000,000

8,553,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Regulatory Matters Additional Narrative Information [Line Items]

176,000,000

DC PLUG charge

Fair value of long-term debt

159,000,000

190,000,000

159,000,000

190,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Advanced Metering Infrastructure Legacy Meter Costs [Member]

758,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Electric Energy and Natural Gas Costs

328,000,000

223,000,000

328,000,000

223,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Regulatory Matters Additional Narrative Information [Line Items]

193,000,000

47,000,000

193,000,000

47,000,000

Merger integration costs

Energy efficiency and demand response programs

42,000,000

45,000,000

42,000,000

45,000,000

Regulatory Matters Additional Narrative Information [Line Items]

545,000,000

596,000,000

545,000,000

596,000,000

Regulatory Matters Additional Narrative Information [Line Items]

4,670,000,000

4,829,000,000

3,785,000,000

Regulatory Matters Additional Narrative Information [Line Items]

5,069,000,000

5,278,000,000

4,579,000,000

5,512,000,000

4,657,000,000

4,750,000,000

4,216,000,000

4,878,000,000

20,437,000,000

18,500,000,000

17,757,000,000

$ 235,000,000

5,000,000

^[1]

22,000,000

^[1]

37,000,000

1,847,000,000

1,773,000,000

1,847,000,000

1,773,000,000

Exelon Generation Co L L C [Member] | Conowingo [Member]

2,242,000,000

2,259,000,000

3,078,000,000

Regulatory Matters Additional Narrative Information [Line Items]

License Costs

37,000,000

Exelon Generation Co L L C [Member] | One-Time Revenue Adjustment [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Exelon Generation Co L L C [Member] | PJM Transmission Rate Design Settlement [Member]

$ 101,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Exelon Generation Co L L C [Member] | Minimum [Member]

^[2]

41,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Exelon Generation Co L L C [Member] | Maximum [Member]

3,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Exelon Generation Co L L C [Member] | Zero emission credit costs

7,000,000

Regulatory Matters Additional Narrative Information [Line Items]

438,000,000

$ 311,000,000

Other Revenue, Net

150,000,000

373,000,000

Regulatory Matters Additional Narrative Information [Line Items]

SocialCarbonCost

16.50

Public Utilities, Requested Rate Increase (Decrease), Amount

^[3]

$ (44,000,000)

Cap on Equity Component of Rate of Return on Common Equity in Federal Energy Regulatory Committee Complaint

55.00%

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

^[3],[4]

$ (26,000,000)

Public Utilities, Approved Return on Equity, Percentage

^[3],[5]

11.50%

1,279,000,000

$ 1,279,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

$ 0

3,000,000

293,000,000

249,000,000

293,000,000

249,000,000

6,050,000,000

6,328,000,000

6,050,000,000

6,328,000,000

1,373,000,000

1,598,000,000

1,398,000,000

1,512,000,000

1,309,000,000

1,571,000,000

1,357,000,000

1,298,000,000

5,882,000,000

5,536,000,000

5,254,000,000

$ 170,000,000

^[1],[6]

1,000,000

^[1],[6]

(6,000,000)

6,343,000,000

6,577,000,000

6,343,000,000

6,577,000,000

^[3]

18,000,000

$ 201,000,000

607,000,000

568,000,000

607,000,000

568,000,000

Commonwealth Edison Co [Member] | Electric Distribution [Member]

2,126,000,000

2,250,000,000

2,734,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

(58,000,000)

Public Utilities, Approved Rate Increase (Decrease), Amount

34,000,000

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

^[7]

$ (24,000,000)

$ (23,000,000)

Public Utilities, Requested Equity Capital Structure, Percentage

8.69%

Commonwealth Edison Co [Member] | Electric Transmission [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | PJM Transmission Rate Design Settlement [Member]

69,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | DC PLUG charge

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Fair value of long-term debt

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Electric Energy and Natural Gas Costs

136,000,000

155,000,000

136,000,000

155,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Merger integration costs

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Energy efficiency and demand response programs

Regulatory Matters Additional Narrative Information [Line Items]

Regulatory Matters Additional Narrative Information [Line Items]

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

22,000,000

410,000,000

175,000,000

141,000,000

175,000,000

141,000,000

421,000,000

549,000,000

421,000,000

549,000,000

765,000,000

757,000,000

653,000,000

866,000,000

729,000,000

715,000,000

630,000,000

796,000,000

3,038,000,000

2,870,000,000

2,994,000,000

1,000,000

^[1]

4,000,000

^[1]

5,000,000

Public Utilities, Requested Equity Capital Structure, Percentage

596,000,000

690,000,000

$ 596,000,000

690,000,000

11.00%

$ 6,000,000

$ 71,000,000

370,000,000

$ 370,000,000

370,000,000

PECO Energy Co [Member] | Electric Distribution [Member]

849,000,000

732,000,000

686,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[7]

$ 82,000,000

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

^[7]

$ 25,000,000

PECO Energy Co [Member] | Gas Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Electric Transmission [Member]

$ 4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | PJM Transmission Rate Design Settlement [Member]

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | DC PLUG charge

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Fair value of long-term debt

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Electric Energy and Natural Gas Costs

36,000,000

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Merger integration costs

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Energy efficiency and demand response programs

Regulatory Matters Additional Narrative Information [Line Items]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[3]

10,000,000

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

^[3],[4],[8]

$ 26,000,000

Public Utilities, Approved Return on Equity, Percentage

10.50%

Proposed Capital Expenditure

$ 12,000,000

571,000,000

Estimated number of smart meters to be installed

7,000,000

81,000,000

Total smart grid smart meter investment grant awarded

$ 480,000,000

Doe Reimbursements

$ 200,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

5,000,000

77,000,000

62,000,000

77,000,000

62,000,000

1,192,000,000

1,101,000,000

1,192,000,000

1,101,000,000

799,000,000

731,000,000

662,000,000

977,000,000

813,000,000

738,000,000

674,000,000

951,000,000

3,169,000,000

3,176,000,000

3,233,000,000

1,000,000

^[1],[6]

4,000,000

^[1],[6]

(1,000,000)

1,269,000,000

1,163,000,000

1,269,000,000

1,163,000,000

^[3]

4,000,000

295,000,000

265,000,000

295,000,000

265,000,000

Baltimore Gas and Electric Company [Member] | Subsequent Event [Member]

959,000,000

882,000,000

934,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 200,000,000

Proposed Capital Expenditure

$ 732,000,000

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

Regulatory Matters Additional Narrative Information [Line Items]

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

$ 72,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 61,000,000

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

$ 43,000,000

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

$ 31,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | PJM Transmission Rate Design Settlement [Member]

18,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Difference between Carrying Value and Fair Value [Member]

51,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | DC PLUG charge

133,000,000

139,000,000

133,000,000

139,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Fair value of long-term debt

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | AMI programs - Deployment Costs

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

52,000,000

Baltimore Gas and Electric Company [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Electric Energy and Natural Gas Costs

48,000,000

53,000,000

56,000,000

53,000,000

48,000,000

53,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Merger integration costs

16,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Energy efficiency and demand response programs

6,000,000

Regulatory Matters Additional Narrative Information [Line Items]

285,000,000

Regulatory Matters Additional Narrative Information [Line Items]

444,000,000

3,047,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

14,000,000

(17,000,000)

27,000,000

84,000,000

56,000,000

84,000,000

56,000,000

1,864,000,000

1,872,000,000

1,864,000,000

1,872,000,000

1,117,000,000

1,361,000,000

1,076,000,000

1,251,000,000

1,121,000,000

1,310,000,000

1,074,000,000

1,175,000,000

4,805,000,000

4,679,000,000

^[1],[6]

(6,000,000)

^[1],[6]

28,000,000

Impairment of Long-Lived Assets to be Disposed of

1,948,000,000

1,928,000,000

1,948,000,000

1,928,000,000

25,000,000

496,000,000

348,000,000

496,000,000

348,000,000

Pepco Holdings LLC [Member] | PJM Transmission Rate Design Settlement [Member]

1,375,000,000

1,396,000,000

Regulatory Matters Additional Narrative Information [Line Items]

84,000,000

Regulatory Matters Additional Narrative Information [Line Items]

$ (5,000,000)

3,643,000,000

4,679,000,000

^[6]

69,000,000

(18,000,000)

^[1]

Pepco Holdings LLC [Member] | DC PLUG charge

$ 1,008,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Fair value of long-term debt

159,000,000

190,000,000

159,000,000

190,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

569,000,000

619,000,000

569,000,000

619,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Electric Energy and Natural Gas Costs

120,000,000

134,000,000

120,000,000

134,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Merger integration costs

93,000,000

30,000,000

93,000,000

30,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Energy efficiency and demand response programs

39,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member]

255,000,000

310,000,000

255,000,000

310,000,000

Regulatory Matters Additional Narrative Information [Line Items]

320,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

6,000,000

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

^[4]

$ 8,000,000

Public Utilities, Approved Return on Equity, Percentage

^[5]

10.50%

Projected Capital Expenditures

500,000,000

891,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

$ 14,000,000

(17,000,000)

(12,000,000)

14,000,000

7,000,000

3,000,000

7,000,000

3,000,000

822,000,000

829,000,000

822,000,000

829,000,000

531,000,000

628,000,000

523,000,000

557,000,000

510,000,000

604,000,000

514,000,000

530,000,000

2,239,000,000

2,158,000,000

2,186,000,000

Alternative Net Capital Requirement

829,000,000

832,000,000

829,000,000

832,000,000

250,000,000

Capital ProjectFundedByBonds

187,500,000

30,000,000

$ 127,000,000

CapitalProjectFundedByAgency

62,500,000

2,000,000

214,000,000

139,000,000

214,000,000

139,000,000

Potomac Electric Power Company [Member] | Electric Distribution [Member]

656,000,000

628,000,000

586,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 30,000,000

$ 66,000,000

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

$ 4,000,000

$ (15,000,000)

$ (24,000,000)

$ 3,000,000

Potomac Electric Power Company [Member] | Electric Transmission [Member]

$ 39,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | PJM Transmission Rate Design Settlement [Member]

13,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | DC PLUG charge

84,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | MergerIntegrationCostsToBeRecoveredInDCServiceTerritory [Member]

159,000,000

190,000,000

159,000,000

190,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Fair value of long-term debt

9,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | MergerIntegrationCostsToBeRecoveredInMarylandServiceTerritory [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

9,000,000

11,000,000

9,000,000

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Electric Energy and Natural Gas Costs

90,000,000

100,000,000

90,000,000

100,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Merger integration costs

84,000,000

8,000,000

84,000,000

8,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Energy efficiency and demand response programs

18,000,000

20,000,000

18,000,000

20,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member]

188,000,000

229,000,000

188,000,000

229,000,000

Regulatory Matters Additional Narrative Information [Line Items]

120,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

14,000,000

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

^[4]

$ 27,000,000

Public Utilities, Approved Return on Equity, Percentage

^[5]

10.50%

314,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

$ 0

2,000,000

6,000,000

59,000,000

42,000,000

59,000,000

42,000,000

606,000,000

593,000,000

606,000,000

593,000,000

331,000,000

328,000,000

289,000,000

384,000,000

330,000,000

327,000,000

282,000,000

362,000,000

1,332,000,000

1,300,000,000

1,277,000,000

^[1],[6]

(7,000,000)

^[1],[6]

20,000,000

665,000,000

635,000,000

665,000,000

635,000,000

13,000,000

111,000,000

82,000,000

111,000,000

82,000,000

Delmarva Power & Light Company [Member] | Electric Distribution [Member]

364,000,000

428,000,000

349,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[7]

$ (7,000,000)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 13,000,000

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

$ 12,000,000

^[7]

$ 19,000,000

Public Utilities, Approved Return on Equity, Percentage

9.50%

Delmarva Power & Light Company [Member] | Gas Distribution [Member]

19,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[7]

$ (4,000,000)

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

^[7]

4,000,000

Delmarva Power & Light Company [Member] | Electric Transmission [Member]

$ 7,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | PJM Transmission Rate Design Settlement [Member]

12,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | DC PLUG charge

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | Fair value of long-term debt

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | Electric Energy and Natural Gas Costs

30,000,000

34,000,000

30,000,000

34,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | Merger integration costs

7,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | Energy efficiency and demand response programs

11,000,000

10,000,000

11,000,000

10,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member]

67,000,000

81,000,000

67,000,000

81,000,000

Regulatory Matters Additional Narrative Information [Line Items]

89,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 40,000,000

4,000,000

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

^[4]

$ 0

Public Utilities, Approved Return on Equity, Percentage

^[5]

10.50%

430,000,000

Amount of Impairment to Carrying Amount of Regulatory Assets

$ 0

7,000,000

18,000,000

11,000,000

18,000,000

11,000,000

402,000,000

411,000,000

402,000,000

411,000,000

254,000,000

406,000,000

265,000,000

$ 310,000,000

271,000,000

$ 370,000,000

$ 270,000,000

$ 275,000,000

1,236,000,000

1,186,000,000

1,257,000,000

^[1],[6]

(6,000,000)

^[1],[6]

19,000,000

420,000,000

422,000,000

420,000,000

422,000,000

(4,000,000)

$ 23,000,000

154,000,000

118,000,000

154,000,000

118,000,000

Atlantic City Electric Company [Member] | Subsequent Event [Member]

335,000,000

312,000,000

$ 311,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

$ 338,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[9]

$ 122,000,000

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

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | PJM Transmission Rate Design Settlement [Member]

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | DC PLUG charge

$ 0

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Fair value of long-term debt

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Advanced Metering Infrastructure Legacy Meter Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Electric Energy and Natural Gas Costs

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Merger integration costs

9,000,000

15,000,000

9,000,000

15,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Energy efficiency and demand response programs

10,000,000

9,000,000

10,000,000

9,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member]

$ 0

Regulatory Matters Additional Narrative Information [Line Items]

One-Time Revenue Adjustment [Member] | Maximum [Member]

$ 111,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

76,000,000

One-Time Revenue Adjustment [Member] | Commonwealth Edison Co [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

51,000,000

One-Time Revenue Adjustment [Member] | Baltimore Gas and Electric Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

15,000,000

One-Time Revenue Adjustment [Member] | Pepco Holdings LLC [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

10,000,000

One-Time Revenue Adjustment [Member] | Potomac Electric Power Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

3,000,000

One-Time Revenue Adjustment [Member] | Delmarva Power & Light Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

5,000,000

One-Time Revenue Adjustment [Member] | Atlantic City Electric Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

$ 2,000,000

[1]	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.
[2]	Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.
[3]	The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.
[4]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246MzY0MUFFQzNGNTE3Mzk3OTI2RjIxNTRFRUQyNkYyMzMM}
[5]	As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
[6]	(b)For the year ended December 31, 2017, includes deferrals of previously incurred integration costs as regulatory assets of $24 million, $8 million, $8 million, and $8 million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $8 million, $6 million, $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information.
[7]	Includes the annual ongoing TCJA tax savings further discussed below.
[8]	BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE.
[9]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246NUYyM0EwMDI1MDhGQUUyMUZEMzExNTNGOUY0NjExNDUM}

Regulatory Matters Regulatory Matters - Annual Electric Distribution/Transmission Filings (Details) - USD ($)
$ in Millions

12 Months Ended

Jan. 15, 2019

Dec. 04, 2018

Nov. 19, 2018

Sep. 07, 2018

Aug. 21, 2018

Jun. 27, 2018

May 31, 2018

Apr. 20, 2018

^[4]

Apr. 17, 2018

Apr. 16, 2018

Mar. 08, 2018

^[4]

Mar. 02, 2018

Feb. 09, 2018

Feb. 06, 2018

Jan. 31, 2018

Jan. 18, 2018

Dec. 19, 2017

Dec. 18, 2017

Nov. 16, 2017

Dec. 31, 2018

Dec. 31, 2017

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

$ (44)

$ 201

Cap on Equity Component of Rate of Return on Common Equity in Federal Energy Regulatory Committee Complaint

^[1]

$ 18

55.00%

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

^[1],[2]

$ (26)

Public Utilities, Approved Equity Capital Structure, Percentage

^[1]

8.32%

Public Utilities, Approved Return on Equity, Percentage

^[1],[3]

11.50%

Commonwealth Edison Co [Member] | Electric Distribution [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (58)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 34

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

^[4]

$ (24)

$ (23)

Public Utilities, Approved Equity Capital Structure, Percentage

6.52%

Public Utilities, Requested Equity Capital Structure, Percentage

8.69%

Commonwealth Edison Co [Member] | Electric Transmission [Member]

Public Utilities, General Disclosures [Line Items]

$ 69

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

Proposed Capital Expenditure

^[1]

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

^[1],[2],[5]

$ 26

Public Utilities, Approved Equity Capital Structure, Percentage

^[1]

7.61%

Public Utilities, Approved Return on Equity, Percentage

10.50%

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

Public Utilities, General Disclosures [Line Items]

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

$ 72

Public Utilities, General Disclosures [Line Items]

$ 18

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

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

^[2]

$ 8

Public Utilities, Approved Equity Capital Structure, Percentage

7.82%

Public Utilities, Approved Return on Equity, Percentage

^[3]

10.50%

Potomac Electric Power Company [Member] | Electric Distribution [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 30

$ 66

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

$ 39

$ 4

$ (15)

$ (24)

^[4]

$ 3

Public Utilities, Requested Return on Equity, Percentage

10.30%

9.50%

9.525%

Potomac Electric Power Company [Member] | Electric Transmission [Member]

Public Utilities, General Disclosures [Line Items]

$ 13

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

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

^[2]

$ 27

Public Utilities, Approved Equity Capital Structure, Percentage

7.29%

Public Utilities, Approved Return on Equity, Percentage

^[3]

10.50%

Delmarva Power & Light Company [Member] | Electric Distribution [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[4]

$ (7)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 19

$ 13

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

$ 12

^[4]

$ 19

Public Utilities, Approved Return on Equity, Percentage

9.50%

Public Utilities, Requested Return on Equity, Percentage

9.70%

Delmarva Power & Light Company [Member] | Electric Transmission [Member]

Public Utilities, General Disclosures [Line Items]

$ 12

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 40

$ 23

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

(4)

^[2]

$ 0

Public Utilities, Approved Equity Capital Structure, Percentage

8.02%

Public Utilities, Approved Return on Equity, Percentage

^[3]

10.50%

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

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[6]

$ 122

Public Utilities, Requested Return on Equity, Percentage

10.10%

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

Public Utilities, General Disclosures [Line Items]

$ 11

[1]	The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246MzY0MUFFQzNGNTE3Mzk3OTI2RjIxNTRFRUQyNkYyMzMM}
[3]	As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
[4]	Includes the annual ongoing TCJA tax savings further discussed below.
[5]	BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE.
[6]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246NUYyM0EwMDI1MDhGQUUyMUZEMzExNTNGOUY0NjExNDUM}

Regulatory Matters Regulatory Matters - Schedule of Regulatory Asset Impairment (Details) $ in Millions	Dec. 31, 2017 USD ($)
Amount of Impairment to Carrying Amount of Regulatory Assets	$ 35
Commonwealth Edison Co [Member]
Amount of Impairment to Carrying Amount of Regulatory Assets	3
Baltimore Gas and Electric Company [Member]
Amount of Impairment to Carrying Amount of Regulatory Assets	5
Pepco Holdings LLC [Member]
Amount of Impairment to Carrying Amount of Regulatory Assets	27
Potomac Electric Power Company [Member]
Amount of Impairment to Carrying Amount of Regulatory Assets	14
Delmarva Power & Light Company [Member]
Amount of Impairment to Carrying Amount of Regulatory Assets	6
Atlantic City Electric Company [Member]
Amount of Impairment to Carrying Amount of Regulatory Assets	$ 7

Regulatory Matters Regulatory Matters - Estimated Commitments related to PJM Agreements (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Jun. 30, 2018

Dec. 31, 2017

Mar. 31, 2017

$ 1,256

$ 1,132

127

3,800

3,532

9,459

9,288

10,203

10,388

562

321

1,847

1,773

320

266

607

568

1,279

6,343

6,577

151

105

370

410

596

690

295

265

571

1,269

1,163

214

139

891

829

832

111

314

665

635

154

118

430

420

422

177

206

$ 444

496

348

3,047

1,948

$ 1,928

$ 220

PJM Transmission Rate Design Settlement [Member] | Exelon Generation Co L L C [Member]

176

^[1]

Accounts Receivable, Gross, Current

^[1]

$ 16

PJM Transmission Rate Design Settlement [Member] | Commonwealth Edison Co [Member]

122

PJM Transmission Rate Design Settlement [Member] | PECO Energy Co [Member]

PJM Transmission Rate Design Settlement [Member] | Baltimore Gas and Electric Company [Member]

PJM Transmission Rate Design Settlement [Member] | Potomac Electric Power Company [Member]

PJM Transmission Rate Design Settlement [Member] | Delmarva Power & Light Company [Member]

PJM Transmission Rate Design Settlement [Member] | Atlantic City Electric Company [Member]

PJM Transmission Rate Design Settlement [Member] | Pepco Holdings LLC [Member]

PJM Transmission Rate Design Settlement [Member] | Exelon Generation Co L L C [Member]

136

PJM Transmission Rate Design Settlement [Member] | Commonwealth Edison Co [Member]

^[1]

PJM Transmission Rate Design Settlement [Member] | PECO Energy Co [Member]

PJM Transmission Rate Design Settlement [Member] | Baltimore Gas and Electric Company [Member]

PJM Transmission Rate Design Settlement [Member] | Potomac Electric Power Company [Member]

PJM Transmission Rate Design Settlement [Member] | Delmarva Power & Light Company [Member]

PJM Transmission Rate Design Settlement [Member] | Atlantic City Electric Company [Member]

PJM Transmission Rate Design Settlement [Member] | Pepco Holdings LLC [Member]

PJM Transmission Rate Design Settlement [Member] | Exelon Generation Co L L C [Member]

221

PJM Transmission Rate Design Settlement [Member] | Commonwealth Edison Co [Member]

^[1]

PJM Transmission Rate Design Settlement [Member] | PECO Energy Co [Member]

122

PJM Transmission Rate Design Settlement [Member] | Baltimore Gas and Electric Company [Member]

PJM Transmission Rate Design Settlement [Member] | Potomac Electric Power Company [Member]

PJM Transmission Rate Design Settlement [Member] | Delmarva Power & Light Company [Member]

PJM Transmission Rate Design Settlement [Member] | Atlantic City Electric Company [Member]

PJM Transmission Rate Design Settlement [Member] | Pepco Holdings LLC [Member]

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

$ 14

[1]	Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.

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

Dec. 31, 2018

Dec. 31, 2017

$ 65

$ 69

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

^[1]

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

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

^[2]

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

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

^[3]

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

^[3]

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

12 Months Ended

60 Months Ended

Jan. 15, 2019

Jan. 04, 2019

Dec. 20, 2018

Dec. 04, 2018

Sep. 07, 2018

Jun. 27, 2018

Jun. 08, 2018

May 31, 2018

Apr. 20, 2018

^[4]

Apr. 17, 2018

Apr. 16, 2018

Mar. 29, 2018

Mar. 08, 2018

^[4]

Feb. 09, 2018

Dec. 19, 2017

Dec. 18, 2017

Nov. 16, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2023

Regulatory Matters Completed Rate Cases [Line Items]

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

^[1],[2]

$ (26)

Public Utilities, Approved Equity Capital Structure, Percentage

^[1]

8.32%

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

$ (44)

Public Utilities, Approved Return on Equity, Percentage

^[1],[3]

11.50%

Commonwealth Edison Co [Member] | Electric Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

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

^[4]

$ (24)

$ (23)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 34

Public Utilities, Approved Equity Capital Structure, Percentage

6.52%

Public Utilities, Requested Equity Capital Structure, Percentage

8.69%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (58)

Regulatory Matters Completed Rate Cases [Line Items]

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

$ 22

Public Utilities, Requested Equity Capital Structure, Percentage

11.00%

PECO Energy Co [Member] | Electric Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

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

^[4]

$ 25

Public Utilities, Requested Rate Increase (Decrease), Amount

^[4]

$ 82

Regulatory Matters Completed Rate Cases [Line Items]

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

^[1],[2],[5]

$ 26

Public Utilities, Approved Equity Capital Structure, Percentage

^[1]

7.61%

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

$ 10

Public Utilities, Approved Return on Equity, Percentage

10.50%

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

Regulatory Matters Completed Rate Cases [Line Items]

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

$ 43

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 61

Public Utilities, Requested Return on Equity, Percentage

9.80%

Regulatory Matters Completed Rate Cases [Line Items]

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

^[2]

$ 8

Public Utilities, Approved Equity Capital Structure, Percentage

7.82%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 6

Public Utilities, Approved Return on Equity, Percentage

^[3]

10.50%

Potomac Electric Power Company [Member] | Electric Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

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

$ 4

$ (15)

$ (24)

^[4]

$ 3

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 30

$ 66

Public Utilities, Requested Return on Equity, Percentage

10.30%

9.50%

9.525%

Regulatory Matters Completed Rate Cases [Line Items]

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

^[2]

$ 27

Public Utilities, Approved Equity Capital Structure, Percentage

7.29%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 14

Public Utilities, Approved Return on Equity, Percentage

^[3]

10.50%

Delmarva Power & Light Company [Member] | Electric Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

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

$ 12

^[4]

$ 19

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 13

Public Utilities, Requested Rate Increase (Decrease), Amount

^[4]

$ (7)

Public Utilities, Requested Return on Equity, Percentage

9.70%

Public Utilities, Approved Return on Equity, Percentage

9.50%

Delmarva Power & Light Company [Member] | Gas Distribution [Member]

Regulatory Matters Completed Rate Cases [Line Items]

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

^[4]

$ 4

Public Utilities, Requested Rate Increase (Decrease), Amount

^[4]

$ (4)

Public Utilities, Requested Return on Equity, Percentage

9.70%

Subsequent Event [Member] | Baltimore Gas and Electric Company [Member]

Regulatory Matters Completed Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 200

[1]	The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246MzY0MUFFQzNGNTE3Mzk3OTI2RjIxNTRFRUQyNkYyMzMM}
[3]	As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
[4]	Includes the annual ongoing TCJA tax savings further discussed below.
[5]	BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to specifically designated load by BGE.

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

12 Months Ended

Jan. 15, 2019

Nov. 19, 2018

Aug. 21, 2018

May 31, 2018

Apr. 17, 2018

Dec. 19, 2017

Dec. 31, 2018

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 40

$ 4

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

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

$ 122

Public Utilities, Requested Return on Equity, Percentage

10.10%

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 6

Potomac Electric Power Company [Member] | Electric Distribution [Member]

Regulatory Matters Pending Rate Cases [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 30

$ 66

Public Utilities, Requested Return on Equity, Percentage

10.30%

9.50%

9.525%

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246NUYyM0EwMDI1MDhGQUUyMUZEMzExNTNGOUY0NjExNDUM}

Regulatory Matters Regulatory Matters - Schedule of TCJA Savings (Details) - USD ($) $ in Millions													3 Months Ended
	Sep. 07, 2018	Aug. 29, 2018	Jul. 01, 2018	Jun. 27, 2018	Apr. 20, 2018	Mar. 29, 2018	Mar. 02, 2018	Feb. 09, 2018	Feb. 06, 2018	Feb. 05, 2018	Jan. 31, 2018	Jan. 18, 2018	Sep. 30, 2018
Commonwealth Edison Co [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act												$ 201
PECO Energy Co [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act						$ 71
Atlantic City Electric Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act							$ 23
Gas Distribution [Member] \| PECO Energy Co [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act			$ 4
Gas Distribution [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act											$ 31
Public Utilities, Rate Credit											2
Gas Distribution [Member] \| Delmarva Power & Light Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act								$ 7
Public Utilities, Rate Credit	$ 1
Electric Distribution [Member] \| PECO Energy Co [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Public Utilities, Rate Credit											67
Electric Distribution [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act											$ 72
Electric Distribution [Member] \| Delmarva Power & Light Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act								$ 19
Public Utilities, Rate Credit				$ 3
Electric Distribution [Member] \| Potomac Electric Power Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act									$ 39
Public Utilities, Rate Credit	$ 20				$ 10
Electric Distribution [Member] \| Atlantic City Electric Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Public Utilities, Rate Credit		$ 6
Maryland Service Territory [Member] \| Electric Distribution [Member] \| Delmarva Power & Light Company [Member]
Regulatory Matters Schedule of TCJA Savings [Line Items]
Tax Savings From Tax Cuts and Jobs Act										$ 31			$ 14
Public Utilities, Rate Credit													$ 2

Regulatory Matters Regulatory Matters - Schedule of Revenue Increases (Decreases) (Details) - Commonwealth Edison Co [Member] - USD ($)
$ in Millions

12 Months Ended

Dec. 04, 2018

Apr. 16, 2018

Dec. 31, 2018

Dec. 31, 2017

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

^[1]

$ (44)

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

^[1],[2]

(26)

Electric Distribution [Member]

Public Utilities, General Disclosures [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (58)

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 34

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

^[3]

$ (24)

$ (23)

Public Utilities, Requested Equity Capital Structure, Percentage

8.69%

[1]	The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246MzY0MUFFQzNGNTE3Mzk3OTI2RjIxNTRFRUQyNkYyMzMM}
[3]	Includes the annual ongoing TCJA tax savings further discussed below.

Mergers, Acquisitions and Dispositions Mergers, Acquisitions and Dispositions - Narrative (Details)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Jul. 09, 2018

USD ($)

Apr. 04, 2018

USD ($)

Feb. 28, 2018

USD ($)

Nov. 07, 2017

USD ($)

Mar. 31, 2017

USD ($)

Sep. 01, 2016

USD ($)

Jun. 16, 2016

USD ($)

Mar. 23, 2016

USD ($)

Dec. 31, 2018

USD ($)

Sep. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Sep. 30, 2017

USD ($)

Jun. 30, 2017

USD ($)

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Mar. 23, 2016

USD ($)

Sep. 30, 2017

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 24, 2016

USD ($)

$ 904

$ 0

$ 904

$ 0

777

Deconsolidation, Gain (Loss), Amount

$ 2

$ 213

213

Business Combination, Contingent Consideration, Asset

$ 235

154

208

6,923

Line of credit facility, maximum borrowing capacity

^[1]

143

^[2]

9,704

127

Business Combination, Bargain Purchase, Gain Recognized, Amount

8,814

$ 9,403

$ 8,076

$ 9,693

8,384

$ 8,768

$ 7,665

$ 8,747

35,985

33,565

31,366

233

2,084

3,876

1,196

$ 0

^[3]

$ 0

^[4]

558

^[5],[6]

Wind Assets [Member]

Exelon Corporation Affiliate [Member] | Commitment Adjustment [Member]

Delmarva Power & Light Company [Member] | Wind Assets [Member]

$ 5

Delmarva Power & Light Company [Member] | Remaining Commitment [Member]

120

Exelon Consolidations [Member]

$ 12

Exelon Consolidations [Member] | Rate Bill Credits [Member]

508

Exelon Consolidations [Member] | Other1 [Member]

259

Exelon Consolidations [Member] | Energy Efficiency Program [Member]

Exelon Consolidations [Member] | Charitable Contributions [Member]

117

Exelon Consolidations [Member] | Delivery System Modernization [Member]

Exelon Consolidations [Member] | Green Sustainability Fund [Member]

Exelon Consolidations [Member] | Workforce Development [Member]

Exelon Consolidations [Member] | Remaining Commitment [Member]

128

Pepco Holdings [Member]

$ 7,142

4,670

$ 4,829

3,785

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

$ 453

$ 364

(66)

$ 4,005

Pepco Holdings LLC [Member] | Other Solar Projects [Member]

Pepco Holdings LLC [Member] | Wind Assets [Member]

Pepco Holdings LLC [Member] | Commitments [Member]

100

Pepco Holdings LLC [Member] | Remaining Commitment [Member]

$ 513

513

ConEdison Solutions [Member]

$ 92

$ 257

Net Working Capital

$ 204

Oyster Creek [Member]

897

^[1],[7]

$ 4

^[1],[7]

(1)

799

731

662

977

813

738

674

951

3,169

3,176

3,233

128

125

313

307

294

^[3]

^[4]

^[5],[6]

904

777

Deconsolidation, Gain (Loss), Amount

203

$ 138

213

Proceeds from Divestiture of Businesses

$ 87

Business Combination, Contingent Consideration, Asset

9,518

9,357

9,518

9,357

163

154

208

293

Line of credit facility, maximum borrowing capacity

^[1]

200

Gain (Loss) on Disposition of Property Plant Equipment

Proceeds from Sale of Productive Assets

$ 37

Business Combination, Bargain Purchase, Gain Recognized, Amount

5,069

5,278

4,579

5,512

4,657

4,750

4,216

4,878

20,437

18,500

17,757

233

443

2,798

550

Exelon Generation Co L L C [Member] | FirstEnergy [Member]

^[3]

^[4]

^[5],[6]

Asset Impairment Charges

$ 23

Exelon Generation Co L L C [Member] | Handley [Member]

$ 140

Exelon Generation Co L L C [Member] | Fitzpatrick [Member]

$ 62

Business Combination, Consideration Transferred

$ 289

289

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets

110

Business Combination, Consideration Transferred, Other

179

Business Combination, Bargain Purchase, Gain Recognized, Amount

233

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent

149

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets

114

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

444

Total net assets

522

Exelon Generation Co L L C [Member] | Fitzpatrick [Member] | Cash and Cash Equivalents [Member]

Business Combination, Consideration Transferred

110

125

9,220

8,835

9,220

8,835

^[1],[7]

(6)

^[1],[7]

$ 444

444

1,117

1,361

1,076

1,251

1,121

1,310

1,074

1,175

4,805

4,679

398

362

Impairment of Long-Lived Assets to be Disposed of

^[3]

(8)

^[4]

^[7]

1,153

^[5],[6]

$ 0

Business Combination, Contingent Consideration, Asset

235

Business Combination, Consideration Transferred, Other

^[7]

(18)

^[1]

3,643

4,679

(61)

$ (61)

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member]

^[5],[6]

$ 317

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Rate Bill Credits [Member]

320

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Other1 [Member]

264

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Energy Efficiency Program [Member]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Charitable Contributions [Member]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Delivery System Modernization [Member]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Green Sustainability Fund [Member]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Workforce Development [Member]

531

628

523

557

510

604

514

530

2,239

2,158

2,186

210

205

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

^[3]

(6)

^[4]

125

^[5],[6]

2,100

Fresh-Start Adjustment, Increase (Decrease), Goodwill

400

Potomac Electric Power Company [Member] | Commitments [Member]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member]

$ 73

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Rate Bill Credits [Member]

120

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Other1 [Member]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Energy Efficiency Program [Member]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Charitable Contributions [Member]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Delivery System Modernization [Member]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Green Sustainability Fund [Member]

Potomac Electric Power Company [Member] | Pepco Holdings LLC [Member] | Workforce Development [Member]

(1)

^[1],[7]

(7)

^[1],[7]

331

328

289

384

330

327

282

362

1,332

1,300

1,277

120

121

(9)

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

^[3]

(2)

^[4]

^[5],[6]

1,400

Fresh-Start Adjustment, Increase (Decrease), Goodwill

300

Delmarva Power & Light Company [Member] | Commitments [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Rate Bill Credits [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Commitment Adjustment [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Other1 [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Energy Efficiency Program [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Charitable Contributions [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Delivery System Modernization [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Green Sustainability Fund [Member]

Delmarva Power & Light Company [Member] | Pepco Holdings LLC [Member] | Workforce Development [Member]

(1)

^[1],[7]

(6)

^[1],[7]

254

406

265

310

271

370

270

275

1,236

1,186

1,257

(1)

$ 61

$ 7

$ 0

$ 41

$ 28

(42)

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

^[3]

$ 0

^[4]

$ 110

^[5],[6]

500

Fresh-Start Adjustment, Increase (Decrease), Goodwill

$ (700)

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

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member]

$ 49

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Rate Bill Credits [Member]

111

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Other1 [Member]

101

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Energy Efficiency Program [Member]

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Charitable Contributions [Member]

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Delivery System Modernization [Member]

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Green Sustainability Fund [Member]

Atlantic City Electric Company [Member] | Pepco Holdings LLC [Member] | Workforce Development [Member]

Exelon Corporation Affiliate [Member] | Other commitments [Member]

Electricity Generation Plant, Non-Nuclear [Member]

$ 83

Impairment of Long-Lived Assets to be Disposed of

$ 41

$ 460

[1]	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.
[2]	Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.
[3]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[4]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[5]	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.
[6]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[7]	(b)For the year ended December 31, 2017, includes deferrals of previously incurred integration costs as regulatory assets of $24 million, $8 million, $8 million, and $8 million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $8 million, $6 million, $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information.

Mergers, Acquisitions and Dispositions Purchase Price Allocation Table - FitzPatrick (Details) - USD ($) $ in Millions		12 Months Ended
	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		$ 154	$ 208	$ 6,923
Business Combination, Bargain Purchase, Gain Recognized, Amount		0	233	0
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross		154	208	293
Business Combination, Bargain Purchase, Gain Recognized, Amount		$ 0	233	$ 0
Exelon Generation Co L L C [Member] \| Fitzpatrick [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			110
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets			110
Business Combination, Consideration Transferred, Other	$ 179		54
Business Combination, Consideration Transferred	289		289
Current assets			60
Property, plant and equipment			298
Unamortized energy contracts			807
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets			114
Total assets			1,279
Current liabilities			6
Unamortized energy contract liabilities			(444)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent			149
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedLiabilities			110
Other liabilities			(15)
Total liabilities			757
Total net assets			522
_BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRetirmentObligations			33
Business Combination, Bargain Purchase, Gain Recognized, Amount			233
Exelon Generation Co L L C [Member] \| Fitzpatrick [Member] \| Cash and Cash Equivalents [Member]
Business Acquisition [Line Items]
Payments to Acquire Businesses, Gross			$ 125
Business Combination, Consideration Transferred	$ 110

Mergers, Acquisitions and Dispositions Purchase Price allocation Table - Con Edison (Details) - USD ($) $ in Millions		12 Months Ended
	Sep. 01, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Business Combination Segment Allocation [Line Items]
Payments to Acquire Businesses, Gross		$ 154	$ 208	$ 6,923
Energy Marketing Contracts Assets, Noncurrent		$ 372	$ 395
ConEdison Solutions [Member]
Business Combination Segment Allocation [Line Items]
Payments to Acquire Businesses, Gross	$ 257

Mergers, Acquisitions and Dispositions Merger Transaction Table (Details) - USD ($) $ in Millions		9 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Payments to Acquire Businesses, Gross			$ 154	$ 208	$ 6,923
Pepco Holdings [Member]
Payments to Acquire Businesses, Gross	$ 7,142
Pepco Holdings LLC [Member] \| Pepco Holdings LLC [Member] \| Deferred Compensation, Share-based Payments [Member]
Stockholders' Equity, Other		$ 29

Mergers, Acquisitions and Dispositions Purchase Price Allocation Table - (PHI) (Details) $ in Millions	Mar. 23, 2016 USD ($)
Pepco Holdings LLC [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	$ 4,005

Mergers, Acquisitions and Dispositions Merger Integration Related Costs Table (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 31, 2017

$ 127

^[1]

$ 16

^[1]

$ 143

^[1]

^[1]

^[1],[2]

(1)

$ 444

^[1],[2]

(6)

^[1],[2]

^[1],[2]

(7)

^[1],[2]

^[1],[2]

(6)

^[1],[2]

Predecessor [Member] | Pepco Holdings LLC [Member]

^[1],[2]

$ (6)

Successor [Member] | Pepco Holdings LLC [Member]

^[2]

$ 29

Regulatory Assets [Member] | Baltimore Gas and Electric Company [Member]

^[2]

$ 69

(18)

^[1]

Regulatory Assets [Member] | Pepco Holdings LLC [Member]

Regulatory Assets [Member] | Potomac Electric Power Company [Member]

Regulatory Assets [Member] | Delmarva Power & Light Company [Member]

Regulatory Assets [Member] | Atlantic City Electric Company [Member]

Regulatory Assets [Member] | Commonwealth Edison Co [Member]

$ 8

Potomac Electric Power Company [Member] | Remaining Commitment [Member]

$ 8

Business Acquisition, Pro Forma Revenue

$ 73

[1]

The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

[2]

(b)For the year ended December 31, 2017, includes deferrals of previously incurred integration costs as regulatory assets of $24 million, $8 million, $8 million, and $8 million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $8 million, $6 million, $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016, includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information.

Mergers, Acquisitions and Dispositions Proforma Impact of Merger (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2018

^[3]

Dec. 31, 2017

Dec. 31, 2016

$ 32,342

^[1]

$ 33,823

^[2]

Business Acquisition, Pro Forma Net Income (Loss)

$ 1,562

^[1]

$ 2,618

^[2]

Business Acquisition, Pro Forma Earnings Per Share, Basic

$ 1.69

^[1]

$ 2.85

^[2]

Business Acquisition, Pro Forma Earnings Per Share, Diluted

$ 1.69

^[1]

$ 2.84

^[2]

Consolidation, Eliminations [Member]

$ 0

^[4]

$ 558

^[5],[6]

Business Acquisition, Pro Forma Revenue

171

559

Electric—transmission and distribution

$ 680

$ 92

[1]	The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended
[2]	The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended
[3]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[4]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[5]	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.
[6]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.

Property, Plant and Equipment Property, Plant and Equipment- Annual Depreciation Provisions as Percentage of Average Service Life (Details)

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

2.73%

2.75%

2.73%

Electric—generation

Gas Distribution Equipment

5.37%

^[1]

4.36%

^[1]

5.94%

2.07%

2.10%

2.17%

Common—electric and gas

PECO Energy Co [Member] | Electric—transmission and distribution

6.98%

7.05%

7.41%

PECO Energy Co [Member] | Gas Distribution Equipment

2.35%

2.37%

2.32%

PECO Energy Co [Member] | Common—electric and gas

1.90%

1.89%

1.82%

Baltimore Gas and Electric Company [Member] | Electric—transmission and distribution

5.44%

5.47%

5.11%

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

2.61%

2.58%

2.56%

Baltimore Gas and Electric Company [Member] | Common—electric and gas

2.36%

2.33%

2.45%

Pepco Holdings LLC [Member] | Electric—transmission and distribution

8.50%

8.64%

9.45%

Pepco Holdings LLC [Member] | Gas Distribution Equipment

2.61%

2.63%

2.52%

Pepco Holdings LLC [Member] | Common—electric and gas

1.59%

2.07%

2.57%

Delmarva Power & Light Company [Member] | Electric—transmission and distribution

6.30%

6.50%

8.12%

Delmarva Power & Light Company [Member] | Gas Distribution Equipment

2.77%

2.75%

2.49%

Delmarva Power & Light Company [Member] | Common—electric and gas

1.59%

2.07%

2.57%

3.70%

4.14%

4.99%

[1]	See Note 8 — Early Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.

Property, Plant and Equipment Property, Plant and Equipment- Narrative (Details)

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Electric—generation

Electric—transmission and distribution

5.37%

^[1]

4.36%

^[1]

5.94%

Exelon Generation Co L L C [Member] | Electric—generation

2.73%

2.75%

2.73%

Commonwealth Edison Co [Member] | Electric—transmission and distribution

5.37%

4.36%

5.94%

Potomac Electric Power Company [Member] | Electric—transmission and distribution

2.95%

2.99%

3.03%

Atlantic City Electric Company [Member] | Electric—transmission and distribution

2.40%

2.35%

2.17%

2.45%

2.46%

2.45%

[1]	See Note 8 — Early Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.

Property, Plant and Equipment Property, Plant and Equipment - Summary of Capitalized Software Costs (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capitalized Software [Line Items]
Capitalized Computer Software, Net			$ 810	$ 834
Capitalized Computer Software, Amortization			282	270	$ 255
Exelon Generation Co L L C [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			164	173
Capitalized Computer Software, Amortization			78	73	72
Commonwealth Edison Co [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			206	227
Capitalized Computer Software, Amortization			79	73	62
PECO Energy Co [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			98	111
Capitalized Computer Software, Amortization			37	39	33
Baltimore Gas and Electric Company [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			166	179
Capitalized Computer Software, Amortization			48	46	44
Potomac Electric Power Company [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			26	2
Capitalized Computer Software, Amortization			2	0	0
Pepco Holdings LLC [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			165	133
Capitalized Computer Software, Amortization			33	34
Delmarva Power & Light Company [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			21	1
Capitalized Computer Software, Amortization			2	0	0
Atlantic City Electric Company [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Net			14	1
Capitalized Computer Software, Amortization			$ 1	$ 0	$ 0
Successor [Member] \| Pepco Holdings LLC [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Amortization		$ 29
Predecessor [Member] \| Pepco Holdings LLC [Member]
Capitalized Software [Line Items]
Capitalized Computer Software, Amortization	$ 8

Property, Plant and Equipment Property, Plant and Equipment - Summary of Capitalized Interest and AFUDC (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

^[1]

$ 1,695

$ 1,658

$ 1,678

Allowance for Funds Used During Construction, Capitalized Interest

108

109

108

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

305

263

^[1]

464

502

472

Allowance for Funds Used During Construction, Capitalized Interest

107

^[1]

377

369

469

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

141

130

127

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

130

111

114

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

162

133

137

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

Allowance for Funds Used During Construction, Capitalized Interest

$ 4

$ 9

Successor [Member] | Pepco Holdings LLC [Member]

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

$ 207

$ 35

Predecessor [Member] | Pepco Holdings LLC [Member]

Allowance for Funds Used During Construction, Capitalized Interest

^[1]

$ 68

$ 10

[1]	Includes interest expense to affiliates.

Impairment of Long-lived Assets Impairment of Long-Lived Assets - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended					9 Months Ended
	Mar. 31, 2016	Jun. 30, 2018	Jun. 30, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Sep. 30, 2017	Dec. 31, 2018	Sep. 30, 2018	Dec. 31, 2017	Sep. 30, 2015
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Tangible Asset Impairment Charges					$ 36
Property, plant and equipment, net								$ 76,707		$ 74,202
Gain (Loss) on Contract Termination						$ 4
Finite-Lived Intangible Assets, Gross								1,267		1,228
Estimated residual value of leased assets	$ 356					356
Proceeds From Lease Termination						$ 360
Wind Assets [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Property, plant and equipment, net					60
Property, Plant, and Equipment, Fair Value Disclosure					$ 24
Pepco Holdings LLC [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Impairment of Long-Lived Assets to be Disposed of			$ 25
Property, plant and equipment, net								13,446		12,498
Finite-Lived Intangible Assets, Gross											$ 25
Exelon Generation Co L L C [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Property, plant and equipment, net								$ 23,981		$ 24,906
Constellation Energy Group LLC [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Tangible Asset Impairment Charges	$ 119			$ 15
Electricity Generation Plant, Non-Nuclear [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Impaired Assets to be Disposed of by Method Other than Sale, Carrying Value of Asset									$ 41
Impairment of Long-Lived Assets to be Disposed of		$ 41	$ 460				$ 460

Early Plant Retirements Early Plant Retirements - Narrative (Details) - USD ($) $ in Millions		12 Months Ended
	Oct. 01, 2018	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment [Line Items]
Payments to Acquire Businesses, Gross		$ 154	$ 208	$ 6,923
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Businesses, Gross		$ 154	$ 208	$ 293
Exelon Generation Co L L C [Member] \| Nuclear Plant [Member]
Property, Plant and Equipment [Line Items]
Ownership interest		42.59%
Everett Marine Terminal [Member] \| Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Payments to Acquire Businesses, Gross	$ 81
Business Combination, Separately Recognized Transactions, Net Gains and Losses	$ 75

Early Plant Retirements Early Plant Retirements - Pretax Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 17, 2016

Jun. 16, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Facility Closing [Member] | TMOysterCreek [Member]

$ (112)

$ 947

$ 297

^[1],[2]

539

^[1]

Accretion Expense, Including Asset Retirement Obligations

^[1],[3]

^[1]

^[1]

Facility Closing [Member] | Three Mile Island [Member]

^[1]

628

^[2],[4]

250

^[4]

Accretion Expense, Including Asset Retirement Obligations

^[3],[4]

^[4]

^[4]

Facility Closing [Member] | Clinton and Quad Cities [Member]

^[4]

339

^[2],[5]

712

^[5]

Accretion Expense, Including Asset Retirement Obligations

$ (120)

$ 146

^[3],[5],[6]

^[5],[7]

^[5],[7]

(86)

^[5]

714

Exelon Generation Co L L C [Member] | Facility Closing [Member] | TMOysterCreek [Member]

(178)

948

401

^[1],[2]

539

^[1]

Accretion Expense, Including Asset Retirement Obligations

^[1],[3]

^[1]

^[1]

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

^[1]

$ 628

^[2],[4]

250

^[4]

Accretion Expense, Including Asset Retirement Obligations

^[3],[4]

^[4]

^[4]

Exelon Generation Co L L C [Member] | Facility Closing [Member] | Clinton and Quad Cities [Member]

^[4]

$ 339

^[2],[5]

712

^[5]

Accretion Expense, Including Asset Retirement Obligations

$ (120)

$ 146

^[3],[5],[6]

^[5],[7]

^[5],[7]

(86)

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[5]

$ 714

[1]	Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.
[2]	Reflects incremental accelerated depreciation of plant assets, including any ARC.
[3]	Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional information.
[4]	Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.
[5]	Reflects incremental charges for Clinton and Quad Cities including incremental accelerated depreciation and amortization from June 2, 2016 through December 6, 2016. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation updated the expected economic useful life for both facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates.
[6]	In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million. In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially recorded in June 2016.
[7]	For Quad Cities based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.

Early Plant Retirements Early Plant Retirements - Implications of Potential Early Plant Retirement on Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Implications of Potential Early Plant Retirement [Line Items]
Property, plant and equipment, net	$ 76,707	$ 74,202
Exelon Generation Co L L C [Member]
Implications of Potential Early Plant Retirement [Line Items]
Property, plant and equipment, net	23,981	$ 24,906
Exelon Generation Co L L C [Member] \| Salem [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Inventory, Raw Materials and Supplies, Gross	45
Nuclear Fuel, Net of Amortization	118
Property, plant and equipment, net	538
Construction in Progress, Gross	44
Asset Retirement Obligation	(395)
Exelon Generation Co L L C [Member] \| Mystic Generating Station [Member] \| Facility Closing [Member]
Implications of Potential Early Plant Retirement [Line Items]
Inventory, Raw Materials and Supplies, Gross	30
Nuclear Fuel, Net of Amortization	20
Property, plant and equipment, net	901
Construction in Progress, Gross	9
Asset Retirement Obligation	$ (1)

Jointly Owned Electric Utility Plant - Ownership Interests in Jointly Owned Electric Plants and Transmission Facilities (Details)
$ in Millions

12 Months Ended

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Pennsylvania [Member]

Miles of transmission voltage lines | mi

127

Delaware And New Jersey [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Miles of transmission voltage lines | mi

151.3

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

500

Conemaugh [Member]

Delaware River Crossing [Member]

500

Substation capacity | V

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Miles of transmission voltage lines | mi

2.5

New Freedom Switching [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Electric Transmission [Member] | Pennsylvania [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1],[2]

$ 28

$ 27

^[1],[2]

Electric Transmission [Member] | Delaware And New Jersey [Member]

^[2]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1],[3]

103

102

^[1],[3]

Other Service [Member] | Other Locations [Member]

^[3]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1],[4]

^[1],[4]

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

^[4]

$ 0

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

44.24%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Quad Cities [Member]

42.59%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

75.00%

^[1]

$ 1,131

1,074

^[1]

587

550

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Peach Bottom [Member]

$ 13

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

50.00%

^[1]

$ 1,451

1,417

^[1]

523

461

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Salem [Member]

$ 15

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[5]

42.59%

^[1],[5]

$ 648

631

^[1],[5]

227

205

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Nine Mile Point [Member]

^[5]

$ 44

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

82.00%

^[1]

$ 910

839

^[1]

126

Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Salem [Member]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Wyman [Member]

$ 3

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

5.89%

^[1]

$ 4

^[1]

PECO Energy Co [Member] | Pennsylvania [Member]

$ 0

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Delaware And New Jersey [Member]

22.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Conemaugh [Member]

42.55%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Delaware River Crossing [Member]

20.72%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

42.55%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

7.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Potomac Electric Power Company [Member] | Pennsylvania [Member]

10.56%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Potomac Electric Power Company [Member] | Conemaugh [Member]

27.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Potomac Electric Power Company [Member] | Valley Forge [Member]

9.72%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power & Light Company [Member] | Pennsylvania [Member]

11.90%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power & Light Company [Member] | Delaware And New Jersey [Member]

9.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power & Light Company [Member] | Conemaugh [Member]

1.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power & Light Company [Member] | Delaware River Crossing [Member]

3.72%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power & Light Company [Member] | Merrill Creek [Member]

7.45%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power & Light Company [Member] | Valley Forge [Member]

11.91%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

7.40%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Delaware And New Jersey [Member]

8.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

13.90%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Delaware River Crossing [Member]

3.83%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Merrill Creek [Member]

7.45%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Valley Forge [Member]

4.83%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | New Freedom Switching [Member]

6.60%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

21.78%

[1]	Excludes asset retirement costs and general plant.
[2]	PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.
[3]	PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant substation. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching
[4]	Generation, DPL and ACE own a 44.24%, 11.91% and 4.83% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center.
[5]	Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2018 and 2017.

Intangible Assets - Schedule of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Roll Forward]
Goodwill, Gross	$ 8,660	$ 8,660	$ 8,660
Goodwill, beginning balance	6,677	6,677
Impairment losses	0	0
Goodwill, ending balance	6,677	6,677
Goodwill, Impaired, Accumulated Impairment Loss	1,983	1,983	1,983
Exelon Generation Co L L C [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	47
Goodwill, ending balance	47	47
Commonwealth Edison Co [Member]
Goodwill [Roll Forward]
Goodwill, Gross	4,608	4,608	4,608
Goodwill, beginning balance	2,625	2,625
Impairment losses	0	0
Goodwill, ending balance	2,625	2,625
Goodwill, Impaired, Accumulated Impairment Loss	1,983	1,983	1,983
Delmarva Power & Light Company [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	8
Goodwill, ending balance	8	8
Pepco Holdings LLC [Member]
Goodwill [Roll Forward]
Goodwill, Gross	4,005	4,005	$ 4,005
Goodwill, beginning balance	4,005	4,005
Impairment losses	0
Goodwill, ending balance	$ 4,005	$ 4,005

Intangible Assets - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Nov. 01, 2016	Mar. 24, 2016
Goodwill [Line Items]
Goodwill	$ 6,677	$ 6,677	$ 6,677
Amortization of Intangible Assets	(109)	(237)	(336)
Exelon Generation Co L L C [Member]
Goodwill [Line Items]
Goodwill	47	47
Amortization of Intangible Assets	63	83	79
Commonwealth Edison Co [Member]
Goodwill [Line Items]
Goodwill	2,625	2,625	2,625
Amortization of Intangible Assets	7	7	7
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				30.00%
Pepco Holdings LLC [Member]
Goodwill [Line Items]
Goodwill	4,005	4,005	$ 4,005
Potomac Electric Power Company [Member]
Goodwill [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets					$ 2,100
Fresh-Start Adjustment, Increase (Decrease), Goodwill					400
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				30.00%
Delmarva Power & Light Company [Member]
Goodwill [Line Items]
Goodwill	$ 8	$ 8
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets					1,400
Fresh-Start Adjustment, Increase (Decrease), Goodwill					300
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				20.00%
Atlantic City Electric Company [Member]
Goodwill [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets					500
Fresh-Start Adjustment, Increase (Decrease), Goodwill					$ (700)
Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount				30.00%
Constellation Energy Group LLC [Member] \| Trade Names [Member]
Goodwill [Line Items]
Useful life	10 years

Intangible Assets - Schedule of Other Intangible Assets (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Sep. 30, 2015

$ 1,267

$ 1,228

(1,149)

(1,255)

118

(27)

Exelon Enterprise [Member]

1,267

1,228

^[1]

(32)

^[1]

(20)

^[1]

(4)

^[1]

(23)

Exelon Enterprise [Member] | Licensing Agreements [Member]

^[1]

(21)

^[1]

^[1]

(34)

(25)

^[1]

Exelon Generation Consolidated [Member]

^[1]

Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[1]

^[1]

^[1]

^[1]

^[1]

^[2],[3]

1,957

1,938

^[2],[3]

(1,588)

(1,574)

^[2],[3]

369

364

Exelon Generation Co L L C [Member] | Customer Relationships [Member]

^[2],[3]

1,957

1,938

325

305

(162)

(133)

163

172

Exelon Generation Co L L C [Member] | Trade Names [Member]

325

305

243

(171)

(148)

243

Commonwealth Edison Co [Member] | Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member]

^[1]

^[1]

^[1]

^[1]

^[1]

162

(148)

(141)

PHI Service Co Affiliate [Member]

162

^[1]

(119)

^[1]

(115)

^[1]

(92)

^[1]

(89)

^[1]

(81)

$ 25

Pepco Holdings LLC [Member] | Unamortized Energy Contracts [Member]

$ 25

(1,515)

954

766

(561)

(749)

$ (1,515)

[1]	(a)On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.
[2]	(b)Includes unamortized energy contract assets and liabilities in Exelon's, Generations and PHI's Consolidated Balance Sheets.
[3]	(c)In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement.

Intangible Assets - Summary of Amortization Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 24, 2016

$ (109)

$ (237)

$ (336)

Fresh-Start Adjustment, Increase (Decrease), Goodwill

$ 400

PHI Service Co Affiliate [Member]

(188)

(336)

(430)

Fresh-Start Adjustment, Increase (Decrease), Goodwill

$ 300

Unamortized Energy Contracts [Member]

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[1]

^[1]

$ 14

$ 35

[1]	Included in Operating revenues or Purchased power and fuel in the Registrants’ Consolidated Statements of Operations and Comprehensive Income

Intangible Assets Renewable and Alternative Energy Credits (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Sep. 30, 2015

Finite-Lived Intangible Assets, Accumulated Amortization

$ 1,267

$ 1,228

1,149

1,255

Finite-Lived Intangible Assets, Net

118

(27)

Exelon Generation Co L L C [Member] | Alternative energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Exelon Generation Co L L C [Member] | Renewable energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

270

312

Exelon Generation Co L L C [Member] | Renewable energy credit noncurrent [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Exelon Consolidations [Member] | Alternative energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Exelon Consolidations [Member] | Renewable energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

279

321

Exelon Consolidations [Member] | Renewable energy credit noncurrent [Member]

Acquired Finite-lived Intangible Asset, Residual Value

PECO Energy Co [Member] | Alternative energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

PECO Energy Co [Member] | Renewable energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

PECO Energy Co [Member] | Renewable energy credit noncurrent [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Pepco Holdings LLC [Member] | Alternative energy credit current [Member]

$ 25

Acquired Finite-lived Intangible Asset, Residual Value

Pepco Holdings LLC [Member] | Renewable energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Pepco Holdings LLC [Member] | Renewable energy credit noncurrent [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Exelon Enterprise [Member] | Licensing Agreements [Member]

Finite-Lived Intangible Assets, Accumulated Amortization

^[1]

^[1]

Finite-Lived Intangible Assets, Net

^[1]

Delmarva Power & Light Company [Member] | Alternative energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Delmarva Power & Light Company [Member] | Renewable energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Delmarva Power & Light Company [Member] | Renewable energy credit noncurrent [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Atlantic City Electric Company [Member] | Alternative energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Atlantic City Electric Company [Member] | Renewable energy credit current [Member]

Acquired Finite-lived Intangible Asset, Residual Value

Atlantic City Electric Company [Member] | Renewable energy credit noncurrent [Member]

Acquired Finite-lived Intangible Asset, Residual Value

$ 0

[1]	(a)On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Fair Value, Inputs, Level 3 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash Collateral Posted

$ 76,000,000

$ 81,000,000

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Derivative assets, fair value

^[1],[2]

443,000,000

445,000,000

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

$ (249,000,000)

$ (256,000,000)

0.78

1.27

4.00%

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

86.00%

88.00%

174

124

12.38

12.8

8.00%

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

120.00%

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

10.00%

11.00%

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

277.00%

139.00%

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

^[1],[2]

$ 56,000,000

$ 26,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Cash Collateral Posted

$ 418,000,000

$ 497,000,000

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

^[3]

618,000,000

349,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Derivative assets, fair value

$ 443,000,000

^[1],[2]

$ 445,000,000

^[4],[5]

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]

0.78

1.27

174

124

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

12.38

12.8

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

10.00%

11.00%

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

277.00%

139.00%

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

$ 56,000,000

^[1],[2]

$ 26,000,000

^[4],[5]

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]

174

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

$ (249,000,000)

$ (256,000,000)

4.00%

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

86.00%

88.00%

8.00%

120.00%

[1]	The fair values do not include cash collateral posted on level three positions of $76 million as of December 31, 2018.
[2]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[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.
[4]	The fair values do not include cash collateral posted on level three positions $81 million as of December 31, 2017.
[5]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($)	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	$ 1,171,000,000	$ 1,147,000,000
Forward Power Basis	3.18
Forward Gas Basis	0.64
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	1,171,000,000	1,147,000,000
Exelon Generation Co L L C [Member] \| Fitzpatrick [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Spent Nuclear Fuel Obligation, Noncurrent	$ 119,000,000	$ 114,000,000

Derivative Financial Instruments - Narrative (Details) - USD ($)
$ in Thousands

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Ineffective portion recognized in income

$ 9,000

$ 15,000

$ 14,000

(17,000)

35,000

InterestRateAndForeignExchangeContract [Member]

1,000

6,000

Commodity Contract [Member]

3,000

5,000

299,000

667,000

Credit exposure under off system sales

3,000

Incremental collateral for loss of investment grade credit rating

69,000

Letters of credit posted

367,000

293,000

(47,000)

(35,000)

Incremental collateral for loss of investment grade credit rating

44,000

33,000

Cash collateral posted

418,000

497,000

2,100,000

1,800,000

Interest Rate Fair Value Hedge Asset at Fair Value

7,000

Derivative, Collateral, Obligation to Return Cash

2,000

4,000

Exelon Generation Co L L C [Member] | InterestRateAndForeignExchangeContract [Member]

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

7,000

2,000

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

1,000

Commonwealth Edison Company [Member] | Energy Related Derivative [Member]

$ 548,000

^[1]

$ 923,000

^[2]

Credit Derivative, Collateral Held Directly or by Third Parties

38000000

Commonwealth Edison Company [Member] | Other Contract [Member]

Credit Derivative, Collateral Held Directly or by Third Parties

19000000

Commonwealth Edison Company [Member] | Renewable Energy Program [Member]

Credit Derivative, Collateral Held Directly or by Third Parties

31000000

Incremental collateral for loss of investment grade credit rating

Term of contract

20 years

$ 7,000

Estimated Percent Of Gas Purchases Being Hedged

20.00%

Incremental collateral for loss of investment grade credit rating

$ 39,000

Incremental collateral for loss of investment grade credit rating

11,000

Delmarva Power & Light Company [Member] | Energy Related Derivative [Member]

Brokered Natural Gas Margin Revenue

$ 2,750

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

Estimated Percent Of Gas Purchases Being Hedged

10.00%

Minimum [Member] | Exelon Generation Co L L C [Member]

Expected generation hedged in next twelve months

89.00%

Expected generation hedged in year two

56.00%

Expected generation hedged in year three

32.00%

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

Estimated Percent Of Gas Purchases Being Hedged

20.00%

Maximum [Member] | Exelon Generation Co L L C [Member]

Expected generation hedged in next twelve months

92.00%

Expected generation hedged in year two

59.00%

Expected generation hedged in year three

35.00%

Atlantic City Electric Company [Member] | Exelon Generation Co L L C [Member]

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

$ 5,000

Due From Affiliate Current Electric Gas Utility

30,000

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

Due From Affiliate Current Electric Gas Utility

24,000

Potomac Electric Power Company [Member] | Exelon Generation Co L L C [Member]

Delmarva Power & Light Company [Member] | Exelon Generation Co L L C [Member]

28,000

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

7,000

Derivative, Collateral, Obligation to Return Cash

43,000

$ 12,000

[1]	Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.
[2]	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.

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Mark-to-market derivative assets (noncurrent assets)

$ 804

$ 976

452

337

(475)

(232)

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

(479)

(409)

Mark-to-market derivative assets (noncurrent assets)

804

976

452

334

(449)

(211)

InterestRateAndForeignExchangeContract [Member]

(252)

(174)

Mark-to-market derivative assets (noncurrent assets)

(2)

(5)

(2)

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

InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

(2)

(1)

(2)

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

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

Mark-to-market derivative assets (noncurrent assets)

(2)

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

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

Mark-to-market derivative assets (noncurrent assets)

(4)

(7)

(2)

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

Corporate, Non-Segment [Member] | Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member]

Mark-to-market derivative assets (noncurrent assets)

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

Corporate, Non-Segment [Member] | Not Designated as Hedging Instrument, Economic Hedge [Member] | InterestRateAndForeignExchangeContract [Member]

Mark-to-market derivative assets (noncurrent assets)

(4)

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

(4)

Collateral and Netting | InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

^[1]

(2)

(7)

^[1]

(1)

^[1]

(3)

(7)

^[1]

^[1]

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

^[1]

(3)

(7)

^[1]

$ 0

[1]

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.

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) - Interest Expense [Member] - Fair Value Hedging [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Interest Rate Swap [Member]
Derivative [Line Items]
Gain (Loss) on Fair Value Hedges Recognized in Earnings	$ (11)	$ (13)	$ (9)
Price Risk Derivative [Member]
Derivative [Line Items]
Increase (Decrease) in Fair Value of Hedged Item in Price Risk Fair Value Hedge	$ 20	$ 28	$ 23

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

$ 50

$ 77

Mark-to-market derivative assets (noncurrent assets)

804

976

452

337

(475)

(232)

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

(479)

(409)

Margin Deposit Assets

(94)

(117)

Mark-to-market derivative assets (noncurrent assets)

804

976

452

334

(449)

(211)

Derivative, Collateral, Obligation to Return Cash

(252)

(174)

(26)

(21)

Commodity Contract [Member]

(223)

(235)

Mark-to-market derivative assets (noncurrent assets)

801

973

445

331

1,246

1,304

(473)

(230)

(474)

(407)

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

(947)

(637)

299

667

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

Mark-to-market derivative assets (noncurrent assets)

801

^[1]

973

^[2]

445

^[1]

331

^[2]

1,246

^[1]

1,304

^[2]

(447)

^[1]

(209)

^[2]

(251)

^[1]

(172)

^[2]

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

(698)

^[1]

(381)

^[2]

548

^[1]

923

^[2]

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

Derivative Liability, Collateral, Right to Reclaim Cash, Offset

(357)

(466)

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

Mark-to-market derivative assets (noncurrent assets)

3,505

3,061

1,266

1,164

4,771

4,225

(3,429)

(2,646)

(1,203)

(1,137)

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

(4,632)

(3,783)

139

442

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

Mark-to-market derivative assets (noncurrent assets)

^[3]

^[3]

^[3]

^[3]

(26)

(21)

^[3]

(223)

(235)

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

^[3]

(249)

(256)

^[3]

(249)

(256)

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

Mark-to-market derivative assets (noncurrent assets)

105

146

(74)

(43)

(20)

(10)

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

(94)

(53)

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

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

121

169

Margin Deposit Assets

(94)

(117)

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

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

125

167

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

Mark-to-market derivative assets (noncurrent assets)

^[4]

(2,809)

^[5]

(2,144)

^[6]

^[4]

(862)

^[5]

(845)

^[6]

^[4]

(3,671)

^[5]

(2,989)

^[6]

^[4]

3,056

^[5]

2,480

^[6]

^[4]

972

^[5]

975

^[6]

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

^[4]

4,028

^[5]

3,455

^[6]

^[4]

$ 357

^[5]

$ 466

^[6]

[1]	Current and noncurrent assets are shown net of collateral of $121 million and $51 million, respectively, and current and noncurrent liabilities are shown net of collateral of $125 million and $60 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $357 million at December 31, 2018.
[2]	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.
[3]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[4]	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 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), $(94) million represents variation margin on the exchanges.
[6]	Of the collateral posted/(received), $(117) million represents variation margin on the exchanges

Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

$ (3,026)

^[1]

(182)

$ (144)

$ (2,995)

(2,995)

(3,026)

(26)

(120)

126

$ (753)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(37)

^[1]

(1)

(4)

(38)

(37)

Cash Flow Hedging [Member]

108

1,376

(282)

Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net

(14)

(17)

(1)

Cash Flow Hedging [Member] | Interest Expense [Member]

(2)

(14)

(17)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[2]

Cash Flow Hedging [Member] | Exelon Generation Co L L C [Member]

Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net

(16)

(19)

(1)

Cash Flow Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Expense [Member]

$ (4)

(4)

(16)

$ (19)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

$ 1

^[2]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

$ 1

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	Amount is net of related income tax expense of $1 million for the year ended December 31, 2017.

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (294)	$ (151)	$ (24)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(307)	(167)	(40)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(6)	(9)	(10)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	7	(6)	(10)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(9)	0	0
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(4)	(3)	0
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(317)	(169)	(31)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(270)	(126)	(490)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(47)	(43)	459
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(9)	(9)	(10)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	7	(6)	(10)
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(9)	0	0
Not Designated as Hedging Instrument, Economic Hedge [Member] \| Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (7)	$ (3)	$ 0

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (294)	$ (151)	$ (24)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(307)	(167)	(40)
Not Designated as Hedging Instrument, Trading [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	17	6	2
Not Designated as Hedging Instrument, Trading [Member] \| Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ 0	$ (1)	$ (1)

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

Dec. 31, 2018

Dec. 31, 2017

$ 17

$ 35

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

$ 33

795

133

181

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

1,201

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

^[1]

795

180

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

1,149

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

153

$ 153

[1]	As of December 31, 2018, credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 million of letters of credit. The credit collateral does not include non-liquid collateral.

Derivative Financial Instruments - Net Credit Exposure by Type of Counterparty (Details) - Exelon Generation Co L L C [Member] - Net Exposure [Member] $ in Millions	Dec. 31, 2018 USD ($)
Derivative [Line Items]
Financial institutions	$ 12
Investor-owned utilities, marketers, power producers	737
Energy cooperatives and municipalities	324
Other	76
Total	$ 1,149

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

Dec. 31, 2018

Dec. 31, 2017

Derivative Asset, Fair Value, Gross Liability

^[1]

$ (1,723)

$ (926)

Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements

^[2]

1,105

577

^[3]

$ (618)

$ (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 - Schedule of Notional Amounts Outstanding (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Not Designated as Hedging Instrument, Economic Hedge [Member]

$ 5,991

$ 3,606

Not Designated as Hedging Instrument, Economic Hedge [Member] | Foreign Exchange Contract [Member]

1,688

Not Designated as Hedging Instrument, Economic Hedge [Member] | Interest Rate Swap [Member]

268

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

1,420

^[1]

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

888

Exelon Generation Co L L C [Member] | Not Designated as Hedging Instrument, Economic Hedge [Member] | Interest Rate Swap [Member]

268

Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member]

620

Corporate, Non-Segment [Member] | Not Designated as Hedging Instrument, Economic Hedge [Member]

636

Corporate, Non-Segment [Member] | Not Designated as Hedging Instrument, Economic Hedge [Member] | Foreign Exchange Contract [Member]

800

Corporate, Non-Segment [Member] | Not Designated as Hedging Instrument, Economic Hedge [Member] | Interest Rate Swap [Member]

Corporate, Non-Segment [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member]

800

$ 0

$ 800

[1]

On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon and Generation as of December 31, 2017.

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 30, 2018

Jun. 30, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 31, 2016

Line of credit facility, maximum borrowing capacity

^[1]

$ 9,704

Average Interest Rate on Commercial Paper Borrowings

2.15%

1.24%

1.12%

Credit facility agreements with minority and community banks

$ 1,696

135

$ 128

Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3],[4]

9,000

9,450

Revolving Credit Facility [Member]

427

Line of credit facility, maximum borrowing capacity

$ 500

Exelon Corporate [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

600

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 0

1.93%

1.16%

Line of credit facility, maximum borrowing capacity

$ 200

$ 45

Average Interest Rate on Commercial Paper Borrowings

1.96%

1.23%

1.14%

Credit facility agreements with minority and community banks

$ 49

$ 75

$ 49

Exelon Generation Co L L C [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

5,300

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 0

1.96%

1.23%

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

Exelon Generation Co L L C [Member] | Secured Debt [Member]

$ 545

$ 480

Exelon Generation Co L L C [Member] | Letter of Credit [Member]

159

$ 179

$ 5

Average Interest Rate on Commercial Paper Borrowings

2.14%

1.24%

Credit facility agreements with minority and community banks

$ 2

$ 34

Commonwealth Edison Co [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

1,000

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 0

2.14%

1.24%

Average Interest Rate on Commercial Paper Borrowings

2.24%

1.13%

Credit facility agreements with minority and community banks

$ 0

$ 34

PECO Energy Co [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

600

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 0

2.24%

1.13%

Average Interest Rate on Commercial Paper Borrowings

2.18%

1.28%

0.95%

Credit facility agreements with minority and community banks

$ 1

$ 5

Baltimore Gas and Electric Company [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

600

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 35

$ 77

2.18%

1.28%

Baltimore Gas and Electric Company [Member] | Letter of Credit [Member]

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

$ 2

Line of credit facility, maximum borrowing capacity

$ 1,500

Average Interest Rate on Commercial Paper Borrowings

2.24%

1.06%

0.90%

Credit facility agreements with minority and community banks

$ 8

$ 2

Potomac Electric Power Company [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

300

500

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 40

$ 26

2.24%

1.06%

Average Interest Rate on Commercial Paper Borrowings

2.07%

1.48%

Credit facility agreements with minority and community banks

$ 1

$ 2

Delmarva Power & Light Company [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

300

500

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 0

$ 216

2.07%

1.48%

Average Interest Rate on Commercial Paper Borrowings

2.21%

1.43%

Credit facility agreements with minority and community banks

$ 0

$ 2

Atlantic City Electric Company [Member] | Commercial Paper [Member]

Line of credit facility, maximum borrowing capacity

^[2],[3]

300

350

^[4]

Average Interest Rate on Commercial Paper Borrowings

$ 14

$ 108

2.21%

1.43%

Maximum [Member] | Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

$ 900

Maximum [Member] | Delmarva Power & Light Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

Maximum [Member] | Atlantic City Electric Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

$ 0

[1]	Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.
[2]	At December 31, 2018, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. At December 31, 2017, excludes $128 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $34 million, $34 million, $5 million, $2 million, $2 million, and $2 million, respectively.
[3]	Excludes $545 million and $480 million in bilateral credit facilities at December 31, 2018 and 2017, respectively, and $159 million and $179 million in credit facilities for project finance at December 31, 2018 and 2017, respectively. These credit facilities do not back Generation's commercial paper program.
[4]	Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 30, 2018

Jun. 30, 2018

Dec. 31, 2017

Mar. 31, 2016

Line of credit facility, maximum borrowing capacity

^[1]

$ 9,704

1,696

8,008

Credit facility agreements with minority and community banks

7,687

135

$ 128

Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

$ 500

591

Line of credit facility, maximum borrowing capacity

200

$ 45

Credit facility agreements with minority and community banks

4,097

$ 75

Exelon Generation Co L L C [Member] | Secured Debt [Member]

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

159

179

Exelon Generation Co L L C [Member] | Letter of Credit [Member]

545

480

Exelon Generation Co L L C [Member] | Line of Credit [Member]

Line of credit facility, maximum borrowing capacity

150

192

Credit facility agreements with minority and community banks

998

Credit facility agreements with minority and community banks

998

600

Credit facility agreements with minority and community banks

600

599

Credit facility agreements with minority and community banks

564

Baltimore Gas and Electric Company [Member] | Letter of Credit [Member]

292

Credit facility agreements with minority and community banks

252

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

1,500

299

Credit facility agreements with minority and community banks

299

300

Credit facility agreements with minority and community banks

286

$ 2

Line of Credit [Member] | Exelon Generation Co L L C [Member]

Line of credit facility, maximum borrowing capacity

^[1]

545

Line of Credit [Member] | Exelon Generation Co L L C [Member] | Secured Debt [Member]

353

Line of credit facility, maximum borrowing capacity

^[1]

159

119

Revolving Credit Facility [Member] | Exelon Corporate [Member]

Line of credit facility, maximum borrowing capacity

^[1]

600

Revolving Credit Facility [Member] | Exelon Generation Co L L C [Member]

591

Line of credit facility, maximum borrowing capacity

^[1]

5,300

1,203

Revolving Credit Facility [Member] | Commonwealth Edison Co [Member]

4,097

Line of credit facility, maximum borrowing capacity

^[1]

1,000

Revolving Credit Facility [Member] | PECO Energy Co [Member]

Line of credit facility, maximum borrowing capacity

^[1]

600

Revolving Credit Facility [Member] | Baltimore Gas and Electric Company [Member]

Line of credit facility, maximum borrowing capacity

^[1]

600

Revolving Credit Facility [Member] | Potomac Electric Power Company [Member]

Line of credit facility, maximum borrowing capacity

^[1]

300

Revolving Credit Facility [Member] | Delmarva Power & Light Company [Member]

Line of credit facility, maximum borrowing capacity

^[1]

300

Revolving Credit Facility [Member] | Atlantic City Electric Company [Member]

Line of credit facility, maximum borrowing capacity

^[1]

300

Maximum [Member] | Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

900

Maximum [Member] | Delmarva Power & Light Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

Maximum [Member] | Atlantic City Electric Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

$ 0

[1]

Debt and Credit Agreements - Summary of Short-term Borrowing Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Short-term Debt [Line Items]
Average borrowings	$ 531	$ 823	$ 1,125
Maximum borrowings outstanding	$ 1,237	$ 2,147	$ 3,076
Short-term Debt, Weighted Average Interest Rate, over Time	2.21%	1.32%	0.88%
Average interest rates at year end	2.15%	1.24%	1.12%
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Average borrowings	$ 37	$ 405	$ 536
Maximum borrowings outstanding	$ 583	$ 1,455	$ 1,735
Short-term Debt, Weighted Average Interest Rate, over Time	1.96%	1.23%	0.94%
Average interest rates at year end	1.96%	1.23%	1.14%
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Average borrowings	$ 154	$ 200	$ 256
Maximum borrowings outstanding	$ 520	$ 470	$ 755
Short-term Debt, Weighted Average Interest Rate, over Time	2.14%	1.24%	0.77%
Average interest rates at year end	2.14%	1.24%
PECO Energy Co [Member]
Short-term Debt [Line Items]
Average borrowings	$ 68	$ 2	$ 0
Maximum borrowings outstanding	$ 350	$ 60	0
Short-term Debt, Weighted Average Interest Rate, over Time	2.24%	1.13%
Average interest rates at year end	2.24%	1.13%
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 65	$ 54	143
Maximum borrowings outstanding	$ 239	$ 165	$ 369
Short-term Debt, Weighted Average Interest Rate, over Time	2.18%	1.28%	0.77%
Average interest rates at year end	2.18%	1.28%	0.95%
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Short-term Bank Loans and Notes Payable	$ 500
Average borrowings			$ 153
Maximum borrowings outstanding			$ 559
Short-term Debt, Weighted Average Interest Rate, over Time			1.03%
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Average borrowings	22	$ 51	$ 4
Maximum borrowings outstanding	$ 90	$ 197	$ 73
Short-term Debt, Weighted Average Interest Rate, over Time	2.24%	1.06%	0.71%
Average interest rates at year end	2.24%	1.06%	0.90%
Delmarva Power & Light Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 87	$ 40	$ 33
Maximum borrowings outstanding	$ 245	$ 216	$ 116
Short-term Debt, Weighted Average Interest Rate, over Time	2.07%	1.48%	0.68%
Average interest rates at year end	2.07%	1.48%
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Short-term Bank Loans and Notes Payable	$ 125
Average borrowings	95	$ 30	$ 0
Maximum borrowings outstanding	$ 210	$ 133	$ 5
Short-term Debt, Weighted Average Interest Rate, over Time	2.21%	1.43%	0.65%
Average interest rates at year end	2.21%	1.43%

Debt and Credit Agreements - Summary of Interest Coverage Ratios (Details)	12 Months Ended
	Dec. 31, 2018
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	7.34
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	10.99
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	7.34
PECO Energy Co [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	8.14
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	9.77
Potomac Electric Power Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	5.98
Delmarva Power & Light Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	7.03
Atlantic City Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	5.06

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) - USD ($)
$ in Millions

1 Months Ended

9 Months Ended

12 Months Ended

Feb. 08, 2019

Sep. 30, 2018

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Jun. 30, 2014

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 1,349

34,911

$ 33,657

(66)

(57)

(216)

(201)

Fair value adjustment

795

865

(1,349)

^[1]

(2,088)

34,075

32,176

390

389

3,528

1,511

1,786

2,490

$ 1,936

PECO Trust III Affiliate [Member]

206

205

PECO Trust IV Affiliate [Member]

103

Secured Debt [Member]

Secured Debt [Member] | Minimum [Member]

^[2]

$ 16,496

15,197

Secured Debt [Member] | Maximum [Member]

^[2]

1.70%

^[2]

7.90%

Senior Notes [Member]

Senior Notes [Member] | Minimum [Member]

$ 11,285

11,285

Senior Notes [Member] | Maximum [Member]

2.45%

7.60%

Unsecured Debt [Member]

Unsecured Debt [Member] | Minimum [Member]

$ 2,900

2,600

Unsecured Debt [Member] | Maximum [Member]

2.40%

Pollution Control Notes [Member]

6.35%

Pollution Control Notes [Member] | Minimum [Member]

$ 435

435

Pollution Control Notes [Member] | Maximum [Member]

2.50%

Notes Payable to Banks [Member]

2.70%

Notes Payable to Banks [Member] | Maximum [Member]

$ 39

Notes Payable, Other Payables [Member]

3.15%

^[3],[4]

$ 188

405

Notes Payable, Other Payables [Member] | Minimum [Member]

$ 0

$ (1)

Notes Payable, Other Payables [Member] | Maximum [Member]

^[3],[4]

2.85%

Junior Subordinated Debt [Member]

^[3],[4]

8.88%

3.497%

2.50%

Junior Subordinated Debt [Member] | Maximum [Member]

$ 1,150

Software License Arrangement [Member]

3.50%

Software License Arrangement [Member] | Maximum [Member]

$ 73

Tax-exempt Money Market Funds [Member]

3.95%

Tax-exempt Money Market Funds [Member] | Minimum [Member]

$ 112

112

Tax-exempt Money Market Funds [Member] | Maximum [Member]

1.74%

Medium-term Notes [Member]

5.40%

Medium-term Notes [Member] | Minimum [Member]

$ 22

Medium-term Notes [Member] | Maximum [Member]

7.61%

Transition Bonds [Member]

7.72%

Transition Bonds [Member] | Maximum [Member]

$ 59

5.55%

Loans Payable [Member]

Loans Payable [Member] | Maximum [Member]

$ 50

Non Recourse Fixed Rate [Member]

2.00%

Non Recourse Fixed Rate [Member] | Minimum [Member]

$ 1,253

1,331

Non Recourse Fixed Rate [Member] | Maximum [Member]

2.29%

Non Recourse Variable Rate [Member]

6.00%

Non Recourse Variable Rate [Member] | Maximum [Member]

^[5]

$ 849

865

Capital Lease Obligations [Member]

^[5]

5.81%

$ 36

Long-term Debt [Member]

Long-term Debt [Member] | ComEd Financing III Affiliate [Member]

390

Long-term Debt [Member] | ComEd Financing III Affiliate [Member] | Maximum [Member]

^[6]

$ 206

206

Long-term Debt [Member] | PECO Trust III Affiliate [Member]

^[6]

6.35%

Long-term Debt [Member] | PECO Trust III Affiliate [Member] | Minimum [Member]

^[6]

$ 81

Long-term Debt [Member] | PECO Trust III Affiliate [Member] | Maximum [Member]

^[6]

7.38%

Long-term Debt [Member] | PECO Trust IV Affiliate [Member]

^[6]

7.50%

Long-term Debt [Member] | PECO Trust IV Affiliate [Member] | Maximum [Member]

^[6]

$ 103

103

^[6]

5.75%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 906

8,759

8,955

(6)

(8)

(51)

(60)

Fair value adjustment

103

(906)

(346)

Debt and Capital Lease Obligations

6,989

7,734

7,887

8,644

2,108

Exelon Generation Co L L C [Member] | Senior Notes [Member]

141

1,261

202

Exelon Generation Co L L C [Member] | Senior Notes [Member] | Minimum [Member]

$ 6,019

6,019

Exelon Generation Co L L C [Member] | Senior Notes [Member] | Maximum [Member]

2.95%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member]

7.60%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member] | Minimum [Member]

$ 435

435

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member] | Maximum [Member]

2.50%

Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member]

2.70%

Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member] | Maximum [Member]

$ 39

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member]

3.15%

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

^[7],[8]

$ 164

223

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

^[7],[8]

2.85%

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member]

^[7],[8]

7.83%

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member] | Minimum [Member]

$ 1,253

1,331

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member] | Maximum [Member]

2.29%

Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member]

6.00%

Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member] | Maximum [Member]

^[9]

$ 849

865

Exelon Generation Co L L C [Member] | Capital Lease Obligations [Member]

^[9]

5.81%

$ 14

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

300

8,187

7,676

(23)

(63)

(52)

(300)

^[10]

(840)

7,801

6,761

Debt and Capital Lease Obligations

205

7,801

6,761

500

350

Commonwealth Edison Co [Member] | ComEd Financing III Affiliate [Member]

840

425

665

(1)

Commonwealth Edison Co [Member] | Secured Debt [Member]

205

Commonwealth Edison Co [Member] | Secured Debt [Member] | Minimum [Member]

^[11]

$ 8,179

7,529

Commonwealth Edison Co [Member] | Secured Debt [Member] | Maximum [Member]

^[11]

2.15%

Commonwealth Edison Co [Member] | Notes Payable, Other Payables [Member]

^[11]

6.45%

Commonwealth Edison Co [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

^[12]

$ 8

147

Commonwealth Edison Co [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

^[12]

Commonwealth Edison Co [Member] | Capital Lease Obligations [Member]

^[12]

7.49%

Commonwealth Edison Co [Member] | Long-term Debt [Member]

$ 8

Thereafter

Commonwealth Edison Co [Member] | Long-term Debt [Member] | ComEd Financing III Affiliate [Member]

206

Commonwealth Edison Co [Member] | Long-term Debt [Member] | ComEd Financing III Affiliate [Member] | Maximum [Member]

^[13]

$ 206

206

^[13]

6.35%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 0

3,125

2,925

(18)

(5)

(23)

(17)

3,084

2,403

^[14]

184

Debt and Capital Lease Obligations

(500)

3,084

2,403

300

PECO Energy Co [Member] | PECO Trust III Affiliate [Member]

500

300

PECO Energy Co [Member] | PECO Trust IV Affiliate [Member]

PECO Energy Co [Member] | Secured Debt [Member]

103

PECO Energy Co [Member] | Secured Debt [Member] | Minimum [Member]

^[15]

$ 3,075

2,925

PECO Energy Co [Member] | Secured Debt [Member] | Maximum [Member]

^[15]

1.70%

PECO Energy Co [Member] | Loans Payable [Member]

^[15]

5.95%

PECO Energy Co [Member] | Loans Payable [Member] | Maximum [Member]

$ 50

PECO Energy Co [Member] | Long-term Debt [Member] | PECO Trust III Affiliate [Member]

2.00%

PECO Energy Co [Member] | Long-term Debt [Member] | PECO Trust III Affiliate [Member] | Minimum [Member]

^[14]

$ 81

PECO Energy Co [Member] | Long-term Debt [Member] | PECO Trust III Affiliate [Member] | Maximum [Member]

^[14]

7.38%

PECO Energy Co [Member] | Long-term Debt [Member] | PECO Trust IV Affiliate [Member]

^[14]

7.50%

PECO Energy Co [Member] | Long-term Debt [Member] | PECO Trust IV Affiliate [Member] | Maximum [Member]

^[14]

$ 103

103

^[14]

5.75%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 0

2,900

2,600

(6)

(18)

(17)

2,876

2,577

2,876

2,577

300

Baltimore Gas and Electric Company [Member] | Senior Notes [Member]

379

Baltimore Gas and Electric Company [Member] | Senior Notes [Member] | Minimum [Member]

$ 2,900

2,600

Baltimore Gas and Electric Company [Member] | Senior Notes [Member] | Maximum [Member]

2.40%

6.35%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 125

5,636

5,189

(14)

(6)

Fair value adjustment

633

686

6,134

5,478

(125)

(396)

6,134

5,478

261

Pepco Holdings LLC [Member] | Secured Debt [Member]

299

169

Pepco Holdings LLC [Member] | Secured Debt [Member] | Minimum [Member]

^[16]

$ 5,242

4,743

Pepco Holdings LLC [Member] | Secured Debt [Member] | Maximum [Member]

^[16]

1.81%

Pepco Holdings LLC [Member] | Unsecured Debt [Member]

^[16]

7.90%

Pepco Holdings LLC [Member] | Unsecured Debt [Member] | Maximum [Member]

$ 185

185

Pepco Holdings LLC [Member] | Notes Payable, Other Payables [Member]

7.45%

Pepco Holdings LLC [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

^[17]

$ 16

Pepco Holdings LLC [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

^[17]

7.28%

Pepco Holdings LLC [Member] | Tax-exempt Money Market Funds [Member]

^[17]

8.88%

Pepco Holdings LLC [Member] | Tax-exempt Money Market Funds [Member] | Minimum [Member]

$ 112

112

Pepco Holdings LLC [Member] | Tax-exempt Money Market Funds [Member] | Maximum [Member]

1.74%

Pepco Holdings LLC [Member] | Medium-term Notes [Member]

5.40%

Pepco Holdings LLC [Member] | Medium-term Notes [Member] | Minimum [Member]

$ 22

Pepco Holdings LLC [Member] | Medium-term Notes [Member] | Maximum [Member]

7.61%

Pepco Holdings LLC [Member] | Transition Bonds [Member]

7.72%

Pepco Holdings LLC [Member] | Transition Bonds [Member] | Minimum [Member]

^[18]

$ 59

Pepco Holdings LLC [Member] | Transition Bonds [Member] | Maximum [Member]

^[18]

Pepco Holdings LLC [Member] | Capital Lease Obligations [Member]

^[18]

5.55%

Capital lease obligations, current

$ 14

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

2,751

2,570

(34)

(32)

2,704

2,521

(15)

(19)

2,704

2,521

Due in 2019

Potomac Electric Power Company [Member] | Secured Debt [Member]

Potomac Electric Power Company [Member] | Secured Debt [Member] | Minimum [Member]

^[19]

$ 2,735

2,535

Potomac Electric Power Company [Member] | Secured Debt [Member] | Maximum [Member]

^[19]

3.05%

Potomac Electric Power Company [Member] | Notes Payable, Other Payables [Member]

^[19]

7.90%

Potomac Electric Power Company [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

^[20]

$ 16

Potomac Electric Power Company [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

^[20]

7.28%

^[20]

8.88%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 91

1,504

1,309

(12)

(11)

(79)

1,403

1,217

(91)

(83)

1,403

1,217

Delmarva Power & Light Company [Member] | Secured Debt [Member]

100

Delmarva Power & Light Company [Member] | Secured Debt [Member] | Minimum [Member]

^[21]

$ 1,370

1,171

Delmarva Power & Light Company [Member] | Secured Debt [Member] | Maximum [Member]

^[21]

1.81%

Delmarva Power & Light Company [Member] | Tax-exempt Money Market Funds [Member]

^[21]

4.27%

Delmarva Power & Light Company [Member] | Tax-exempt Money Market Funds [Member] | Minimum [Member]

$ 112

112

Delmarva Power & Light Company [Member] | Tax-exempt Money Market Funds [Member] | Maximum [Member]

1.74%

Delmarva Power & Light Company [Member] | Medium-term Notes [Member]

5.40%

Delmarva Power & Light Company [Member] | Medium-term Notes [Member] | Minimum [Member]

$ 22

Delmarva Power & Light Company [Member] | Medium-term Notes [Member] | Maximum [Member]

7.61%

7.72%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 18

1,196

1,127

(1)

(7)

(5)

1,170

840

(18)

(281)

1,170

840

260

Atlantic City Electric Company [Member] | Secured Debt [Member]

281

$ 48

Atlantic City Electric Company [Member] | Secured Debt [Member] | Minimum [Member]

^[22]

$ 1,137

1,037

Atlantic City Electric Company [Member] | Secured Debt [Member] | Maximum [Member]

^[22]

3.38%

Atlantic City Electric Company [Member] | Transition Bonds [Member]

^[22]

6.80%

Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months

$ 18

^[23]

$ 90

Atlantic City Electric Company [Member] | Transition Bonds [Member] | Maximum [Member]

$ 21

AGEPFNotesNov2017 [Member] | AGE Biomass project [Member] | Long-term Debt [Member]

^[23]

5.55%

Subsequent Event [Member]

$ 228

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

Repayments of Debt

$ 300

Repayments of Debt

$ 300

[1]	In January 2019, $300 million of ComEd long-term debt due within one year was paid in full.
[2]	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.
[3]	Includes capital lease obligations of $36 million and $53 million at December 31, 2018 and 2017, respectively. Lease payments of $21 million, $5 million, $1 million, $1 million, less than $1 million, and $8 million will be made in 2019, 2020, 2021, 2022, 2023, and thereafter, respectively.
[4]	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.
[5]	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.
[6]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[7]	Includes Generation’s capital lease obligations of $14 million and $18 million at December 31, 2018 and 2017, respectively. Generation will make lease payments of $7 million, $5 million, $1 million, and $1 million in 2019, 2020, 2021, and 2022, respectively. Lease payments of less than $1 million annually will be made from 2023 through expiration of the final capital lease in 2024.
[8]	Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.
[9]	Excludes interest on CEU Upstream nonrecourse debt, see discussion below.
[10]	In January 2019, the $300 million balance was paid in full.
[11]	Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.
[12]	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2018 and 2017, respectively. Lease payments of less than $1 million annually will be made from 2019 through expiration at 2053.
[13]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
[14]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[15]	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
[16]	Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.
[17]	Includes Pepco's capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively.
[18]	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.
[19]	Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.
[20]	Includes capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017, respectively. Lease payments of $14 million will be made in 2019.
[21]	Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture.
[22]	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.
[23]	Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021.

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

$ 1,349

3,528

1,511

3,084

850

^[1]

24,979

35,301

390

$ 389

206

205

906

2,108

1,024

4,720

8,759

300

500

350

^[2]

7,243

8,393

Commonwealth Edison Co [Member] | ComEd Financing III Affiliate [Member]

205

205

300

350

^[3]

2,609

3,309

^[4]

184

300

250

300

2,050

2,900

125

261

310

500

4,420

5,636

310

2,425

2,751

500

913

1,504

Capital Lease Obligations [Member]

260

898

1,196

Capital Leases, Future Minimum Payments Due Thereafter

Capital Lease Obligations [Member] | Exelon Generation Co L L C [Member]

Capital Leases, Future Minimum Payments Due Thereafter

Long-term Debt [Member]

Long-term Debt [Member] | ComEd Financing III Affiliate [Member]

390

Long-term Debt [Member] | Commonwealth Edison Co [Member]

^[5]

206

Long-term Debt [Member] | Commonwealth Edison Co [Member] | ComEd Financing III Affiliate [Member]

206

Long-term Debt [Member] | PECO Energy Co [Member] | PECO Financing Trusts [Member]

^[6]

206

$ 206

Minimum [Member] | Tax-exempt Money Market Funds [Member]

$ 184

Minimum [Member] | Tax-exempt Money Market Funds [Member] | Pepco Holdings LLC [Member]

1.74%

Minimum [Member] | Tax-exempt Money Market Funds [Member] | Delmarva Power & Light Company [Member]

1.74%

Maximum [Member] | Tax-exempt Money Market Funds [Member]

1.74%

Maximum [Member] | Tax-exempt Money Market Funds [Member] | Pepco Holdings LLC [Member]

5.40%

Maximum [Member] | Tax-exempt Money Market Funds [Member] | Delmarva Power & Light Company [Member]

5.40%

Maximum [Member] | Long-term Debt [Member] | ComEd Financing III Affiliate [Member]

5.40%

Maximum [Member] | Long-term Debt [Member] | Commonwealth Edison Co [Member] | ComEd Financing III Affiliate [Member]

^[5]

6.35%

^[6]

6.35%

[1]	Includes $390 million due to ComEd and PECO financing trusts.
[2]	Includes $206 million due to ComEd financing trust.
[3]	Includes $184 million due to PECO financing trusts.
[4]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[5]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[6]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.

Debt and Credit Agreements - Narrative (Details)
$ / shares in Units, shares in Millions

12 Months Ended

Dec. 31, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

$ / shares

Dec. 30, 2018

USD ($)

Jun. 30, 2018

USD ($)

Mar. 31, 2016

USD ($)

Oct. 23, 2015

USD ($)

Jun. 30, 2014

USD ($)

$ / shares

$ 1,349,000,000

1,349,000,000

^[1]

$ 2,088,000,000

Line of credit facility, maximum borrowing capacity

1,786,000,000

2,490,000,000

$ 1,936,000,000

^[2]

9,704,000,000

1,696,000,000

34,911,000,000

33,657,000,000

Collateral amount of debt

35,301,000,000

3,000,000,000

Line of Credit Facility, Current Borrowing Capacity

$ 135,000,000

128,000,000

Transition Bonds [Member]

2.50

$ 59,000,000

90,000,000

Senior Notes [Member]

Junior Subordinated Debt [Member]

11,285,000,000

Equity units issued | shares

$ 1,150,000,000

Conversion price | $ / shares

$ 50

Stock Issued During Period, Shares, Treasury Stock Reissued | shares

3.497%

2.50%

Junior Subordinated Notes

$ 1,150,000,000

Loss on Reissuance, Treasury Stock

1,050,000,000

Maximum [Member]

Basis points adders for prime-based borrowings

90.00%

Basis points adders for LIBOR-based borrowings

1.7

Maximum [Member] | Transition Bonds [Member]

Maximum [Member] | Senior Notes [Member]

5.55%

Maximum [Member] | Junior Subordinated Debt [Member]

7.60%

Minimum [Member] | Senior Notes [Member]

3.50%

Revolving Credit Facility [Member]

2.45%

Line of credit facility, maximum borrowing capacity

$ 500,000,000

$ 0

569,000,000

46,000,000

9,000,000

7,039,000,000

7,039,000,000

Exelon Corporate [Member] | Senior Notes [Member]

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

^[3]

5,889,000,000

Exelon Corporate [Member] | Maximum [Member] | Senior Notes [Member]

$ 1,150,000,000

1,150,000,000

Exelon Corporate [Member] | Maximum [Member] | Junior Subordinated Debt [Member]

^[3]

7.60%

Exelon Corporate [Member] | Minimum [Member] | Senior Notes [Member]

3.50%

Exelon Corporate [Member] | Revolving Credit Facility [Member]

^[3]

2.45%

Line of credit facility, maximum borrowing capacity

^[2]

$ 600,000,000

906,000,000

906,000,000

346,000,000

Line of credit facility, maximum borrowing capacity

141,000,000

1,261,000,000

202,000,000

200,000,000

$ 45,000,000

8,759,000,000

8,955,000,000

Line of Credit Facility, Current Borrowing Capacity

8,759,000,000

$ 49,000,000

49,000,000

$ 75,000,000

Exelon Generation Co L L C [Member] | ExGen Texas Power [Member] | Interest Rate Swap [Member]

3.00

Non-recourse debt, interest rate swap

2.34%

$ 505,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member]

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member]

6,019,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExGen Texas Power [Member]

31,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member]

675,000,000

Non-recourse debt, commitment

38,000,000

$ 646,000,000

Debt, Weighted Average Interest Rate

2.82%

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Denver International Airport [Member]

$ 508,000,000

5.50%

$ 7,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Holyoke [Member]

$ 6,000,000

5.25%

$ 11,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Upstream Gas Property [Member]

8,000,000

Gain (Loss) on Sale of Debt Investments

15,000,000

Escrow Deposit

6,000,000

37,000,000

$ 15,000,000

15,000,000

Proceeds from Sales of Business, Affiliate and Productive Assets

22,000,000

1,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | SolGen [Member]

3.93%

$ 150,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Renewable Power Generation [Member]

$ 137,000,000

4.11%

$ 150,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Continetal Wind [Member]

115,000,000

Line of credit facility, maximum borrowing capacity

131,000,000

Aggregate Bank Commitments Under Unsecured Revolving Credit Facilities

10,000,000

$ 114,000,000

6.00%

Generation capacity of portfolio | MW

$ 613,000,000

667

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExGenRenewablesIVNov2024 [Member]

$ 479,000,000

3.00%

Non-recourse debt, interest rate swap

$ 850,000,000

636,000,000

Non-recourse debt, hedge percentage

$ 834,000,000

2.32%

Proceeds from Issuance of Debt

$ 785,000,000

Proceeds from (Repayments of) Restricted Cash, Financing Activities

$ 50,000,000

Exelon Generation Co L L C [Member] | Maximum [Member] | Senior Notes [Member]

Exelon Generation Co L L C [Member] | Minimum [Member] | Senior Notes [Member]

7.60%

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

2.95%

Line of credit facility, maximum borrowing capacity

^[2]

$ 5,300,000,000

1,203,000,000

Exelon Generation Co L L C [Member] | Line of Credit [Member]

Line of credit facility, maximum borrowing capacity

^[2]

545,000,000

353,000,000

Exelon Generation Co L L C [Member] | Domestic Line of Credit [Member]

Line of credit facility, maximum borrowing capacity

95,000,000

$ 100,000,000

Exelon Generation Co L L C [Member] | Line of Credit [Member]

Line of credit facility, maximum borrowing capacity

150,000,000

Line of Credit Facility, Current Borrowing Capacity

30,000,000

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

545,000,000

480,000,000

300,000,000

300,000,000

^[4]

840,000,000

840,000,000

425,000,000

665,000,000

2,000,000

8,187,000,000

7,676,000,000

8,393,000,000

Line of Credit Facility, Current Borrowing Capacity

$ 33,000,000

34,000,000

Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]

2.00

Line of credit facility, maximum borrowing capacity

^[2]

$ 1,000,000,000

500,000,000

300,000,000

3,125,000,000

2,925,000,000

3,309,000,000

Line of Credit Facility, Current Borrowing Capacity

$ 34,000,000

34,000,000

PECO Energy Co [Member] | Revolving Credit Facility [Member]

2.00

Line of credit facility, maximum borrowing capacity

^[2]

$ 600,000,000

41,000,000

$ 379,000,000

1,000,000

2,900,000,000

2,600,000,000

2,900,000,000

Line of Credit Facility, Current Borrowing Capacity

$ 5,000,000

5,000,000

Preferred Stock, Redemption Price Per Share | $ / shares

$ 100

Baltimore Gas and Electric Company [Member] | Senior Notes [Member]

2.00

Baltimore Gas and Electric Company [Member] | Maximum [Member] | Senior Notes [Member]

$ 2,900,000,000

2,600,000,000

Baltimore Gas and Electric Company [Member] | Minimum [Member] | Senior Notes [Member]

6.35%

Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]

2.40%

Line of credit facility, maximum borrowing capacity

^[2]

$ 600,000,000

125,000,000

299,000,000

169,000,000

5,636,000,000

5,189,000,000

5,636,000,000

$ 500,000,000

Pepco Holdings LLC [Member] | Transition Bonds [Member]

LIBOR plus 1%

Pepco Holdings LLC [Member] | Maximum [Member] | Transition Bonds [Member]

^[5]

$ 59,000,000

90,000,000

Pepco Holdings LLC [Member] | Minimum [Member] | Transition Bonds [Member]

^[5]

5.55%

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

^[5]

Line of credit facility, maximum borrowing capacity

$ 1,500,000,000

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member] | Maximum [Member]

Line of credit facility, maximum borrowing capacity

900,000,000

15,000,000

14,000,000

13,000,000

$ 11,000,000

8,000,000

2,751,000,000

2,570,000,000

2,751,000,000

Line of Credit Facility, Current Borrowing Capacity

$ 5,000,000

2,000,000

Potomac Electric Power Company [Member] | Revolving Credit Facility [Member]

2.00

Line of credit facility, maximum borrowing capacity

^[2]

$ 300,000,000

91,000,000

79,000,000

4,000,000

40,000,000

100,000,000

1,000,000

1,504,000,000

1,309,000,000

1,504,000,000

Line of Credit Facility, Current Borrowing Capacity

$ 5,000,000

2,000,000

Delmarva Power & Light Company [Member] | Revolving Credit Facility [Member]

2.00

Line of credit facility, maximum borrowing capacity

^[2]

$ 300,000,000

Delmarva Power & Light Company [Member] | Revolving Credit Facility [Member] | Maximum [Member]

Line of credit facility, maximum borrowing capacity

18,000,000

281,000,000

35,000,000

$ 48,000,000

1,196,000,000

1,127,000,000

1,196,000,000

$ 125,000,000

Line of Credit Facility, Current Borrowing Capacity

LIBOR plus 0.55%

$ 5,000,000

2,000,000

Atlantic City Electric Company [Member] | Transition Bonds [Member]

2.00

$ 18,000,000

Atlantic City Electric Company [Member] | Maximum [Member] | Transition Bonds [Member]

^[6]

$ 59,000,000

$ 90,000,000

Atlantic City Electric Company [Member] | Revolving Credit Facility [Member]

^[6]

5.55%

Line of credit facility, maximum borrowing capacity

^[2]

$ 300,000,000

Atlantic City Electric Company [Member] | Revolving Credit Facility [Member] | Maximum [Member]

Line of credit facility, maximum borrowing capacity

Corporate, Non-Segment [Member] | Exelon Corporate [Member]

$ 500,000,000

CENG [Member] | Exelon Generation Co L L C [Member] | Domestic Line of Credit [Member]

LIBOR plus 1%

Line of credit facility, maximum borrowing capacity

$ 200,000,000

CENG [Member] | Exelon Generation Co L L C [Member] | Line of Credit [Member]

Line of credit facility, maximum borrowing capacity

$ 100,000,000

[1]	In January 2019, $300 million of ComEd long-term debt due within one year was paid in full.
[2]	Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $49 million, $33 million, $34 million, $5 million, $5 million, $5 million and $5 million, respectively. These facilities expire on October 11, 2019. These facilities are solely utilized to issue letters of credit. As of December 31, 2018, letters of credit issued under these facilities totaled $5 million and $2 million for Generation and BGE, respectively.
[3]	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.
[4]	In January 2019, the $300 million balance was paid in full.
[5]	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.
[6]	Maturities of ACE's Transition Bonds outstanding at December 31, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021.

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended	12 Months Ended
	Dec. 31, 2018	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Income taxes	$ 26			$ 120	$ (126)	$ 753
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Income taxes				(108)	(1,376)	282
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Income taxes				168	417	301
PECO Energy Co [Member]
Income Taxes [Line Items]
Income taxes				6	104	149
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Income taxes				74	218	174
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Income taxes				13	105	41
Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Income taxes				22	71	22
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Income taxes				12	26	(4)
Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Income taxes				35	217
Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Income taxes			$ 3
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Income taxes		$ 17
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Current				226	194	60
Deferred				(98)	(471)	600
Investment Tax Credit				(24)	(25)	(24)
Internal Revenue Service (IRS) [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current				337	584	513
Deferred				(347)	(2,005)	(254)
Investment Tax Credit				(21)	(21)	(20)
Internal Revenue Service (IRS) [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current				(63)	(191)	(135)
Deferred				145	523	379
Investment Tax Credit				(2)	(2)	(2)
Internal Revenue Service (IRS) [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current				11	71	63
Deferred				10	28	72
Investment Tax Credit				0	0	0
Internal Revenue Service (IRS) [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current				(5)	74	51
Deferred				47	101	88
Investment Tax Credit				0	(1)	(1)
Internal Revenue Service (IRS) [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Current				28	(20)	(118)
Deferred				(21)	114	136
Investment Tax Credit				0	0	0
Internal Revenue Service (IRS) [Member] \| Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Current				(3)	(24)	(88)
Deferred				13	82	97
Investment Tax Credit				0	0	0
Internal Revenue Service (IRS) [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Current				(14)	(12)	(26)
Deferred				18	34	22
Investment Tax Credit				0	0	0
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Current				(4)	(60)
Deferred				24	250
Investment Tax Credit				(1)	(1)
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Current			(281)
Deferred			283
Investment Tax Credit			(1)
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Current		0
Deferred		10
Investment Tax Credit		0
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Current				(1)	14	39
Deferred				17	162	78
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current				6	65	45
Deferred				(83)	1	(2)
State and Local Jurisdiction [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current				(29)	(49)	(4)
Deferred				117	136	63
State and Local Jurisdiction [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current				1	14	9
Deferred				(16)	(9)	5
State and Local Jurisdiction [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current				0	(5)	5
Deferred				32	49	31
State and Local Jurisdiction [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Current				0	(2)	7
Deferred				6	13	16
State and Local Jurisdiction [Member] \| Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Current				0	0	1
Deferred				12	13	12
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Current				0	0	0
Deferred				8	4	$ 0
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Current				7	(4)
Deferred				$ 9	$ 32
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Current			(11)
Deferred			$ 13
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Current		0
Deferred		$ 7

Income Taxes - Reconciliation to Effective Tax Rate (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

0.60%

2.30%

3.30%

^[1]

Qualified nuclear decommissioning trust fund income

(1.90%)

3.80%

3.40%

Amortization of investment tax credit, including deferred taxes on basis difference

(1.20%)

(0.90%)

(1.20%)

(3.50%)

^[2]

(1.70%)

(4.90%)

(2.20%)

(1.80%)

(3.60%)

(1.00%)

(0.20%)

(8.30%)

(1.20%)

(0.40%)

1.90%

(3.60%)

5.60%

(2.20%)

^[3]

0.90%

(33.10%)

1.00%

0.10%

(0.70%)

^[4]

Amount of Impairment to Carrying Amount of Regulatory Assets

5.40%

(3.30%)

38.20%

$ 35

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

(16.60%)

2.90%

3.20%

^[1]

Qualified nuclear decommissioning trust fund income

(11.80%)

9.90%

7.90%

Amortization of investment tax credit, including deferred taxes on basis difference

(6.50%)

(2.10%)

(2.30%)

(0.00%)

^[2]

(0.00%)

^[2]

(0.00%)

(13.50%)

(4.70%)

(8.30%)

(6.10%)

(0.60%)

0.00%

(1.70%)

0.00%

(1.20%)

1.10%

(5.60%)

^[3]

2.70%

(128.30%)

1.30%

(0.50%)

(1.40%)

^[4]

(29.50%)

(94.60%)

32.90%

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

8.30%

5.70%

5.60%

^[1]

Qualified nuclear decommissioning trust fund income

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.20%)

(0.30%)

(0.20%)

^[2]

0.30%

^[2]

(0.60%)

(0.00%)

(0.00%)

(9.10%)

1.30%

0.00%

4.50%

0.00%

0.00%

^[3]

(0.10%)

0.10%

0.50%

0.20%

0.10%

^[4]

Amount of Impairment to Carrying Amount of Regulatory Assets

20.20%

42.40%

44.30%

$ 3

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

(2.60%)

0.60%

1.30%

^[1]

Qualified nuclear decommissioning trust fund income

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(14.10%)

^[2]

(13.80%)

^[2]

(9.60%)

(0.00%)

(0.00%)

(3.20%)

0.00%

0.00%

0.00%

0.00%

0.00%

^[3]

0.00%

(2.30%)

0.30%

(0.10%)

(1.20%)

^[4]

1.30%

19.30%

25.40%

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

6.60%

5.40%

5.00%

^[1]

Qualified nuclear decommissioning trust fund income

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(1.30%)

^[2]

0.10%

^[2]

(2.70%)

(0.00%)

(0.00%)

(8.00%)

0.00%

0.00%

0.00%

0.00%

0.00%

^[3]

0.00%

0.90%

0.90%

0.20%

0.00%

^[4]

Amount of Impairment to Carrying Amount of Regulatory Assets

19.10%

41.50%

37.20%

$ 5

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

2.20%

3.20%

15.70%

^[1]

Qualified nuclear decommissioning trust fund income

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(0.20%)

(2.70%)

^[2]

(0.40%)

^[2]

(22.80%)

(0.00%)

(0.00%)

(14.80%)

0.00%

0.00%

0.00%

(6.30%)

23.50%

0.00%

^[3]

0.00%

2.70%

0.20%

(0.20%)

(1.80%)

^[4]

Amount of Impairment to Carrying Amount of Regulatory Assets

5.80%

33.90%

49.40%

$ 14

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

^[5]

6.70%

5.40%

52.70%

^[1],[5]

Qualified nuclear decommissioning trust fund income

0.00%

^[5]

Amortization of investment tax credit, including deferred taxes on basis difference

(0.30%)

(0.20%)

(3.70%)

^[5]

(0.30%)

^[2]

2.00%

^[2]

(25.50%)

^[5]

(0.00%)

^[5]

(0.00%)

^[5]

(12.00%)

0.00%

^[5]

0.00%

^[5]

0.00%

(7.80%)

112.90%

^[5]

0.00%

^[3]

0.00%

2.50%

0.40%

0.10%

(2.20%)

^[4],[5]

Amount of Impairment to Carrying Amount of Regulatory Assets

15.50%

37.00%

169.20%

^[5]

$ 6

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

^[5]

7.40%

5.60%

6.20%

^[1],[5]

Qualified nuclear decommissioning trust fund income

0.00%

^[5]

Amortization of investment tax credit, including deferred taxes on basis difference

(0.40%)

0.80%

^[5]

(0.50%)

^[2]

3.60%

^[2]

10.30%

^[5]

(0.00%)

^[5]

(0.00%)

^[5]

(14.90%)

0.00%

^[5]

0.00%

^[5]

0.00%

(19.80%)

(44.90%)

^[5]

0.00%

^[3]

0.00%

1.60%

1.20%

(0.40%)

1.30%

^[4],[5]

Amount of Impairment to Carrying Amount of Regulatory Assets

13.80%

25.20%

8.70%

^[5]

$ 7

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

21.00%

35.00%

3.00%

4.80%

Qualified nuclear decommissioning trust fund income

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.20%)

^[2]

(1.60%)

1.10%

(0.00%)

(0.00%)

(14.50%)

0.00%

(9.50%)

0.00%

^[3]

0.10%

6.40%

0.30%

(0.10%)

Amount of Impairment to Carrying Amount of Regulatory Assets

8.10%

37.50%

$ 27

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

^[5]

35.00%

^[1],[5]

5.80%

Qualified nuclear decommissioning trust fund income

^[5]

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

^[5]

1.40%

^[5]

39.00%

^[5]

(0.00%)

^[5]

(0.00%)

^[5]

0.00%

^[5]

(0.70%)

^[5]

(89.00%)

^[4],[5]

3.30%

^[5]

(5.20%)

Effective Income Tax Rate Reconciliation At Federal Statutory Income Tax Rate [Line Items]

State income taxes, net of Federal income tax benefit

35.00%

^[1]

11.90%

Qualified nuclear decommissioning trust fund income

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.90%)

(13.50%)

(0.00%)

(0.00%)

0.00%

0.00%

11.10%

^[4]

3.60%

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member]

47.20%

[1]	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.
[2]	Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5 million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 4 - Regulatory Matters for additional information.
[3]	Included are impacts for TCJA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives, the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback.
[4]	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and accepted in 2017. No change to the results recorded as of December 31, 2016
[5]	DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Plant basis differences	$ (12,533)	$ (12,490)
Deferred Tax Liabilities, Other Finite-Lived Assets	117	150
Derivatives and other financial instruments	89	(85)
Deferred pension and postretirement obligation	1,435	1,463
Deferred Tax Liabilities, Investments	(351)	(553)
Deferred debt refinancing costs	234	217
Deferred Tax Liabilities, Regulatory Assets and Liabilities	(749)	(688)
Tax loss carryforward	237	344
Tax credit carryforward	811	861
Investment in partnerships	(797)	(434)
Other, net	934	746
Deferred income tax liabilities (net)	(10,573)	(10,469)
Unamortized investment tax credits	(724)	(732)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(11,297)	(11,201)
Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(2,495)	(2,819)
Deferred Tax Liabilities, Other Finite-Lived Assets	(44)	(66)
Derivatives and other financial instruments	35	(66)
Deferred pension and postretirement obligation	(188)	(205)
Deferred Tax Liabilities, Investments	(351)	(553)
Deferred debt refinancing costs	23	26
Deferred Tax Liabilities, Regulatory Assets and Liabilities	0	0
Tax loss carryforward	78	76
Tax credit carryforward	816	868
Investment in partnerships	(775)	(416)
Other, net	239	78
Deferred income tax liabilities (net)	(2,662)	(3,077)
Unamortized investment tax credits	(700)	(705)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(3,362)	(3,782)
Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(4,059)	(3,825)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	69	(2)
Deferred pension and postretirement obligation	(255)	(285)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(7)	(8)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	300	489
Tax loss carryforward	0	33
Tax credit carryforward	0	1
Investment in partnerships	0	0
Other, net	151	141
Deferred income tax liabilities (net)	(3,801)	(3,456)
Unamortized investment tax credits	(12)	(13)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(3,813)	(3,469)
PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,862)	(1,762)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(26)	(15)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	0	(1)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	(129)	(90)
Tax loss carryforward	18	9
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	67	71
Deferred income tax liabilities (net)	(1,932)	(1,788)
Unamortized investment tax credits	(1)	(1)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(1,933)	(1,789)
Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,399)	(1,368)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(26)	(29)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(3)	(3)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	172	136
Tax loss carryforward	25	11
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	12	13
Deferred income tax liabilities (net)	(1,219)	(1,240)
Unamortized investment tax credits	(3)	(4)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(1,222)	(1,244)
Pepco Holdings LLC [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(2,577)	(2,521)
Deferred Tax Liabilities, Other Finite-Lived Assets	161	216
Derivatives and other financial instruments	3	3
Deferred pension and postretirement obligation	(102)	(130)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	187	203
Deferred Tax Liabilities, Regulatory Assets and Liabilities	(90)	(184)
Tax loss carryforward	96	156
Tax credit carryforward	0	6
Investment in partnerships	0	0
Other, net	196	193
Deferred income tax liabilities (net)	(2,126)	(2,058)
Unamortized investment tax credits	(8)	(8)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(2,134)	(2,066)
Atlantic City Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(645)	(607)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(14)	(18)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(1)	(1)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	83	86
Tax loss carryforward	26	35
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	19	16
Deferred income tax liabilities (net)	(532)	(489)
Unamortized investment tax credits	(3)	(4)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(535)	(493)
Delmarva Power & Light Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(743)	(717)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(46)	(51)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(2)	(2)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	96	88
Tax loss carryforward	52	68
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	17	14
Deferred income tax liabilities (net)	(626)	(600)
Unamortized investment tax credits	(2)	(3)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(628)	(603)
Potomac Electric Power Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,148)	(1,152)
Deferred Tax Liabilities, Other Finite-Lived Assets	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(78)	(78)
Deferred Tax Liabilities, Investments	0	0
Deferred debt refinancing costs	(4)	(4)
Deferred Tax Liabilities, Regulatory Assets and Liabilities	58	39
Tax loss carryforward	12	40
Tax credit carryforward	0	0
Investment in partnerships	0	0
Other, net	98	94
Deferred income tax liabilities (net)	(1,062)	(1,061)
Unamortized investment tax credits	(2)	(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$ (1,064)	$ (1,063)

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details)
$ in Millions

Dec. 31, 2018

USD ($)

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Exelon Generation Co L L C [Member]

$ 811

^[1]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Commonwealth Edison Co [Member]

816

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | PECO Energy Co [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Baltimore Gas and Electric Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Pepco Holdings LLC [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Potomac Electric Power Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Delmarva Power & Light Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Atlantic City Electric Company [Member]

State and Local Jurisdiction [Member]

4,103

^[2]

272

State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member]

1,544

^[2]

104

State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member]

State and Local Jurisdiction [Member] | PECO Energy Co [Member]

224

^[3]

State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member]

395

^[4]

State and Local Jurisdiction [Member] | Pepco Holdings LLC [Member]

1,492

^[5]

102

State and Local Jurisdiction [Member] | Potomac Electric Power Company [Member]

192

^[6]

State and Local Jurisdiction [Member] | Delmarva Power & Light Company [Member]

772

^[7]

State and Local Jurisdiction [Member] | Atlantic City Electric Company [Member]

365

^[8]

$ 0

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246NUYzQjUwOTBEOUJENTE4OUJFODU2NDRDNjVGNkZEQzYM}
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246MDkyRDA3MDExQ0UwNUM3Q0JGMTJENTVGQjRDRkUxMEUM}
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246NTg5NzdDOUEwOTQ4NTk2NzlDM0NDM0NCREMxNDZGNEMM}
[4]	.
[5]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246RjE3NUQ0OEVCOEU4NTZBNjhDMkY3MzUwQUY0NTc3MDAM}
[6]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246NzBCNTFENTBCREJGNTIxMzhFRURCRkZFQzYxRDA1MDMM}
[7]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246OEMzNEQ1NEJCRDI5NTIxNUJCNTY4MkZEOEE3MEExOTcM}
[8]	.

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			$ 22
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	$ 743	$ 916	1,078
Increases based on tax positions related to current year			108
Increases based on tax positions prior to current year	15		(332)
Decreases based on tax positions prior to current year	30	28	88
Unrecognized Tax Benefits, Period Increase (Decrease)	(251)	(196)	(21)
Decrease from settlements with taxing authorities	(53)	(5)	(27)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	(7)
Unrecognized tax benefits - ending balance	477	743	916
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			5
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	468	490	534
Increases based on tax positions related to current year			10
Increases based on tax positions prior to current year	15		(12)
Decreases based on tax positions prior to current year	21	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	(36)	(17)	(20)
Decrease from settlements with taxing authorities	(53)	(5)	(27)
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	(7)
Unrecognized tax benefits - ending balance	408	468	490
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	2	(12)	142
Increases based on tax positions related to current year			0
Increases based on tax positions prior to current year	0		(154)
Decreases based on tax positions prior to current year	0	14	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	2	2	(12)
PECO Energy Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	0	0	0
Increases based on tax positions related to current year			0
Increases based on tax positions prior to current year	0		0
Decreases based on tax positions prior to current year	0	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	0	0	0
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	120	120	120
Increases based on tax positions related to current year			0
Increases based on tax positions prior to current year	0		0
Decreases based on tax positions prior to current year	0	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	(120)	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	0	120	120
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	59	80	8
Increases based on tax positions related to current year			21
Increases based on tax positions prior to current year	0		0
Decreases based on tax positions prior to current year	7	0	51
Unrecognized Tax Benefits, Period Increase (Decrease)	(66)	(21)	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	0	59	80
Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	21	37	3
Increases based on tax positions related to current year			16
Increases based on tax positions prior to current year	0		0
Decreases based on tax positions prior to current year	1	0	18
Unrecognized Tax Benefits, Period Increase (Decrease)	(22)	(16)	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	0	21	37
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			0
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	14	22	0
Increases based on tax positions related to current year			22
Increases based on tax positions prior to current year	0		0
Decreases based on tax positions prior to current year	0	14	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	(22)	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	14	14	22
Pepco Holdings LLC [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	125	172
Increases based on tax positions prior to current year	0
Decreases based on tax positions prior to current year	8	14
Unrecognized Tax Benefits, Period Increase (Decrease)	(88)	(61)
Decrease from settlements with taxing authorities	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Unrecognized tax benefits - ending balance	$ 45	125	172
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Acquisition			(5)
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance		$ 172	22
Increases based on tax positions related to current year			59
Increases based on tax positions prior to current year			0
Decreases based on tax positions prior to current year			96
Unrecognized Tax Benefits, Period Increase (Decrease)			0
Decrease from settlements with taxing authorities			0
Unrecognized tax benefits - ending balance			$ 172

Income Taxes - Summary of Interest Receivable (Payable) (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	$ 236	$ 233
Unrecognized Tax Benefits, Income Tax Penalties Accrued	(17)	(17)
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	(2)	(3)
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	4	4
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
PECO Energy Co [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	0	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	0	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	1	2
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	0	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	0	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0	0
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	0	0
Unrecognized Tax Benefits, Income Tax Penalties Accrued	$ 0	$ 0

Income Taxes - Summary of Interest Expense (Income) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			$ 0	$ (2)	$ 106
Net interest (income) expense recognized related to uncertain tax positions			(3)	37	165
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	0
Net interest (income) expense recognized related to uncertain tax positions			0	(1)	(13)
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	86
Net interest (income) expense recognized related to uncertain tax positions			0	11	117
PECO Energy Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	0
Net interest (income) expense recognized related to uncertain tax positions			0	0	0
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	0
Net interest (income) expense recognized related to uncertain tax positions			0	0	0
Pepco Holdings LLC [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			0
Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions		$ (2)
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	$ 0
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	0
Net interest (income) expense recognized related to uncertain tax positions			0	0	6
Delmarva Power & Light Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	0
Net interest (income) expense recognized related to uncertain tax positions			0	0	0
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			0	0	0
Net interest (income) expense recognized related to uncertain tax positions			$ 0	$ 0	$ (1)

Income Taxes - Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Jul. 27, 2018

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 1999

Increase in Unrecognized Tax Benefits is Reasonably Possible

$ 71

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

Limitation on Deductible Interest Expense

100.00%

Allowable Expensing For Cost Of Qualified Property

30.00%

Unrecognized Tax Benefits, Income Tax Penalties Expense

$ 477

$ 916

$ 477

$ 743

$ 916

$ 1,078

(2)

106

Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities

Decrease in Unrecognized Tax Benefits is Reasonably Possible

241

Unrecognized Tax Benefits, Period Increase (Decrease)

120

(126)

753

(251)

(196)

(21)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

412

373

(17)

Tax positions for which there is uncertainty about the timing of tax benefits

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

$ 20

463

633

463

523

$ 633

10,203

10,388

Like kind exchange [Member]

9,459

$ 9,288

Deferred gain on sale of property

$ 1,200

Unrecognized Tax Benefits, Income Tax Penalties Expense

$ 90

Decrease in Unrecognized Tax Benefits is Reasonably Possible

$ 33

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

Unrecognized Tax Benefits, Income Tax Penalties Expense

408

490

$ 408

$ 468

$ 490

534

Decrease in Unrecognized Tax Benefits is Reasonably Possible

Unrecognized Tax Benefits, Period Increase (Decrease)

(108)

(1,376)

282

(36)

(17)

(20)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

226

444

Tax positions for which there is uncertainty about the timing of tax benefits

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

408

483

408

461

483

Allocation of federal tax benefit under tax sharing agreement

155

$ 155

$ 102

$ 94

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

Unrecognized Tax Benefits, Income Tax Penalties Expense

(12)

$ 2

$ (12)

142

Unrecognized Tax Benefits, Period Increase (Decrease)

168

417

301

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Tax positions for which there is uncertainty about the timing of tax benefits

(12)

$ (12)

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

Allocation of federal tax benefit under tax sharing agreement

6,343

$ 6,343

6,577

Commonwealth Edison Co [Member] | Like kind exchange [Member]

$ 1,279

Decrease in Unrecognized Tax Benefits is Reasonably Possible

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

Unrecognized Tax Benefits, Income Tax Penalties Expense

$ 0

Unrecognized Tax Benefits, Period Increase (Decrease)

104

149

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Allocation of federal tax benefit under tax sharing agreement

596

$ 596

690

410

Increase in Unrecognized Tax Benefits is Reasonably Possible

120

$ 120

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

Unrecognized Tax Benefits, Income Tax Penalties Expense

120

$ 0

$ 120

120

Decrease in Unrecognized Tax Benefits is Reasonably Possible

120

Unrecognized Tax Benefits, Period Increase (Decrease)

218

174

(120)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Allocation of federal tax benefit under tax sharing agreement

1,269

$ 1,269

1,163

571

Increase in Unrecognized Tax Benefits is Reasonably Possible

$ 59

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

Unrecognized Tax Benefits, Income Tax Penalties Expense

$ 0

$ 59

$ 80

Decrease in Unrecognized Tax Benefits is Reasonably Possible

Unrecognized Tax Benefits, Period Increase (Decrease)

105

(66)

(21)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

829

$ 829

832

891

Increase in Unrecognized Tax Benefits is Reasonably Possible

$ 21

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

^[1]

Unrecognized Tax Benefits, Income Tax Penalties Expense

$ 0

$ 21

$ 37

Decrease in Unrecognized Tax Benefits is Reasonably Possible

Unrecognized Tax Benefits, Period Increase (Decrease)

(22)

(16)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

$ 16

665

$ 665

635

314

Increase in Unrecognized Tax Benefits is Reasonably Possible

$ 14

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

^[1]

Unrecognized Tax Benefits, Income Tax Penalties Expense

$ 14

$ 22

Unrecognized Tax Benefits, Period Increase (Decrease)

(4)

(22)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

420

$ 420

422

430

Increase in Unrecognized Tax Benefits is Reasonably Possible

$ 94

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

21.00%

35.00%

$ 172

$ 45

$ 125

172

Unrecognized Tax Benefits, Period Increase (Decrease)

217

(88)

(61)

Unrecognized Tax Benefits, Income Tax Penalties Accrued

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

Allocation of federal tax benefit under tax sharing agreement

1,948

1,928

3,047

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

^[1]

35.00%

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

$ 3

Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent

35.00%

Decrease in Unrecognized Tax Benefits is Reasonably Possible

172

$ 22

Unrecognized Tax Benefits, Period Increase (Decrease)

$ 17

Internal Revenue Service (IRS) [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

(98)

(471)

600

146

Internal Revenue Service (IRS) [Member] | Exelon Generation Co L L C [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

(347)

(2,005)

(254)

Internal Revenue Service (IRS) [Member] | Commonwealth Edison Co [Member]

Internal Revenue Service (IRS) [Member] | PECO Energy Co [Member]

145

523

379

Internal Revenue Service (IRS) [Member] | Baltimore Gas and Electric Company [Member]

Internal Revenue Service (IRS) [Member] | Potomac Electric Power Company [Member]

101

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

(21)

114

136

Internal Revenue Service (IRS) [Member] | Delmarva Power & Light Company [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

Internal Revenue Service (IRS) [Member] | Atlantic City Electric Company [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

Internal Revenue Service (IRS) [Member] | Pepco Holdings LLC [Member]

Internal Revenue Service (IRS) [Member] | Pepco Holdings LLC [Member] | Successor [Member]

250

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

283

Internal Revenue Service (IRS) [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

State and Local Jurisdiction [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

162

425

Unrecognized Tax Benefits that Would Impact Effective Tax Rate

411

Increase (Decrease) in Income Taxes

$ 16

State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

(83)

(2)

411

Increase (Decrease) in Income Taxes

State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member]

State and Local Jurisdiction [Member] | PECO Energy Co [Member]

117

136

State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member]

(16)

(9)

State and Local Jurisdiction [Member] | Potomac Electric Power Company [Member]

State and Local Jurisdiction [Member] | Delmarva Power & Light Company [Member]

State and Local Jurisdiction [Member] | Atlantic City Electric Company [Member]

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

$ 0

State and Local Jurisdiction [Member] | Pepco Holdings LLC [Member]

Decrease in Unrecognized Tax Benefits is Reasonably Possible

Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit

$ 32

Increase (Decrease) in Income Taxes

$ 17

State and Local Jurisdiction [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Decrease in Unrecognized Tax Benefits is Reasonably Possible

$ 21

State and Local Jurisdiction [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ 13

Net Regulatory Liabilities Associated With Marginal State Income Tax Rates [Member] | State and Local Jurisdiction [Member]

$ 7

Net Regulatory Liabilities Associated With Marginal State Income Tax Rates [Member] | State and Local Jurisdiction [Member] | Delmarva Power & Light Company [Member]

Net Regulatory Liabilities Associated With Marginal State Income Tax Rates [Member] | State and Local Jurisdiction [Member] | Pepco Holdings LLC [Member]

Net Regulatory Assets Associated With Marginal State Income Tax Rates [Member] | State and Local Jurisdiction [Member] | Potomac Electric Power Company [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 1

[1]	DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($)

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Sep. 30, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

^[1]

$ 489,000,000

$ 468,000,000

$ 446,000,000

20,000,000

2,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

(1,000,000)

2,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

489,000,000

468,000,000

446,000,000

Asset Retirement Obligation, Period Increase (Decrease)

$ 203,000,000

$ 84,000,000

$ 138,000,000

180,000,000

34,000,000

Nuclear decommissioning

Asset Retirement Obligation Roll Forward Analysis [Line Items]

Proceeds from Customers

144,000,000

77,000,000

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

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

8,734,000,000

9,662,000,000

^[2]

8,734,000,000

478,000,000

458,000,000

Asset Retirement Obligation, Period Increase (Decrease)

$ 772,000,000

444,000,000

(77,000,000)

34,000,000

Asset Retirement Obligation, Current

10,005,000,000

9,662,000,000

^[2]

8,734,000,000

22,000,000

13,000,000

Asset Retirement Obligation, Liabilities Incurred

(58,000,000)

8,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

(3,000,000)

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Atlantic City Electric Company [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

3,000,000

Asset Retirement Obligation, Period Increase (Decrease)

1,000,000

Asset Retirement Obligation, Liabilities Incurred

4,000,000

3,000,000

^[3]

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 199,000,000

197,000,000

199,000,000

10,000,000

Asset Retirement Obligation, Period Increase (Decrease)

35,000,000

(1,000,000)

(3,000,000)

(7,000,000)

Asset Retirement Obligation, Liabilities Incurred

$ 238,000,000

197,000,000

$ 199,000,000

^[3]

$ 1,000,000

[1]	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	.

Asset Retirement Obligations - Narrative (Details) - USD ($)

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Mar. 31, 2018

Sep. 30, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Jun. 30, 2018

$ 9,679,000,000

$ 10,029,000,000

Percent of additional decommissioning shortfall with recourse

$ 20,000,000

$ 2,000,000

50.00%

Spent Nuclear Fuel Obligation, Noncurrent

$ 11,661,000,000

13,272,000,000

1,171,000,000

1,147,000,000

Line of credit facility, maximum borrowing capacity

^[1]

9,704,000,000

Asset Retirement Obligation, Period Increase (Decrease)

$ 180,000,000

34,000,000

Recovery Stranded Costs

$ 4,000,000

24,000,000

9,450,000,000

9,844,000,000

Shortfall of decommissioning funds with recourse

203,000,000

$ 84,000,000

$ 138,000,000

50,000,000

Spent Nuclear Fuel Obligation, Noncurrent

11,661,000,000

13,272,000,000

1,171,000,000

1,147,000,000

ZionSolutions rent payable

1.00

Line of credit facility, maximum borrowing capacity

$ 200,000,000

$ 45,000,000

Annual average accretion of the ARO

4.863%

Number of years used in present value measurement

30 years

Historical five-year annual average after-tax return on NDT funds

5.00%

Exelon Generation Co L L C [Member] | Minimum [Member]

Estimated annual after tax return on nuclear decommissioning funds

Investment Interest Rate

1000.00%

5.00%

Exelon Generation Co L L C [Member] | Maximum [Member]

Estimated annual after tax return on nuclear decommissioning funds

Investment Interest Rate

7000.00%

6.20%

Nuclear Plant [Member]

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

$ 890,000,000

Asset Retirement Obligation, Period Increase (Decrease)

$ 116,000,000

$ 178,000,000

Decommissioning Liability, Noncurrent

122,000,000

120,000,000

Nuclear decommissioning

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

Proceeds from Customers

144,000,000

77,000,000

Asset Retirement Obligation, Period Increase (Decrease)

(77,000,000)

34,000,000

$ 772,000,000

444,000,000

Zion Station [Member]

Decommissioning Liability, Noncurrent

Zion Station [Member] | Exelon Generation Co L L C [Member]

Decommissioning Liability, Noncurrent

Assets, Total [Member]

$ 12,695,000,000

$ 13,349,000,000

[1]

Asset Retirement Obligations - Unrealized Gain on NDT Funds (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligations [Line Items]
Decommissioning Fund Investments	$ 11,661	$ 13,272
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Decommissioning Fund Investments	11,661	13,272
Collateral Pledged [Member] \| Unregulated Operation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Unrealized Gain (Loss) on Investments	(483)	521	$ 194
Collateral Pledged [Member] \| Regulated Operation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Unrealized Gain (Loss) on Investments	(715)	455	$ 216
Assets, Total [Member]
Asset Retirement Obligations [Line Items]
Decommissioning Fund Investments	$ 12,695	$ 13,349

Asset Retirement Obligations - Pledged Assets and Payables to ZionSolutions (Details) - USD ($)

Dec. 31, 2018

Jun. 30, 2018

Dec. 31, 2017

Line of credit facility, maximum borrowing capacity

^[1]

$ 9,704,000,000

9,679,000,000

$ 10,029,000,000

Line of credit facility, maximum borrowing capacity

200,000,000

$ 45,000,000

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

9,450,000,000

9,844,000,000

Held-to-maturity Securities Pledged as Collateral

^[2]

9,000,000

39,000,000

Accounts Payable, Interest-bearing, Noncurrent

9,000,000

37,000,000

Accounts Payable, Interest-bearing, Current

$ 965

$ 942,000,000

[1]

[2]

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

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($)

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Mar. 23, 2016

Sep. 30, 2017

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 20,000,000

$ 2,000,000

^[1]

489,000,000

$ 468,000,000

446,000,000

20,000,000

2,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 203,000,000

$ 84,000,000

$ 138,000,000

Asset Retirement Obligation, Period Increase (Decrease)

^[1]

489,000,000

468,000,000

446,000,000

180,000,000

34,000,000

203,000,000

84,000,000

138,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 2,000,000

20,000,000

^[1]

2,000,000

20,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 0

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

22,000,000

^[1]

22,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

(1,000,000)

1,000,000

^[1]

(1,000,000)

1,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

(1,000,000)

2,000,000

^[1]

(1,000,000)

2,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

(3,000,000)

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

199,000,000

197,000,000

199,000,000

35,000,000

(1,000,000)

^[2]

1,000,000

Asset Retirement Obligation, Period Increase (Decrease)

10,000,000

(3,000,000)

(7,000,000)

(1,000,000)

(5,000,000)

238,000,000

199,000,000

238,000,000

197,000,000

199,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | PECO Energy Co [Member]

35,000,000

(1,000,000)

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

28,000,000

27,000,000

28,000,000

(1,000,000)

^[2]

Asset Retirement Obligation, Period Increase (Decrease)

^[3]

1,000,000

(1,000,000)

28,000,000

27,000,000

28,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Baltimore Gas and Electric Company [Member]

(1,000,000)

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

24,000,000

2,000,000

^[2]

Asset Retirement Obligation, Period Increase (Decrease)

^[3]

1,000,000

(2,000,000)

25,000,000

24,000,000

25,000,000

24,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Pepco Holdings LLC [Member]

2,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

14,000,000

16,000,000

14,000,000

36,000,000

2,000,000

^[2]

$ 0

Asset Retirement Obligation, Period Increase (Decrease)

52,000,000

14,000,000

52,000,000

16,000,000

14,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Pepco Holdings LLC [Member] | Successor [Member]

36,000,000

2,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Potomac Electric Power Company [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

2,000,000

3,000,000

2,000,000

22,000,000

34,000,000

1,000,000

^[2]

Asset Retirement Obligation, Period Increase (Decrease)

37,000,000

2,000,000

37,000,000

3,000,000

2,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Delmarva Power & Light Company [Member]

22,000,000

34,000,000

1,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

9,000,000

10,000,000

9,000,000

1,000,000

^[2]

Asset Retirement Obligation, Period Increase (Decrease)

11,000,000

9,000,000

11,000,000

10,000,000

9,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Atlantic City Electric Company [Member]

1,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

3,000,000

1,000,000

^[2]

Asset Retirement Obligation, Period Increase (Decrease)

4,000,000

3,000,000

4,000,000

3,000,000

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Enterprise [Member]

1,000,000

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

(7,000,000)

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Commonwealth Edison Co [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

121,000,000

113,000,000

121,000,000

7,000,000

(13,000,000)

^[2]

Asset Retirement Obligation, Period Increase (Decrease)

^[3]

4,000,000

7,000,000

(3,000,000)

(2,000,000)

121,000,000

113,000,000

121,000,000

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

7,000,000

(13,000,000)

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

8,734,000,000

9,662,000,000

^[4]

8,734,000,000

772,000,000

444,000,000

(58,000,000)

8,000,000

Asset Retirement Obligation, Period Increase (Decrease)

478,000,000

458,000,000

(77,000,000)

34,000,000

10,005,000,000

8,734,000,000

10,005,000,000

9,662,000,000

^[4]

8,734,000,000

Asset Retirement Obligation, Current

$ 772,000,000

444,000,000

22,000,000

13,000,000

Nuclear decommissioning | Exelon Enterprise [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 393,000,000

384,000,000

393,000,000

80,000,000

(11,000,000)

^[2]

1,000,000

16,000,000

18,000,000

(6,000,000)

(10,000,000)

$ 471,000,000

$ 393,000,000

471,000,000

384,000,000

$ 393,000,000

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 80,000,000

$ (11,000,000)

[1]	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	.
[3]	(b)In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building, which Pepco retired and closed in 1981.
[4]	Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.

Retirement Benefits Retirement Benefits- Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2018

Dec. 31, 2019

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Increase (Decrease) in Obligation, Pension Benefits

$ 23

Benefit obligation increase (decrease) reflecting actual census data

(14)

Accumulated Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), after Tax

Regulatory asset increase (decrease) due to updated valuation adjustment

Defined benefit plan, amounts recognized In regulatory liabilities, before tax

$ 1

Defined Contribution Plan, Employer Discretionary Contribution Amount

^[1]

$ 179

$ 128

$ 164

Fitzpatrick [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Increase (Decrease) in Obligation, Pension Benefits

Benefit obligation increase (decrease) reflecting actual census data

$ (17)

Projected Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Funded Percentage

81.00%

80.00%

Accumulated Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Funded Percentage

85.00%

88.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Regulatory asset increase (decrease) due to updated valuation adjustment

$ (6)

$ (423)

^[2]

$ 959

7.00%

Defined Contribution Plan, Employer Discretionary Contribution Amount

^[4]

3.62%

^[3],[5]

4.04%

^[6],[7]

4.29%

^[8]

$ 300

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Regulatory asset increase (decrease) due to updated valuation adjustment

$ (57)

$ 125

^[2]

$ 95

6.60%

6.58%

6.71%

Change in Assumptions for Defined Benefit Plans [Member] | Pension Plan, Defined Benefit [Member]

^[4]

3.61%

^[3],[5]

4.04%

^[6],[7]

4.29%

^[7],[8]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

7.00%

Change in Assumptions for Defined Benefit Plans [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

3.62%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

6.60%

Assets [Member] | Pension Plan, Defined Benefit [Member]

3.61%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Assets [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

(4.86%)

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Subsequent Event [Member] | Pension Plan, Defined Benefit [Member]

(4.66%)

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Subsequent Event [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

7.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

6.67%

[1]	Includes $13 million related to CENG for the year ended December 31, 2016
[2]	2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.
[3]	(a)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2018. Certain benefit plans used individual rates ranging from 3.49%-3.65% and 3.57%-3.68% for pension and other postretirement plans, respectively.
[4]	(d)Not applicable to pension and other postretirement benefit plans that do not have plan assets.
[5]	(e)3.25% through 2019 and 3.75% thereafter.
[6]	(b)The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2017. Certain benefit plans used individual rates ranging from 3.66%-4.11% and 4.00%-4.17% for pension and other postretirement plans, respectively.
[7]	(f)The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods.
[8]	(c)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2016. Certain benefit plans used the individual rates ranging from 3.68%-4.14% and 4.32%-4.43% for pension and other postretirement plans, respectively.

Retirement Benefits Retirement Benefits - Summary of Changes in Benefit Obligations and Plan Assets (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 13

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement

$ 48

(34)

Net benefit obligation at beginning of year

22,337

21,060

405

^[1]

387

^[2]

$ 354

Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant

802

^[1]

842

^[2]

830

Actuarial (gain) loss(a)

^[3]

(1,561)

1,182

Plan amendments

(4)

Acquisitions(b)

^[4]

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(1,239)

(1,125)

Net benefit obligation at end of year

20,692

22,337

21,060

Actual return on plan assets

18,573

16,791

(945)

2,600

Defined Benefit Plan, Plan Assets, Contributions by Plan Participant

337

341

Defined Benefit Plan, Plan Assets, Benefits Paid

(1,239)

(1,125)

Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

16,678

18,573

16,791

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

$ 12

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Remeasurement due to Settlement

Net benefit obligation at beginning of year

4,856

4,457

112

^[1]

106

^[2]

107

Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant

175

^[1]

182

^[2]

185

Actuarial (gain) loss(a)

^[3]

(540)

350

Plan amendments

Acquisitions(b)

^[4]

Defined Benefit Plan, Benefit Obligation, Benefits Paid

(275)

(309)

Net benefit obligation at end of year

4,369

4,856

4,457

Actual return on plan assets

2,732

2,578

(136)

346

Defined Benefit Plan, Plan Assets, Contributions by Plan Participant

Defined Benefit Plan, Plan Assets, Benefits Paid

(275)

(309)

Other Postretirement Benefit Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ 2,408

$ 2,732

$ 2,578

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

$ 6

[1]	FitzPatrick net benefit costs are included for the period after acquisition.
[2]	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.
[3]	(a)The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience. The pension and OPEB actuarial losses in 2017 primarily reflect a decrease in the discount rate.
[4]	(b)Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017.

Retirement Benefits Retirement Benefits - Balance Sheet locations of Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	$ 26	$ 28
Pension obligations	3,988	3,736
Non-pension postretirement benefit obligations	0	0
Unfunded status (net benefit obligation less plan assets)	4,014	3,764
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	33	31
Pension obligations	0	0
Non-pension postretirement benefit obligations	1,928	2,093
Unfunded status (net benefit obligation less plan assets)	$ 1,961	$ 2,124

Retirement Benefits Reitrement Benefits- Projected Benefit Obligations and Accumulated Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Projected Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 20,692	$ 22,337
Fair value of net plan assets	16,678	18,573
Accumulated Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 19,656	$ 21,153

Retirement Benefits Retirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 47

$ 109

$ 116

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

^[1]

(1,561)

1,182

405

^[2]

387

^[3]

354

802

^[2]

842

^[3]

830

(1,252)

^[2]

(1,196)

^[3]

(1,141)

^[2]

^[3]

Settlement and other charges(c)

629

^[2]

607

^[3]

554

^[2],[4]

^[3],[4]

Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

589

^[2]

644

^[3]

613

$ 12

(14)

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)

^[1]

(540)

350

112

^[2]

106

^[3]

107

175

^[2]

182

^[3]

185

(173)

^[2]

(162)

^[3]

(162)

(186)

^[2]

(188)

^[3]

(185)

Settlement and other charges(c)

^[2]

^[3]

^[2],[4]

^[3],[4]

Other Postretirement Benefit Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ (5)

^[2]

$ (1)

^[3]

$ 8

(3)

(2)

$ 1

[1]	(a)The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate and favorable health care claims experience. The pension and OPEB actuarial losses in 2017 primarily reflect a decrease in the discount rate.
[2]	FitzPatrick net benefit costs are included for the period after acquisition.
[3]	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.
[4]	2016 amount includes an additional termination benefit for PHI.

Retirement Benefits Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets (Liabilities) related to Retirement Plans (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2018

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 61

$ 635

$ (222)

^[1]

$ 644

Current year prior service cost (credit)

(629)

(607)

^[1]

(554)

(4)

^[1]

(60)

(2)

(1)

^[1]

(14)

DefinedBenefitPlanAccumulatedOtherComprehensiveIncomeAndRegulatoryAssetsAcqusition

(3)

^[1]

^[1]

994

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

(3)

(824)

1,010

Defined benefit plan, amounts recognized in OCI, before tax

(401)

^[1]

Defined benefit plan, amounts recognized in regulatory assets, before tax

(6)

(423)

^[1]

959

Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ 0

(14)

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

(14)

Defined benefit plan, amounts recognized in OCI, before tax

(1)

Defined benefit plan, amounts recognized in regulatory assets, before tax

(13)

Other Postretirement Benefit Plan, Defined Benefit [Member]

(232)

166

^[1]

(101)

Current year prior service cost (credit)

(66)

(61)

^[1]

(63)

^[1]

186

188

^[1]

185

DefinedBenefitPlanAccumulatedOtherComprehensiveIncomeAndRegulatoryAssetsAcqusition

^[1]

^[1]

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

(112)

293

115

Defined benefit plan, amounts recognized in OCI, before tax

(55)

168

^[1]

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ (57)

$ 125

^[1]

$ 95

Other Postretirement Benefit Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

(2)

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

Defined benefit plan, amounts recognized in OCI, before tax

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 1

[1]	2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.

Retirement Benefits Retirement Benefits - Gross Accumulated Other Comprehensive Loss and Regulatory Assets (Liabilities) not Recognized as Components of Periodic Benefit Cost (Details) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service (credit) cost	$ (29)	$ (24)
Actuarial loss	7,558	7,556
Total	7,529	7,532
Benefits included in accumulated other comprehensive income	3,899	3,896
Benefits included in regulatory assets	3,630	3,636
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service (credit) cost	(337)	(522)
Actuarial loss	531	829
Total	194	307
Benefits included in accumulated other comprehensive income	70	125
Benefits included in regulatory assets	$ 124	$ 182

Retirement Benefits Retirement Benefits - Assumptions Used in Calculations (Details)

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 24, 2016

^[8]

CENG Legacy Benefit Plans [Member] | Minimum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

3.49%

3.66%

3.68%

CENG Legacy Benefit Plans [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

3.65%

4.11%

4.14%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Net Periodic Benefit Cost Investment Crediting Rate

4.00%

4.46%

5.31%

Benefit Obligation Investment Crediting Rate

4.46%

4.00%

4.46%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets

7.00%

Pension Plan, Defined Benefit [Member] | CENG Legacy Benefit Plans [Member] | Minimum [Member]

4.31%

^[1],[2]

3.62%

^[2],[3]

4.04%

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

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

4.13%

3.49%

3.66%

Pension Plan, Defined Benefit [Member] | CENG Legacy Benefit Plans [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

4.36%

3.65%

4.11%

Pension Plan, Defined Benefit [Member] | Period One [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

3.25%

Pension Plan, Defined Benefit [Member] | Period One [Member] | CENG Legacy Benefit Plans [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

3.25%

Pension Plan, Defined Benefit [Member] | Period Two [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

3.75%

Pension Plan, Defined Benefit [Member] | Period Two [Member] | CENG Legacy Benefit Plans [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

3.75%

Pension Plan, Defined Benefit [Member] | Predecessor [Member] | Pepco Holdings LLC [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Rate of compensation increase

5.00%

Net Periodic Benefit Cost Investment Crediting Rate

2.89%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets

^[7]

6.50%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

5.00%

Qualified Plan [Member] | Predecessor [Member] | Pepco Holdings LLC [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Non-Qualified Pension Plan [Member] | Predecessor [Member] | Pepco Holdings LLC [Member]

^[8]

4.65%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Other Postretirement Benefit Plan, Defined Benefit [Member]

4.55%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Health care cost trend rate

5.00%

5.50%

Ultimate health care cost trend rate

5.00%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets

6.60%

6.58%

6.71%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Minimum [Member]

4.30%

^[1],[2]

3.61%

^[2],[3]

4.04%

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

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

3.57%

4.00%

4.32%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

3.68%

4.17%

4.43%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | CENG Legacy Benefit Plans [Member] | Minimum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

4.27%

3.57%

4.00%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | CENG Legacy Benefit Plans [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

4.38%

3.68%

4.17%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Predecessor [Member] | Pepco Holdings LLC [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets

^[7]

6.75%

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

5.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

4.55%

[1]	(a)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2018. Certain benefit plans used individual rates ranging from 4.13% - 4.36% and 4.27% - 4.38% for pension and other postretirement plans, respectively.
[2]	(d)3.25% through 2019 and 3.75% thereafter.
[3]	(b)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2017. Certain benefit plans used individual rates ranging from 3.49% - 3.65% and 3.57% - 3.68% for pension and other postretirement plans, respectively.
[4]	(c)The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of December 31, 2016. Certain benefit plans used individual rates ranging from 3.66% - 4.11% and 4.00% - 4.17% for pension and other postretirement plans, respectively.
[5]	(e)The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the legacy PHI pension and other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods.
[6]	(f)Obligation was not remeasured for the PHI predecessor for the period from January 1, 2016, to March 23, 2016.
[7]	(h)Expected return on other postretirement benefit plan assets is pre-tax.
[8]	(g)The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55%, respectively.

Retirement Benefits Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2018 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2018	$ 25
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2018	1,196
2019	1,221
2020	1,258
2021	1,284
2022	1,302
2022 through 2026	6,770
Total estimated future benefit payments through 2028	13,031
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2018	255
2019	263
2020	269
2021	274
2022	282
2022 through 2026	1,483
Total estimated future benefit payments through 2028	$ 2,826

Retirement Benefits Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Amount included in capital and operating & maintenance expense

$ 583

$ 643

$ 621

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[1]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[2]

204

227

218

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

177

176

166

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 67

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 94

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

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[3],[4]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[3]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[3]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 3

$ 12

^[3]

$ 13

^[3]

$ 15

^[3]

[1]	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.
[2]	FitzPatrick net benefit costs are included for the period after acquisition
[3]	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the year ended December 31, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.
[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 Retirement Benefits - Pension and Other Postretirement Benefit Plan Target Asset Allocations (Details)

Dec. 31, 2018

Dec. 31, 2017

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Pension Plan, Defined Benefit [Member] | Equity Securities [Member]

100.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

35.00%

Pension Plan, Defined Benefit [Member] | Fixed Income Securities [Member]

32.00%

35.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

37.00%

Pension Plan, Defined Benefit [Member] | Alternative Investments [Member]

38.00%

39.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

28.00%

Other Postretirement Benefit Plan, Defined Benefit [Member]

^[1]

30.00%

26.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Other Postretirement Benefit Plan, Defined Benefit [Member] | Equity Securities [Member]

100.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

47.00%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Fixed Income Securities [Member]

44.00%

47.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

28.00%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Alternative Investments [Member]

28.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

25.00%

^[1]

28.00%

25.00%

[1]	Alternative investments include private equity, hedge funds, real estate, and private credit

Retirement Benefits Retirement Benefits - Reconciliation of Level 3 Assets and Liabilities measured at Fair Value for Pension and Other Postretirement Benefit Plans (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 18,573

$ 16,791

Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]

16,678

18,573

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Relating to assets still held at the reporting date

458

437

(5)

Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Sold

(1)

(12)

^[1]

(39)

Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member]

486

458

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Relating to assets still held at the reporting date

232

206

(14)

Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Sold

(1)

(12)

^[1]

Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Equity Security Individually Held [Member]

216

232

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Relating to assets still held at the reporting date

Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Sold

^[1]

Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Private Placement [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Relating to assets still held at the reporting date

224

229

^[2]

Defined Benefit Plan, Plan Assets Level 3 Reconciliation, Increase (Decrease) for Actual Return (Loss) on Plan Assets Sold

^[1]

(39)

Fair Value, Measurements, Recurring [Member]

268

224

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

3,433

3,534

^[3],[4]

21,303

Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]

^[3],[4]

19,130

^[5]

21,303

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[3],[4]

458

Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member]

^[3],[4]

486

^[5]

458

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

7,247

^[5]

8,216

^[4]

18,575

Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member] | Debt Securities [Member]

^[4]

16,720

^[5]

18,575

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

613

^[5]

756

^[4]

6,739

Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member] | Private Placement [Member]

^[4]

6,102

^[5]

6,739

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

798

^[5]

695

^[4]

919

Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member]

^[4]

1,066

^[5]

919

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

458

Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Debt Securities [Member]

^[4]

486

^[5]

458

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

232

Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member] | Fair Value, Inputs, Level 3 [Member] | Private Placement [Member]

^[4]

216

^[5]

232

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

224

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

$ 268

^[5]

$ 224

[1]	(b)Represents cash settlements only.
[2]	(a)Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.
[3]	Excludes net liabilities of $44 million and net assets of $2 million at December 31, 2018 and 2017, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables or payables related to pending securities sales and purchases, interest and dividends receivable
[4]	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy
[5]	Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan obligations

Retirement Benefits Retirement Benefits - Summary of Defined Contribution Savings Plan (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

^[1]

$ 179

$ 128

$ 164

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[2]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

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

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 1

^[3],[4]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 13

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[3]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 1

^[3]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Common Stock Narrative Information [Line Items]

^[3]

$ 2

[1]	Includes $13 million related to CENG for the year ended December 31, 2016
[2]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above
[3]	Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016
[4]	These amounts primarily represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts above.

Severance Severance - PHI Merger (Details) - PHI Merger [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 57
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	9
Commonwealth Edison Co [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	2
PECO Energy Co [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1
Baltimore Gas and Electric Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1
Pepco Holdings LLC [Member] \| Successor [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	44
Potomac Electric Power Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	21
Delmarva Power & Light Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	13
Atlantic City Electric Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 10

Severance Severance - Liabilities Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	$ 77	$ 94	$ 88
Payments for Restructuring		(29)
Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	35	35
Payments for Restructuring	(52)
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	47	58	36
Payments for Restructuring		(9)
Exelon Generation Co L L C [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	9	31
Payments for Restructuring	(20)
Commonwealth Edison Co [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	2	3	3
Payments for Restructuring		(2)
Commonwealth Edison Co [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1	2
Payments for Restructuring	(2)
PECO Energy Co [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	0	0	0
Payments for Restructuring		0
PECO Energy Co [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0
Payments for Restructuring	0
Baltimore Gas and Electric Company [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	1	0	0
Payments for Restructuring		0
Baltimore Gas and Electric Company [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1	0
Payments for Restructuring	0
Pepco Holdings LLC [Member] \| Successor [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	7	20	29
Payments for Restructuring		(12)
Pepco Holdings LLC [Member] \| Successor [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	5	3
Payments for Restructuring	(18)
Potomac Electric Power Company [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	0	0	0
Payments for Restructuring		0
Potomac Electric Power Company [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1	0
Payments for Restructuring	(1)
Delmarva Power & Light Company [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	0	0	0
Payments for Restructuring		0
Delmarva Power & Light Company [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	0
Payments for Restructuring	0
Atlantic City Electric Company [Member]
Restructuring Cost and Reserve [Line Items]
Restructuring Reserve	0	0	$ 0
Payments for Restructuring		0
Atlantic City Electric Company [Member] \| Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0	$ 0
Payments for Restructuring	$ 0

Shareholders' Equity Schedule of Common Stock Authorized and Outstanding (Details) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Class of Stock [Line Items]
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	968,187,955	963,335,888
Common Stock [Member]
Class of Stock [Line Items]
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock [Member] \| Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 12.50	$ 12.50
Common stock, shares authorized	250,000,000	250,000,000
Common stock, shares outstanding	127,021,331	127,021,246
Common Stock [Member] \| PECO Energy Co [Member]
Class of Stock [Line Items]
Common stock, shares authorized	500,000,000	500,000,000
Common stock, shares outstanding	170,478,507	170,478,507
Common Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Common stock, shares authorized	1,500	1,500
Common stock, shares outstanding	1,000	1,000
Common Stock [Member] \| Potomac Electric Power Company [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common stock, shares authorized	200,000,000	200,000,000
Common stock, shares outstanding	100	100
Common Stock [Member] \| Delmarva Power & Light Company [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 2.25	$ 2.25
Common stock, shares authorized	1,000	1,000
Common stock, shares outstanding	1,000	1,000
Common Stock [Member] \| Atlantic City Electric Company [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 3.00	$ 3.00
Common stock, shares authorized	25,000,000	25,000,000
Common stock, shares outstanding	8,546,017	8,546,017

Shareholders' Equity Shareholder Narrative (Details) - USD ($) $ / shares in Units, $ in Millions						12 Months Ended
	Jun. 01, 2017	Sep. 19, 2016	Sep. 18, 2016	Jul. 03, 2016	Jul. 03, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Jun. 30, 2017	Jul. 30, 2015	Jun. 30, 2014
Schedule of Capitalization, Equity [Line Items]
Stock Repurchased During Period, Shares							33,000,000	0
Temporary Equity, Share Subscriptions										57,500,000	57,500,000
Sale of Stock, Price Per Share										$ 32.48
Treasury Stock, Number of Shares Held						2,000,000	2,000,000
Treasury stock, at cost						$ 123	$ 123
Stock Repurchased During Period, Value						$ 0		$ 0
Stock Redeemed or Called During Period, Value								(193)
Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized						100,000,000	100,000,000
Preferred Stock, Shares Outstanding						0	0
Equity units issued [Member]
Schedule of Capitalization, Equity [Line Items]
Stock Issued During Period, Shares, Treasury Stock Reissued	33,000,000
Minimum [Member]
Schedule of Capitalization, Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value										$ 1,870
Commonwealth Edison Co [Member]
Schedule of Capitalization, Equity [Line Items]
Class of Warrant or Right, Outstanding						60,285	60,584
Commonwealth Edison Co [Member] \| Common Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Common Stock Shares Reserved For Warrant Conversion						20,095	20,195
Commonwealth Edison Co [Member] \| Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized						850,000	850,000
Preferred Stock, Shares Outstanding						0	0
Commonwealth Edison Co [Member] \| Cumulative Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized						6,810,451	6,810,451
Preferred Stock, Shares Outstanding						0	0
Baltimore Gas and Electric Company [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Value, Outstanding								$ 190
Preferred Stock, Redemption Price Per Share								$ 100
Stock Redeemed or Called During Period, Shares		400,000	500,000	400,000	600,000
Preferred Stock, Dividend Rate, Percentage		6.70%	6.97%	7.125%	6.99%
Stock Redeemed or Called During Period, Value			$ 90	$ 100				$ (190)
Junior Subordinated Debt [Member]
Schedule of Capitalization, Equity [Line Items]
Shares Issued, Price Per Share									$ 35
Junior Subordinated Notes							$ 1,150				$ 1,150
Equity units issued											23,000,000
Stock Issued During Period, Shares, Treasury Stock Reissued							33,000,000

Stock-Based Compensation Plans - Narrative (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Obligations of outstanding restricted stock not settled

$ 83

$ 108

Settlement of restricted stock

106

$ 88

$ 68

Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options

$ 33

Weighted Average Period Non Vested Performance Share Awards Are Expected To Be Recognized Over

1 year 8 months

Performance Shares [Member]

Common Stock Narrative Information [Line Items]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 38.15

^[1]

$ 35.00

$ 28.85

Percentage to be settled as common stock

50.00%

Percentage to be settled as cash

50.00%

Percentage to be settled as cash if ownership requirements are met

100.00%

Performance Shares [Member] | Pepco Holdings LLC [Member]

Common Stock Narrative Information [Line Items]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

26.10

Employee Stock Option [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

4 years

Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition

1 year 8 months 12 days

Restricted Stock Units (RSUs) [Member]

Common Stock Narrative Information [Line Items]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 38.60

$ 34.98

$ 28.14

Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options

$ 38

Minimum [Member] | Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

3 years

Maximum [Member] | Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

5 years

LTIP [Member]

Common Stock Narrative Information [Line Items]

Shares authorized

[1]	(a)As of December 31, 2018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.

Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

$ 208

$ 191

$ 175

^[1]

(18)

Allocated Share-based Compensation Expense, Net of Tax

154

117

107

^[1]

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

143

107

^[1]

(16)

(29)

(18)

Restricted Stock Units (RSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

^[1]

(28)

(35)

(27)

Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Stock Compensation Plan [Member]

^[1]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

^[1]

$ (54)

$ (74)

$ (68)

^[1]

Predecessor [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

$ 3

(1)

Allocated Share-based Compensation Expense, Net of Tax

Predecessor [Member] | Pepco Holdings LLC [Member] | Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Restricted Stock Units (RSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 0

[1]	(a)2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

Stock-Based Compensation Plans - Schedule of Pre-Tax Stock-based Compensation Expense (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 208

$ 191

$ 175

^[1]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 3

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

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

^[2]

111

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

^[3],[4]

$ 4

[1]	(a)2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.
[2]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE or PHI amounts above.
[3]	Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 2018 and 2017 was not material.
[4]	These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations.

Stock-Based Compensation Plans - Components of Tax Benefits from Stock-based Compensation (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation				$ (18)
Restricted Stock Units (RSUs) [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation		$ (28)	$ (35)	(27)
Performance Shares [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation		$ (16)	$ (29)	$ (18)
Pepco Holdings LLC [Member] \| Predecessor [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation	$ (1)

Stock-Based Compensation Plans - Summary of Stock Option Activity (Details) - Employee Stock Option [Member] - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

6,723,611

(1,522,952)

(1,173,007)

4,027,652

6,723,611

Weighted Average Exercise Price (in usd per share)

$ 43.95

$ 47.69

Options Exercised, Weighted Average Exercise Price (in usd per share)

36.54

Options Forfeited, Weighted Average Exercise Price (in usd per share)

0.00

Options Expired, Weighted Average Exercise Price (in usd per share)

$ 74.99

Shares Outstanding, Weighted Average Remaining Contractual Life

2 years 10 months 24 days

2 years 7 months 24 days

Exercisable at December 31, 2017

^[1]

4,027,652

Shares Exercisable, Weighted Average Exercise Price (in usd per share)

^[1]

$ 43.95

Shares Exercisable, Weighted Average Remaining Contractual Life

^[1]

2 years 10 months 24 days

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value

$ 14

$ 7

Shares Exercisable, Aggregate Intrinsic Value

^[1]

$ 14

[1]	Includes stock options issued to retirement eligible employees.

Stock-Based Compensation Plans - Summary of Information of Stock Options Exercised (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Common Stock [Abstract]

Aggregate value

^[1]

$ 12

$ 15

$ 11

Cash received for exercise price

$ 56

$ 107

$ 19

[1]	The difference between the market value on the date of exercise and the option exercise price.

Stock-Based Compensation Plans - Summary of Nonvested Restricted Stock Unit Activity (Details) - Restricted Stock Units (RSUs) [Member] - $ / shares

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Undistributed vested awards

^[1]

3,389,503

Granted

1,321,988

Vested

(1,845,300)

Forfeited

(65,046)

^[2]

(507,804)

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

2,293,341

3,389,503

^[1]

$ 32.24

Granted, Weighted Average Grant Date Fair Value (in usd per share)

38.60

$ 34.98

$ 28.14

Vested, Weighted Average Exercise Price (in usd per share)

32.03

Forfeited, Weighted Average Exercise Price (in usd per share)

32.96

Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)

^[2]

36.76

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

$ 35.06

$ 32.24

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

1,131,487

1,488,383

[1]	Excludes 1,131,487 and 1,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.
[2]	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2018.

Stock-Based Compensation Plans - Summary of Nonvested Performance Share Awards Activity (Details) - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options

$ 33

Weighted Average Period Non Vested Performance Share Awards Are Expected To Be Recognized Over

1 year 8 months

Fair Value Of Settled Performance Share Awards

$ 61

^[1]

$ 72

$ 45

Performance Share Awards Obligations Settled In Cash

$ 49

^[1]

$ 56

$ 28

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Period Increase (Decrease)

^[2]

2,956,966

Granted

1,637,542

1,348,029

Vested

(848,574)

Forfeited

(50,467)

Undistributed vested awards

^[3]

(1,640,268)

Nonvested, Weighted Average Exercise Price (in usd per share)

^[2]

3,403,228

2,956,966

^[2]

$ 33.13

$ 32.65

Granted, Weighted Average Grant Date Fair Value (in usd per share)

38.15

^[1]

$ 35.00

$ 28.85

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Change in Performance, Weighted Average Grant Date Fair Value

30.66

Vested, Weighted Average Exercise Price (in usd per share)

36.26

Forfeited, Weighted Average Exercise Price (in usd per share)

36.24

Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)

^[3]

$ 33.38

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

3,586,259

2,723,440

Performance Shares [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 26.10

[1]	(a)As of December 31, 2018, $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.7 years.
[2]	Excludes 3,586,259 and 2,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 2018 and 2017, respectively, as they are fully vested.
[3]	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2018.

Stock-Based Compensation Plans - Balance Sheet Classification of Obligations related to Outstanding Performance Share Awards Not Yet Settled (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Classification Of Obligations Related To Outstanding Performance Share Awards Not Yet Settled Current Liabilities

^[1]

$ 135

$ 57

Classification Of Obligations Related To Outstanding Performance Share Awards Not Yet Settled Deferred Credits And Other Liabilities

^[2]

109

100

Classification Of Obligations Related To Outstanding Performance Share Awards Not Yet Settled Common Stock

Total Balance Sheet Classification Of Obligations Related To Outstanding Performance Share Awards Not Yet Settled

$ 270

$ 183

[1]	Represents the current liability related to performance share awards expected to be settled in cash.
[2]	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share Earnings Per Share - Schedule of Earnings per Share (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Earnings Per Share [Abstract]
Net income (loss) attributable to common shareholders	$ 152	$ 733	$ 539	$ 585	$ 1,880	$ 823	$ 95	$ 990	$ 2,010	$ 3,786	$ 1,121
Weighted average common shares outstanding — basic									967	947	924
Assumed exercise and/or distributions of stock-based awards									2	2	3
Weighted average common shares outstanding — diluted									969	949	927

Earnings Per Share Earnings Per Share - Narrative (Details) - shares shares in Millions		12 Months Ended
	Jun. 01, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Equity units issued [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock Issued During Period, Shares, Treasury Stock Reissued	33
Pepco Holdings [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger)		0	0	0
Employee Stock Option [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger)		3	8	12

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Movement in Accumulated Other Comprehensive Income [Roll Forward]

$ 32,187

$ 27,640

$ 27,330

^[1]

182

144

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

171

(36)

539

Gains and (Losses) on Cash Flow Hedges

33,070

32,187

27,640

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(14)

(17)

^[2]

(1)

^[2],[3]

^[2]

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

^[2]

(2)

(14)

(17)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

Unrealized Gains and (losses) on Marketable Securities

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

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

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

(10)

Pension and Non-Pension Postretirement Benefit Plan Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(2,998)

(2,610)

^[2]

(143)

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

181

140

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

^[2]

151

^[2],[5]

(539)

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

^[2]

(2,960)

(2,998)

(2,610)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

Foreign Currency Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(23)

(30)

^[2]

(10)

^[2],[3]

^[2]

(10)

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

^[2]

(33)

(23)

(30)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

AOCI of Investments Unconsolidated Affiliates

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(1)

(7)

^[2]

^[2],[3]

^[2]

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

^[2]

(1)

(7)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(3,026)

^[2]

(2,660)

^[2]

(2,624)

^[2]

(141)

^[2],[3]

182

144

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

^[2]

173

^[2]

(36)

^[2],[5]

(539)

Total | Accounting Standards Update 2016-01 [Member]

^[2]

(2,995)

(3,026)

(2,660)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

(10)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(16)

(19)

^[2]

(1)

^[2],[3]

^[2]

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

^[2]

(4)

(16)

(19)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

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

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

(3)

Exelon Generation Co L L C [Member] | Pension and Non-Pension Postretirement Benefit Plan Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

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

^[2]

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

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(23)

(30)

^[2]

(10)

^[2],[3]

^[2]

(10)

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

^[2]

(33)

(23)

(30)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

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

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(1)

(7)

^[2]

^[2],[3]

^[2]

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

^[2]

(1)

(7)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

Exelon Generation Co L L C [Member] | Total

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

(37)

(54)

^[2]

^[2],[3]

^[2]

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

^[2]

(38)

(37)

(54)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

(3)

PECO Energy Co [Member] | Gains and (Losses) on Cash Flow Hedges

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

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

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

PECO Energy Co [Member] | Unrealized Gains and (losses) on Marketable Securities

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

PECO Energy Co [Member] | Unrealized Gains and (losses) on Marketable Securities | Accounting Standards Update 2016-01 [Member]

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

(1)

PECO Energy Co [Member] | Pension and Non-Pension Postretirement Benefit Plan Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

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

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

PECO Energy Co [Member] | Foreign Currency Items

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

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

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

PECO Energy Co [Member] | AOCI of Investments Unconsolidated Affiliates

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

PECO Energy Co [Member] | AOCI of Investments Unconsolidated Affiliates | Accounting Standards Update 2016-01 [Member]

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

PECO Energy Co [Member] | Total

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[2]

^[2]

^[2],[3]

^[2]

PECO Energy Co [Member] | Total | Accounting Standards Update 2016-01 [Member]

^[2]

$ 1

Movement in Accumulated Other Comprehensive Income [Roll Forward]

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

^[2],[4]

$ (1)

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.
[3]	See next tables for details about these reclassifications.
[4]	Exelon prospectively adopted the new standard Recognition and Measurement of Financial Assets and Financial 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 1 — Significant Accounting Policies for additional information.
[5]	Exelon early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated with Exelon’s pension and OPEB obligations. See Note 1 — Significant Accounting Policies for additional information.

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Mar. 23, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

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

$ (112)

$ 947

$ 297

$ 26

120

(126)

753

Amortization of pension and other postretirement benefit plan items

2,084

3,876

1,196

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

^[1]

(182)

(144)

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

Gains and (Losses) on Cash Flow Hedges

(1)

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

Gains and (Losses) on Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

^[2],[3]

(1)

(4)

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

Other cash flow hedges

^[1]

(1)

(5)

Total before tax

^[1]

(1)

(5)

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

^[1]

Net of tax

^[1]

(1)

(4)

Prior service costs

Amortization of pension and other postretirement benefit plan items

^[1],[4]

Actuarial losses

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

Amortization of pension and other postretirement benefit plan items

^[1],[4]

(333)

(324)

Pension and Non-Pension Postretirement Benefit Plan Items

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

Amortization of pension and other postretirement benefit plan items

^[1]

(243)

(232)

Tax benefit

^[1]

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

(181)

(140)

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

(178)

948

401

(108)

(1,376)

282

Amortization of pension and other postretirement benefit plan items

443

2,798

$ 550

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

^[1]

(1)

(4)

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

Exelon Generation Co L L C [Member] | Gains and (Losses) on Cash Flow Hedges | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

^[2],[3]

(1)

(4)

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

Other cash flow hedges

^[1]

(1)

(5)

Total before tax

^[1]

(1)

(5)

Exelon Generation Co L L C [Member] | Prior service costs

^[1]

Net of tax

^[1]

(1)

(4)

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

Amortization of pension and other postretirement benefit plan items

^[1],[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

^[1],[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

^[1]

Tax benefit

^[1]

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

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

217

$ 398

$ 362

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

$ (4)

$ 19

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.
[3]	See next tables for details about these reclassifications.
[4]	This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 16 — Retirement Benefits for additional information.

Changes in Accumulated Other Comprehensive Income - Components of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	$ (17)	$ (90)	$ 30
Prior service costs
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	24	36	30
Actuarial losses
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(86)	(128)	(118)
Pension and Non-Pension Postretirement Benefit Plan Items
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	50	13	115
Gains and (Losses) on Cash Flow Hedges
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(5)	(7)	0
Unrealized Gains and (losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gains (losses) on investments in unconsolidated affiliates	0	(3)	3
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	0	(1)	0
Exelon Generation Co L L C [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Tax	(5)	(10)	1
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	(4)	(6)	(2)
Exelon Generation Co L L C [Member] \| Unrealized Gains and (losses) on Marketable Securities
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gains (losses) on investments in unconsolidated affiliates	(1)	(3)	3
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$ 0	$ (1)	$ 0

Commitments and Contingencies Commitments and Contingencies - Narrative (Details)

3 Months Ended

12 Months Ended

Nov. 04, 2016

Nov. 01, 2015

USD ($)

Sep. 23, 2015

USD ($)

Dec. 31, 2018

USD ($)

employee

Open_claim

MGPSite

Sep. 30, 2018

USD ($)

Dec. 31, 2017

USD ($)

Dec. 31, 2018

USD ($)

employee

Open_claim

MGPSite

Dec. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

Feb. 17, 2012

USD ($)

^[1],[2]

$ 1,378,000,000

Business Acquisition Residual Commitment | MW

$ 1,000,000,000

Power Volume | MW

220

Loss Contingency, Loss in Period

$ 50,000,000

Nontrade Receivables, Current

^[3]

124,000,000

$ 94,000,000

$ 124,000,000

94,000,000

Nontrade Receivables, Noncurrent

^[4]

15,000,000

Accounts Payable, Other, Current

^[3],[5]

(17,000,000)

(11,000,000)

(17,000,000)

(11,000,000)

DOE Spent Nuclear Fuel One Time Fee

34,000,000

^[6]

32,143,000,000

29,619,000,000

28,106,000,000

^[1],[2]

763,000,000

Entity Number of Employees | employee

1,500

Leasehold Improvements, Gross

$ 90,000,000

Lessee, Operating Lease, Term of Contract

20 years

Costs Incurred, Development Costs

458,000,000

Nuclear financial protection pool value

450,000,000

Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses

13,600,000,000

Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident

3,100,000,000

Mutual Insurance Total Retrospective Premium Obligation

345,000,000

Mutual Replacement Power Cost Insurance Maximum Retrospective Premium Obligation

3,200,000,000

Cost of spent nuclear fuel disposal per kWh of net nuclear generation

0.001

Spent Nuclear Fuel Storage Reimbursement

^[7]

1,274,000,000

Spent Nuclear Fuel Storage Reimbursement Net Co Owners

^[7],[8]

1,100,000,000

DOE Spent Nuclear Fuel One Time Fee

277,000,000

DOE Spent Nuclear Fuel One Time Fee With Interest

1,171,000,000

1,147,000,000

$ 1,171,000,000

1,147,000,000

Spent Nuclear Fuel Treasury Interest Rate

2.351%

Loss Contingency Accrual, Provision

20,000,000

Environmental loss contingencies

90,000,000

Asbestos Liability Reserve

$ 79,000,000

78,000,000

$ 79,000,000

78,000,000

Open Asbestos Liability Claims | Open_claim

238

Exelon Generation Co L L C [Member] | Minimum [Member]

Business Acquisition, Expected New Generation Mwh | MW

$ 450,000,000

285

Exelon Generation Co L L C [Member] | Maximum [Member]

Business Acquisition, Expected New Generation Mwh | MW

500,000,000

$ 500,000,000

300

Exelon Generation Co L L C [Member] | West Lake [Member]

Loss Contingency Accrual, Provision

280,000,000

Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]

Nuclear insurance liability limit per incident

14,100,000,000

$ 14,100,000,000

Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member] | Maximum [Member]

Nuclear financial protection pool value

$ 454,000,000

Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

Mutual Property Insurance Distribution To Members

58,000,000

60,000,000

58,000,000

60,000,000

$ 21,000,000

^[2],[9]

23,000,000

Sites under study/remediation | MGPSite

Other Increase (Decrease) in Environmental Liabilities

$ 48,000,000

^[2],[9]

$ 25,000,000

Sites under study/remediation | MGPSite

^{[2],[9],[10],[11]}

$ 143,000,000

Sites under study/remediation | MGPSite

Common Equity Tier One Capital Ratio

48.00%

Occupancy, Net

$ 42,000,000

$ 12,000,000

Operating Leases, Income Statement, Initial Direct Costs

25,000,000

Oil and Gas Property, Lease Operating Expense

29,000,000

28,000,000

^[2]

$ 377,000,000

^[2]

86,000,000

Accrued Liabilities and Other Liabilities

30,000,000

28,000,000

30,000,000

28,000,000

^[2],[9]

96,000,000

Common Equity Tier One Capital Ratio

48.00%

^[2]

$ 32,000,000

Common Equity Tier One Capital Ratio

30.00%

Open Claims [Member] | Exelon Generation Co L L C [Member]

Asbestos Liability Reserve

$ 24,000,000

Estimated Future Claims [Member] | Exelon Generation Co L L C [Member]

Asbestos Liability Reserve

$ 55,000,000

[1]	)Excludes Generation’s contingent operating lease payments associated with contracted generation agreement
[2]	)Includes amounts related to shared use land arrangement
[3]	)Recorded in Accounts receivable, other.
[4]	)Recorded in Deferred debits and other assets, oth
[5]	)Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities
[6]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.
[7]	)Includes $53 and $49, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CEN
[8]	)Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Cree
[9]	)Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectivel
[10]	)The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022 , respectivel
[11]	)The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022 , respectivel

Commitments and Contingencies Commitments and Contingencies - Schedule of Minimum Future Operating Lease Payments (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Nov. 30, 2016

Operating Leases Future Minimum Payments Due [Line Items]

^[1],[2]

$ 140

^[1],[2]

149

^[1],[2]

143

^[1],[2]

126

^[1],[2]

Remaining Years

^[1],[2]

723

^[1],[2]

1,378

Operating Leases Future Minimum Payments Due [Line Items]

^[1],[2]

^[1],[2]

^[1],[2]

^[1],[2]

^[1],[2]

^[1],[2]

545

^[1],[2]

763

Operating Leases Future Minimum Payments Due [Line Items]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

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

^[2],[3]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

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

^[2],[3]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

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

$ 26

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

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

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

$ 14

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

Remaining Years

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

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

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

143

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

159

^[2]

377

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

Operating Leases Future Minimum Payments Due [Line Items]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

^[2],[3]

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

^[2],[3]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

$ 32

[1]	)Excludes Generation’s contingent operating lease payments associated with contracted generation agreement
[2]	)Includes amounts related to shared use land arrangement
[3]	)Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectivel
[4]	)The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022 , respectivel
[5]	)The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022 , respectivel

Commitments and Contingencies Commitments and Contingencies - Schedule of Future Rental Expense under Operating Leases (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 670

$ 709

$ 777

Operating Leases Future Minimum Payments Due [Line Items]

Long Term Contract For Purchase Of Electric Power Capacity

^[1]

558

578

667

$ 604

493

508

604

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

$ 49

Operating Leases Future Minimum Payments Due [Line Items]

$ 12

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Nontrade Receivables, Current

$ 8

$ 14

$ 13

[1]

)Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $493 million, $508 million and $604 million during 2018, 2017 and 2016, respectively. Excludes contract amortization associated with purchase accounting and contract acquisition

Commitments and Contingencies Commitments and Contingencies - Settlement Agreements (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2018

Dec. 31, 2017

Guarantor Obligations [Line Items]

^[1]

$ 124

$ 94

Nontrade Receivables, Noncurrent

^[2]

Accounts Payable, Other, Current

^[1],[3]

(17)

$ (11)

Spent Nuclear Fuel Storage Reimbursement

Guarantor Obligations [Line Items]

^[4]

1,274

Spent Nuclear Fuel Storage Reimbursement Net Co Owners

^[4],[5]

$ 1,100

Exelon Generation Co L L C [Member] | Department of Energy [Member]

Guarantor Obligations [Line Items]

Spent Nuclear Fuel Storage Reimbursement

$ 53

Spent Nuclear Fuel Storage Reimbursement Net Co Owners

$ 49

[1]	)Recorded in Accounts receivable, other.
[2]	)Recorded in Deferred debits and other assets, oth
[3]	)Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities
[4]	)Includes $53 and $49, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CEN
[5]	)Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Cree

Supplemental Financial Information Supplemental Financial Information - Summary of Taxes other than income (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Supplemental Statement of Operations Information [Line Items]

^[1]

$ 919

$ 898

$ 753

557

545

483

247

230

226

114

1,783

1,731

1,576

Supplemental Statement of Operations Information [Line Items]

^[1]

114

126

122

273

269

246

130

121

117

556

555

506

Supplemental Statement of Operations Information [Line Items]

^[1]

243

240

242

(4)

311

296

293

Supplemental Statement of Operations Information [Line Items]

^[1]

131

125

136

163

154

164

Supplemental Statement of Operations Information [Line Items]

^[1]

143

132

123

254

240

229

Supplemental Statement of Operations Information [Line Items]

^[1]

337

318

101

455

452

Supplemental Statement of Operations Information [Line Items]

^[1]

$ 253

$ 354

Supplemental Statement of Operations Information [Line Items]

^[1]

$ 78

$ 105

Supplemental Statement of Operations Information [Line Items]

^[1]

316

300

312

379

371

377

Supplemental Statement of Operations Information [Line Items]

^[1]

Supplemental Statement of Operations Information [Line Items]

^[1]

$ 5

$ 6

$ 7

[1]

Supplemental Financial Information Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Net realized income on NDT funds - Regulatory agreement units

^[1]

$ 506

$ 488

$ 237

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

^[1]

302

209

126

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

(715)

455

216

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

(483)

521

194

Net unrealized income (losses) on pledged assets

(8)

(10)

(1)

Regulatory offset to NDT fund-related activities

^[2]

171

(724)

(372)

Total decommissioning-related activities

(227)

939

400

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

(106)

Non-service net periodic benefit cost

(47)

(109)

(116)

(3)

(112)

947

297

Net realized income on NDT funds - Regulatory agreement units

^[1]

506

488

237

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

^[1]

302

209

126

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

(715)

455

216

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

(483)

521

194

Net unrealized income (losses) on pledged assets

(8)

(10)

(1)

Regulatory offset to NDT fund-related activities

^[2]

171

(724)

(372)

Total decommissioning-related activities

(227)

939

400

Interest income (expense) related to uncertain income tax positions

(1)

Benefit (penalty) related to uncertain income tax positions

^[3]

(2)

(5)

(178)

948

401

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

(86)

(65)

(1)

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

$ 1

Interest income (expense) related to uncertain income tax positions

(1)

Benefit (penalty) related to uncertain income tax positions

^[3]

$ 44

$ 0

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

(11)

$ (4)

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

Interest income (expense) related to uncertain income tax positions

Benefit (penalty) related to uncertain income tax positions

^[3]

$ 2

$ 7

$ 9

[1]	Includes investment income and realized gains and losses on sales of investments within the NDT funds.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246MTE0OEY2QkJBNTBGNUFBQ0IwMkE4RTI0QzY3MTNDRUEM}
[3]	See Note 14—Income Taxes for additional information on the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.

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

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Mar. 23, 2016

Sep. 30, 2017

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 3,740

$ 3,293

$ 3,477

555

478

407

Amortization of Nuclear Fuel Lease

(109)

(237)

(336)

^[1]

1,115

1,096

1,159

^[2]

489

468

446

5,971

5,427

5,576

1,421

2,430

1,340

540

(441)

Pension and non-pension postretirement benefit costs

583

643

619

159

125

155

Stock-based compensation costs

111

Other decommissioning related-activity

(2)

^[3]

(313)

^[4]

(384)

^[5]

Energy-related options

^[6]

^[7]

(11)

^[8]

Amortization of regulatory asset related to debt costs

(10)

(15)

(18)

(11)

^[9]

^[10]

558

^[11],[12]

Discrete impacts from EIMA and FEJA

^[13]

(52)

^[14]

^[15]

^[16]

Long-term incentive plan

140

109

Baltimore City conduit lease settlement

(28)

Cash Working Capital order

(13)

(19)

(30)

(35)

1,124

721

1,333

Increase (decrease) in capital expenditures not paid

(69)

(128)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

$ (107)

$ 191

(107)

191

Noncash or Part Noncash Divestiture, Amount of Consideration Received

^[12]

Dividends on stock compensation

Assumption of member purchase liability

154

208

6,923

Dissolution of financing trust due to long-term debt retirement

Fair value adjustment of long-term debt due to retirement

(5)

Allowance for Doubtful Accounts Receivable, Write-offs

Fitzpatrick [Member]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

^[17]

(54)

1,748

1,409

1,835

Amortization of Nuclear Fuel Lease

^[1]

1,115

1,096

1,159

^[2]

489

468

446

3,415

3,056

3,519

369

391

339

746

337

435

Pension and non-pension postretirement benefit costs

204

227

218

Other decommissioning related-activity

(2)

^[3]

(313)

^[4]

(384)

^[5]

Energy-related options

^[6]

^[7]

(11)

^[8]

Amortization of regulatory asset related to debt costs

(12)

(11)

^[9]

^[10]

^[11],[12]

^[16]

203

$ 84

$ 138

(23)

298

112

Increase (decrease) in capital expenditures not paid

(199)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

(130)

191

(130)

191

Noncash or Part Noncash Divestiture, Amount of Consideration Received

^[12]

Assumption of member purchase liability

154

208

293

Fair value of pension and OPEB obligation transferred in connection with FitzPatrick

Exelon Generation Co L L C [Member] | noncash member [Member]

Fair value of net assets contributed (distributed) in connection with the PHI merger, net of cash

119

Exelon Generation Co L L C [Member] | Fitzpatrick [Member]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

^[17]

(54)

820

777

708

120

^[2]

940

850

775

332

307

298

(153)

(444)

Pension and non-pension postretirement benefit costs

177

176

166

Amortization of regulatory asset related to debt costs

^[9]

^[10]

^[11],[12]

Discrete impacts from EIMA and FEJA

^[13]

(52)

^[14]

^[15]

^[16]

(14)

(12)

242

164

215

Increase (decrease) in capital expenditures not paid

(61)

(91)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Contribution of Property

^[18]

158

^[19]

274

261

244

^[2]

301

286

270

125

103

104

(2)

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

^[9]

^[10]

^[11],[12]

^[16]

(3)

(4)

(3)

Increase (decrease) in capital expenditures not paid

(12)

(11)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

335

312

299

148

161

124

^[2]

483

473

423

(2)

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

^[9]

^[10]

^[11],[12]

^[16]

Baltimore City conduit lease settlement

(28)

Cash Working Capital order

(13)

(12)

(14)

(21)

Increase (decrease) in capital expenditures not paid

(86)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Dissolution of financing trust due to long-term debt retirement

480

457

260

218

^[2]

740

675

250

236

(32)

(144)

Pension and non-pension postretirement benefit costs

(1)

Amortization of regulatory asset related to debt costs

(17)

(3)

(6)

^[9]

(8)

^[10]

^[16]

(28)

143

Increase (decrease) in capital expenditures not paid

(12)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

325

190

^[2]

515

209

258

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(5)

^[11],[12]

317

(11)

515

Increase (decrease) in capital expenditures not paid

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Fair value of net assets contributed (distributed) in connection with the PHI merger, net of cash

^[12],[20]

127

Fair value of pension obligation transferred in connection with the PHI Merger, net of cash

^[12],[20]

Pepco Holdings LLC [Member] | Successor [Member] | noncash member [Member]

Assumption of member purchase liability

$ 94

^[2]

152

Pension and non-pension postretirement benefit costs

Stock-based compensation costs

Amortization of regulatory asset related to debt costs

^[11],[12]

(3)

Increase (decrease) in capital expenditures not paid

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

218

203

175

167

118

120

^[2]

385

321

295

123

114

118

(104)

216

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

(17)

(12)

^[9]

(6)

^[10]

125

^[11],[12]

^[16]

(6)

(13)

(3)

(6)

175

Increase (decrease) in capital expenditures not paid

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Potomac Electric Power Company [Member] | noncash member [Member]

131

124

110

^[2]

182

167

157

(6)

(49)

115

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

^[9]

(2)

^[10]

^[11],[12]

^[16]

(1)

(7)

(14)

114

Increase (decrease) in capital expenditures not paid

(12)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

^[2]

136

146

165

(12)

(2)

200

Pension and non-pension postretirement benefit costs

Amortization of regulatory asset related to debt costs

^[9]

^[10]

110

^[11],[12]

^[16]

(1)

(6)

155

Increase (decrease) in capital expenditures not paid

(13)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

$ 1

Other Intangible Assets [Member]

Other Intangible Assets [Member] | Exelon Generation Co L L C [Member]

Other Intangible Assets [Member] | Commonwealth Edison Co [Member]

Other Intangible Assets [Member] | PECO Energy Co [Member]

Other Intangible Assets [Member] | Baltimore Gas and Electric Company [Member]

Other Intangible Assets [Member] | Pepco Holdings LLC [Member]

Other Intangible Assets [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Other Intangible Assets [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ 0

Other Intangible Assets [Member] | Potomac Electric Power Company [Member]

$ 0

Other Intangible Assets [Member] | Delmarva Power & Light Company [Member]

Other Intangible Assets [Member] | Atlantic City Electric Company [Member]

Unamortized Energy Contracts [Member]

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[21]

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

^[21]

$ 14

$ 35

[1]	Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[3]	Includes the elimination of decommissioning-related activities 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 for additional information regarding the accounting for nuclear decommissioning.
[4]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVlYzRiNDIxOTkxNDRkN2ViNWYzYTRhOTVmMjFkNDYzfFRleHRTZWxlY3Rpb246ODE3Q0FGRTQ3ODgzNTMyQkFDNzc4ODYwRDFBNDI1OTMM}
[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 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 to results of operations.
[7]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[8]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[9]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[10]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[11]	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.
[12]	See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[13]	Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information.
[14]	Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 4 — Regulatory Matters for additional information.
[15]	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 4 — Regulatory Matters for additional information.
[16]	On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged) employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally accrued throughout 2017 that will now be accrued ratably over the year in 2018.
[17]	Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 5 - Mergers, Acquisitions and Dispositions for additional information.
[18]	See Note 14 — Income Taxes for additional information on the like-kind exchange tax position
[19]	See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.
[20]	Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.
[21]	Included in Operating revenues or Purchased power and fuel in the Registrants’ Consolidated Statements of Operations and Comprehensive Income

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

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 24, 2016

Mar. 23, 2016

Dec. 31, 2015

$ 1,349

$ 898

$ 635

$ 6,502

247

207

253

205

185

1,781

1,190

914

6,712

^[1]

1,656

1,858

^[2]

(319)

(322)

313

298

^[3]

(34)

(31)

279

267

Equity investments without readily determinable fair values

267

297

625

640

^[4]

1,191

978

412

373

334

328

131

100

2,112

1,837

Financing Trusts

^[5]

Bloom Energy

180

206

NET Power

Other Equity Method Investments

Employee benefit trusts and investments

Other available for sale investments

^[6]

244

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

750

416

290

431

153

138

158

123

903

554

448

556

^[1]

965

1,017

^[2]

(104)

(114)

Equity investments without readily determinable fair values

251

283

414

433

^[4]

479

407

226

444

Exelon Generation Co L L C [Member] | Financing Trusts

898

1,022

Exelon Generation Co L L C [Member] | Bloom Energy

^[5]

Exelon Generation Co L L C [Member] | NET Power

180

206

Exelon Generation Co L L C [Member] | Other Equity Method Investments

Exelon Generation Co L L C [Member] | Employee benefit trusts and investments

Exelon Generation Co L L C [Member] | Other available for sale investments

^[6]

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

135

166

330

144

^[1]

223

242

^[2]

(81)

(73)

^[3]

(17)

(14)

Equity investments without readily determinable fair values

^[4]

187

158

105

102

Commonwealth Edison Co [Member] | Financing Trusts

373

327

Commonwealth Edison Co [Member] | Bloom Energy

^[5]

Commonwealth Edison Co [Member] | NET Power

Commonwealth Edison Co [Member] | Other Equity Method Investments

Commonwealth Edison Co [Member] | Employee benefit trusts and investments

Commonwealth Edison Co [Member] | Other available for sale investments

^[6]

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

130

271

295

135

275

298

^[1]

114

162

^[2]

(61)

(56)

^[3]

(5)

Equity investments without readily determinable fair values

^[4]

PECO Energy Co [Member] | Financing Trusts

113

114

PECO Energy Co [Member] | Bloom Energy

^[5]

PECO Energy Co [Member] | NET Power

PECO Energy Co [Member] | Other Equity Method Investments

PECO Energy Co [Member] | Employee benefit trusts and investments

PECO Energy Co [Member] | Other available for sale investments

^[6]

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

^[1]

168

205

^[2]

(20)

(24)

^[3]

(3)

Equity investments without readily determinable fair values

^[4]

Baltimore Gas and Electric Company [Member] | Financing Trusts

155

164

Baltimore Gas and Electric Company [Member] | Bloom Energy

^[5]

Baltimore Gas and Electric Company [Member] | NET Power

Baltimore Gas and Electric Company [Member] | Other Equity Method Investments

Baltimore Gas and Electric Company [Member] | Employee benefit trusts and investments

Baltimore Gas and Electric Company [Member] | Other available for sale investments

^[6]

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

124

186

236

^[1]

186

232

^[2]

(53)

(55)

^[3]

(9)

Equity investments without readily determinable fair values

130

132

^[4]

106

256

261

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

170

236

$ 348

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

$ 319

Pepco Holdings LLC [Member] | Financing Trusts

$ 348

Pepco Holdings LLC [Member] | Bloom Energy

^[5]

Pepco Holdings LLC [Member] | NET Power

Pepco Holdings LLC [Member] | Other Equity Method Investments

Pepco Holdings LLC [Member] | Employee benefit trusts and investments

Pepco Holdings LLC [Member] | Other available for sale investments

^[6]

130

132

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

^[1]

133

^[2]

(21)

^[3]

(5)

Equity investments without readily determinable fair values

105

102

^[4]

Potomac Electric Power Company [Member] | Financing Trusts

126

137

Potomac Electric Power Company [Member] | Bloom Energy

^[5]

Potomac Electric Power Company [Member] | NET Power

Potomac Electric Power Company [Member] | Other Equity Method Investments

Potomac Electric Power Company [Member] | Employee benefit trusts and investments

Potomac Electric Power Company [Member] | Other available for sale investments

^[6]

105

102

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

^[1]

^[2]

(13)

(16)

^[3]

(1)

Equity investments without readily determinable fair values

^[4]

Delmarva Power & Light Company [Member] | Financing Trusts

Delmarva Power & Light Company [Member] | Bloom Energy

^[5]

Delmarva Power & Light Company [Member] | NET Power

Delmarva Power & Light Company [Member] | Other Equity Method Investments

Delmarva Power & Light Company [Member] | Employee benefit trusts and investments

Delmarva Power & Light Company [Member] | Other available for sale investments

^[6]

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

101

$ 133

$ 33

^[1]

^[2]

(19)

(18)

^[3]

(3)

Equity investments without readily determinable fair values

^[4]

Atlantic City Electric Company [Member] | Financing Trusts

Atlantic City Electric Company [Member] | Bloom Energy

^[5]

Atlantic City Electric Company [Member] | NET Power

Atlantic City Electric Company [Member] | Other Equity Method Investments

Atlantic City Electric Company [Member] | Employee benefit trusts and investments

Atlantic City Electric Company [Member] | Other available for sale investments

^[6]

$ 0

[1]	Represents unbilled portion of receivables estimated under Exelon’s unbilled critical accounting policy.
[2]	Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable.
[3]	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.
[4]	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
[5]	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.
[6]	The Registrants’ debt and equity security investments are recorded at fair market value.

Segment Information Segment Information - Narrative (Details)	12 Months Ended
	Dec. 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 Segment Information - Reconciliation to Consolidated Financial Statements (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 0

$ 8,814

$ 9,403

$ 8,076

$ 9,693

$ 8,384

$ 8,768

$ 7,665

$ 8,747

$ 35,985

33,565

31,366

4,353

3,828

3,936

^[1]

32,143

29,619

28,106

1,554

1,560

1,536

2,232

3,782

1,973

120

(126)

753

2,084

3,876

1,196

7,594

7,584

8,553

^[2]

119,666

116,770

119,666

116,770

4,609

4,428

181

161

1,117

1,361

1,076

1,251

1,121

1,310

1,074

1,175

4,805

4,679

432

578

217

398

362

1,375

1,396

^[3]

21,984

21,247

21,984

21,247

$ 3,463

4,428

161

3,643

4,679

(58)

(61)

$ (61)

1,008

$ 1,122

1,153

273

5,069

$ 5,278

$ 4,579

$ 5,512

4,657

$ 4,750

$ 4,216

$ 4,878

20,437

18,500

17,757

1,268

1,115

1,439

365

1,455

857

(108)

(1,376)

282

443

2,798

550

2,242

2,259

3,078

Operating Segments [Member]

^[4]

47,556

48,457

47,556

48,457

^[1]

16,155

14,227

13,970

^[1]

2,710

2,575

2,146

^[1]

303

592

207

^[1]

15,344

14,840

13,869

^[1]

1,470

1,333

1,166

^[1]

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

^[1]

35,985

33,567

31,365

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

^[5]

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

^[5]

^[5]

Intersegment Eliminations [Member]

(1)

^[1]

(1,256)

(1,105)

(1,430)

^[1]

(8)

^[1]

(5)

(1)

(4)

^[1]

(45)

(29)

(31)

^[1]

(20)

(10)

(13)

^[1]

(1,960)

(1,880)

(1,686)

^[1]

(3,294)

(3,025)

(3,164)

^[6]

^[1]

(3,341)

(3,026)

(3,164)

(1)

(2)

(5)

(1)

(2)

(5)

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

(9,800)

(10,552)

(9,800)

(10,552)

^[7]

(17)

(14)

^[7]

^[7]

(420)

(3)

^[7]

(437)

(17)

(437)

(19)

(1)

(435)

(17)

(1)

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

(408)

(404)

(2)

(5,421)

(4,987)

(5,421)

(4,987)

^[7]

(13)

^[7]

^[7]

^[7]

(13)

(13)

(13)

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

^[7]

(4)

^[7]

^[7]

^[7]

(4)

(4)

(4)

(3)

(2)

(118)

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

^[1],[8]

17,411

15,332

15,400

^[1],[8]

2,718

2,575

2,146

^[1],[8]

308

593

211

^[1],[8]

^[1],[8]

^[1],[8]

^[1],[8]

20,437

18,500

17,757

^[8]

1,797

1,457

1,879

^[1],[8]

19,510

18,001

16,878

^[8]

432

440

364

^[8]

365

1,455

857

^[8]

(108)

(1,376)

282

^[8]

443

2,798

550

^[8]

2,242

2,259

3,078

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

^[8]

47,556

48,457

47,556

48,457

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

^[6],[8]

1,269

1,110

1,428

^[1]

^[1]

^[1]

^[1]

5,882

5,536

5,254

^[1]

^[1]

^[1]

5,882

5,536

5,254

940

850

775

^[1]

4,741

4,214

4,056

347

361

461

832

984

679

168

417

301

664

567

378

2,126

2,250

2,734

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

31,213

29,726

31,213

29,726

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

^[6]

^[1]

^[1]

^[1]

^[1]

2,470

2,375

2,531

^[1]

568

495

463

^[1]

^[1]

3,038

2,870

2,994

301

286

270

^[1]

2,452

2,215

2,292

129

126

123

466

538

587

104

149

460

434

438

849

732

686

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

10,642

10,170

10,642

10,170

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

^[6]

^[1]

^[1]

^[1]

^[1]

2,428

2,489

2,609

^[1]

741

687

624

^[1]

^[1]

3,169

3,176

3,233

483

473

423

^[1]

2,696

2,562

2,683

106

105

103

387

525

468

218

174

313

307

294

959

882

934

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

9,716

9,104

9,716

9,104

^[6]

3,643

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

1,153

^[1],[9]

^[1],[9]

^[1],[9]

^[1],[7],[9]

4,609

4,469

^[1],[7],[9]

181

161

^[1],[7],[9]

^[1],[7],[9]

4,805

4,679

^[9]

740

675

^[1],[9]

4,156

3,911

^[9]

261

245

^[9]

432

578

^[9]

217

^[9]

398

362

^[9]

1,375

1,396

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

21,984

21,247

21,984

21,247

^[1],[9]

^[1],[9]

^[1],[9]

^[1],[7],[9]

3,506

^[1],[7],[9]

^[1],[7],[9]

^[1],[7],[9]

3,643

^[9]

515

^[1],[9]

3,549

^[9]

195

^[9]

(58)

^[9]

^[9]

(61)

^[9]

1,008

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

^[9]

21,984

21,247

21,984

21,247

^[7]

1,096

^[7]

^[7]

^[7]

1,153

152

1,048

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

273

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

^[6],[9]

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

^[6],[9]

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

^[7]

2,239

2,158

^[7]

^[7]

^[7]

2,239

2,158

385

321

1,919

1,760

128

121

223

310

105

210

205

656

628

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

8,299

7,832

8,299

7,832

^[7]

1,675

^[7]

^[7]

^[7]

1,675

224

1,577

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

489

^[7]

511

^[7]

^[7]

^[7]

511

443

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

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

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

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

^[7]

1,151

1,139

^[7]

181

161

^[7]

^[7]

1,332

1,300

182

167

1,143

1,071

142

192

120

121

364

428

Delmarva Power & Light Company [Member] | Operating Segments [Member] | Successor [Member]

4,588

4,357

4,588

4,357

^[7]

850

^[7]

^[7]

^[7]

942

120

952

(30)

(35)

Delmarva Power & Light Company [Member] | Operating Segments [Member] | Predecessor [Member]

277

^[7]

279

^[7]

^[7]

^[7]

335

284

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

Delmarva Power & Light Company [Member] | Intersegment Eliminations [Member] | Successor [Member]

Delmarva Power & Light Company [Member] | Intersegment Eliminations [Member] | Predecessor [Member]

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

^[7]

1,236

1,186

^[7]

^[7]

^[7]

1,236

1,186

136

146

1,087

1,029

103

335

312

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

3,699

3,445

3,699

3,445

^[7]

989

^[7]

^[7]

^[7]

989

128

1,000

(51)

(5)

(47)

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

218

^[7]

268

^[7]

^[7]

^[7]

268

251

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

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

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

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

^[1],[10]

^[1],[10]

^[1],[10]

^[1],[10]

^[1],[10]

^[1],[10]

1,948

1,831

1,648

^[1],[10]

1,948

1,831

1,648

^[10]

^[1],[10]

1,929

1,742

1,812

^[10]

279

283

290

^[10]

(249)

(296)

(555)

^[10]

(55)

294

(156)

^[10]

(193)

(590)

(398)

^[10]

113

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

^[10]

8,355

8,618

8,355

8,618

^[7],[11]

^[7],[11]

^[7],[11]

435

^[7],[11]

435

^[11]

^[11]

442

^[11]

^[11]

388

377

^[11]

(10)

^[11]

(22)

(91)

^[11]

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

^[11]

$ 10,819

$ 10,600

10,819

10,600

^[7],[11]

^[7],[11]

^[7],[11]

^[7],[11]

^[11]

^[11]

^[11]

^[11]

(84)

^[11]

(23)

^[11]

(34)

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

^[11]

^[7],[11]

^[7],[11]

^[7],[11]

^[7],[11]

^[11]

^[11]

^[11]

^[11]

^[11]

(16)

^[11]

(44)

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

^[11]

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

^[6],[10]

1,942

1,824

1,647

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

^[11]

435

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

^[11]

$ 47

Generation Mid Atlantic [Member]

^[11]

$ 0

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

5,487

5,540

6,179

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

^[12]

5,474

5,515

6,212

Generation Midwest [Member]

(33)

Generation Midwest [Member] | Operating Segments [Member]

4,706

4,181

4,412

Generation Midwest [Member] | Intersegment Eliminations [Member]

^[12]

4,717

4,206

4,402

Segment Elimination [Member] | Intersegment Eliminations [Member]

(11)

(25)

^[6]

$ (3,289)

$ (3,020)

$ (3,159)

[1]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.
[2]	Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities for additional information.
[3]	PHI’s consolidated total assets include $33 million and $41 million at December 31, 2018 and 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 $69 million and $102 million at December 31, 2018 and 2017, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities for additional information.
[4]	Generation’s consolidated assets include $9,634 million and $9,556 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,480 million and $3,516 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities for additional information.
[5]	Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016, respectively.
[6]	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 authoritative guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
[7]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.
[8]	See Note 25 — Related Party Transactions for additional information on intersegment revenues.
[9]	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2018.
[10]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[11]	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.
[12]	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants

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

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 8,814

$ 9,403

$ 8,076

$ 9,693

$ 8,384

$ 8,768

$ 7,665

$ 8,747

$ 35,985

$ 33,565

$ 31,366

Generation Mid Atlantic [Member]

Generation Midwest [Member]

5,487

5,540

6,179

Generation New England [Member]

4,706

4,181

4,412

Generation New York [Member]

2,841

2,002

1,769

Generation ERCOT [Member]

1,687

1,550

1,166

Generation Other Regions [Member]

1,133

962

837

Generation Reportable Segments Total [Member]

1,494

1,049

907

Generation Natural Gas [Member]

17,348

15,284

15,270

Generation All Other Segments [Member]

2,780

2,628

2,281

^[1]

309

588

206

Generation Total Consolidated Group [Member]

(262)

(131)

(500)

Operating Segments [Member]

20,437

18,500

17,757

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

^[2]

35,985

33,567

31,365

Operating Segments [Member] | Generation Midwest [Member]

^[3]

5,474

5,515

6,212

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

^[3]

4,717

4,206

4,402

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

^[3]

2,845

2,010

1,778

Operating Segments [Member] | Generation ERCOT [Member]

^[3]

1,687

1,567

1,208

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

^[3]

1,132

958

831

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

^[3]

1,556

1,076

969

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

^[3]

17,411

15,332

15,400

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

^[3]

2,718

2,575

2,146

Amortization of intangible assets related to commodity contracts

(38)

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

(319)

(175)

(41)

^[3]

20,437

18,500

17,757

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

(1)

Intersegment Eliminations [Member]

^[1],[3]

308

593

211

^[2]

(3,294)

(3,025)

(3,164)

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

^[4]

Intersegment Eliminations [Member] | Generation Midwest [Member]

(33)

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

(11)

(25)

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

(4)

(8)

(9)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

(17)

(42)

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

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

(62)

(27)

(62)

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

(63)

(48)

(130)

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

135

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

^[1]

(5)

Contracts with Customers [Member] | Operating Segments [Member] | Generation Mid Atlantic [Member]

Contracts with Customers [Member] | Operating Segments [Member] | Generation Midwest [Member]

^[3]

5,241

5,523

6,182

Contracts with Customers [Member] | Operating Segments [Member] | Generation New England [Member]

^[3]

4,527

3,923

4,007

Contracts with Customers [Member] | Operating Segments [Member] | Generation New York [Member]

^[3]

2,660

2,064

1,953

Contracts with Customers [Member] | Operating Segments [Member] | Generation ERCOT [Member]

^[3]

1,723

1,605

1,198

Contracts with Customers [Member] | Operating Segments [Member] | Generation Other Regions [Member]

^[3]

572

641

810

Contracts with Customers [Member] | Operating Segments [Member] | Generation Reportable Segments Total [Member]

^[3]

870

594

670

Contracts with Customers [Member] | Operating Segments [Member] | Generation Natural Gas [Member]

^[3]

15,593

14,350

14,820

Contracts with Customers [Member] | Operating Segments [Member] | Generation Total Consolidated Group [Member]

^[3]

1,524

1,658

1,953

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

^[3]

17,627

16,752

17,529

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

^[1],[3]

510

744

756

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

^[3],[5]

233

(8)

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

^[3],[5]

190

283

395

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

^[3],[5]

185

(54)

(175)

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

^[3],[5]

(36)

(38)

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

^[3],[5]

560

317

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

^[3],[5]

686

482

299

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

^[3],[5]

1,818

982

580

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

^[3],[5]

1,194

917

193

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

^[3],[5]

2,810

1,748

228

Generation Mid Atlantic [Member]

^[1],[3],[5]

$ (202)

$ (151)

$ (545)

[1]	Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million and $52 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017 and 2016, respectively, unrealized mark-to-market losses of $262 million, $131 million, and $500 million in 2018, 2017, and 2016, respectively, and elimination of intersegment revenues.
[2]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 23 — Supplemental Financial Information for additional information on total utility taxes.
[3]	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants
[4]	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 authoritative guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
[5]	Includes revenues from derivatives and leases.

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

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Generation Midwest [Member]

$ 3,073

$ 3,214

$ 3,317

Generation New England [Member]

3,135

2,820

2,971

Generation New York [Member]

354

514

438

Generation ERCOT [Member]

1,122

1,008

752

Generation Other Regions [Member]

258

332

281

Generation Reportable Segments Total [Member]

375

305

336

Generation All Other Segments [Member]

8,317

8,193

8,095

^[1]

427

617

832

Generation Total Consolidated Group [Member]

(262)

(131)

(500)

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

8,744

8,810

8,927

Operating Segments [Member] | Generation Midwest [Member]

^[2]

3,022

3,105

3,282

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

^[2]

3,112

2,810

2,969

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

^[2]

368

538

467

Operating Segments [Member] | Generation ERCOT [Member]

^[2]

1,112

1,007

771

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

^[2]

501

575

412

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

^[2]

515

476

483

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

^[2]

8,630

8,511

8,384

Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel

^[1],[2]

114

299

543

(319)

(175)

(41)

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

(57)

(12)

(60)

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

^[2]

8,744

8,810

8,927

Intersegment Revenue Net Of Purchase Power And Fuel

109

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

(14)

(24)

(29)

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

Intersegment Revenue Net Of Purchase Power And Fuel

(19)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

Intersegment Revenue Net Of Purchase Power And Fuel

(243)

(131)

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

Intersegment Revenue Net Of Purchase Power And Fuel

(140)

(171)

(147)

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

Intersegment Revenue Net Of Purchase Power And Fuel

(313)

(318)

(289)

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

Intersegment Revenue Net Of Purchase Power And Fuel

^[1]

313

318

289

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

Intersegment Revenue Net Of Purchase Power And Fuel

$ 0

[1]

[2]

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

Related Party Transactions - Related Party Transactions included in Consolidated Income Statement (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ 0

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

$ 25

(28)

(32)

(24)

Equity in earnings (losses) of unconsolidated affiliates

(28)

(32)

(24)

1,332

1,236

1,166

Exelon Generation Co LLC Affiliate [Member]

(1)

PECO Energy Co Affiliate [Member]

^[1]

(2)

Baltimore Gas And Electric Company Affiliate [Member]

^[1]

Atlantic City Electric Co Affiliate [Member]

^[1]

^[1]

PECO Trust III Affiliate [Member]

PECO Trust IV Affiliate [Member]

BGE Capital Trust II Affiliate [Member]

Qualifying Facilities And Domestic Power Projects Affiliate [Member]

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(29)

(33)

(25)

Other Affiliate [Member]

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

1,268

1,115

1,439

661

697

663

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(30)

(33)

(25)

Equity in earnings (losses) of unconsolidated affiliates

(30)

(33)

(25)

1,001

659

922

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

155

102

142

^[2]

523

121

(6)

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

^[3]

^[4]

128

138

290

^[3]

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

^[5]

260

388

608

Exelon Generation Co L L C [Member] | Potomac Electric Power Co Affiliate [Member]

^[3]

^[6]

206

255

295

Exelon Generation Co L L C [Member] | Delmarva Power & Light Co Affiliate [Member]

Exelon Generation Co L L C [Member] | Atlantic City Electric Co Affiliate [Member]

^[7]

120

179

154

Exelon Generation Co L L C [Member] | PHI Service Co Affiliate [Member]

^[8]

Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]

^[9]

1,001

659

922

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

155

102

142

^[10]

652

689

650

Exelon Generation Co L L C [Member] | Potomac Capital Investment Affiliate [Member]

^[10]

Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member]

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(30)

(33)

(25)

Exelon Generation Co L L C [Member] | Other Affiliate [Member]

(3)

(4)

(2)

529

108

267

270

227

Equity in earnings (losses) of unconsolidated affiliates

459

422

369

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

500

651

315

Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member]

^[11]

529

108

Commonwealth Edison Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]

Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]

459

422

369

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

500

651

315

^[12]

265

270

225

Commonwealth Edison Co [Member] | ComEd Financing III Affiliate [Member]

^[12]

135

118

112

126

135

287

156

149

146

Equity in earnings (losses) of unconsolidated affiliates

306

288

277

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[13]

^[14]

126

135

287

PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]

(1)

PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]

PECO Energy Co [Member] | Atlantic City Electric Co Affiliate [Member]

PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]

306

288

277

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

^[15]

146

142

PECO Energy Co [Member] | PECO Trust III Affiliate [Member]

^[15]

PECO Energy Co [Member] | PECO Trust IV Affiliate [Member]

257

384

604

162

153

132

Equity in earnings (losses) of unconsolidated affiliates

209

198

179

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

109

184

^[16]

^[17]

257

384

604

Baltimore Gas and Electric Company [Member] | Commonwealth Edison Co Affiliate [Member]

Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]

Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]

209

198

179

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

109

184

^[18]

157

152

130

Baltimore Gas and Electric Company [Member] | BGE Capital Trust II Affiliate [Member]

^[18]

355

463

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

152

150

Equity in earnings (losses) of unconsolidated affiliates

326

311

385

758

$ 45

486

152

150

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

181

Equity in earnings (losses) of unconsolidated affiliates

273

Pepco Holdings LLC [Member] | Exelon Generation Co LLC Affiliate [Member] | Successor [Member]

1,251

Pepco Holdings LLC [Member] | PHI Service Co Affiliate [Member] | Successor [Member]

486

355

463

Pepco Holdings LLC [Member] | Exelon Corporation Affiliate [Member] | Successor [Member]

^[19]

1,251

326

311

Pepco Holdings LLC [Member] | Exelon Business Services Co Affiliate [Member] | Successor [Member]

273

385

758

^[19]

147

145

Pepco Holdings LLC [Member] | Other Affiliate [Member] | Successor [Member]

^[19]

102

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

$ 0

206

255

295

226

Equity in earnings (losses) of unconsolidated affiliates

169

133

136

Potomac Electric Power Company [Member] | Corporate, Non-Segment [Member]

166

161

187

Potomac Electric Power Company [Member] | Exelon Generation Co LLC Affiliate [Member]

248

302

Potomac Electric Power Company [Member] | PHI Service Co Affiliate [Member]

^[20]

^[21]

206

255

295

^[22],[23]

137

^[22],[23]

219

263

Potomac Electric Power Company [Member] | Exelon Corporation Affiliate [Member]

^[23]

169

133

136

Potomac Electric Power Company [Member] | Exelon Business Services Co Affiliate [Member]

166

161

187

^[23]

Potomac Electric Power Company [Member] | Pepco Energy Services Affiliate [Member]

^[23]

^[24]

120

179

154

162

Equity in earnings (losses) of unconsolidated affiliates

112

Delmarva Power & Light Company [Member] | Corporate, Non-Segment [Member]

150

152

Delmarva Power & Light Company [Member] | Exelon Generation Co LLC Affiliate [Member]

174

202

^[25]

120

179

154

Delmarva Power & Light Company [Member] | Commonwealth Edison Co Affiliate [Member]

Delmarva Power & Light Company [Member] | Atlantic City Electric Co Affiliate [Member]

Delmarva Power & Light Company [Member] | PHI Service Co Affiliate [Member]

^[26],[27]

111

^[26],[27]

165

194

Delmarva Power & Light Company [Member] | Exelon Corporation Affiliate [Member]

^[26]

112

Delmarva Power & Light Company [Member] | Exelon Business Services Co Affiliate [Member]

150

152

^[26]

Delmarva Power & Light Company [Member] | Pepco Energy Services Affiliate [Member]

^[26]

Delmarva Power & Light Company [Member] | Other Affiliate [Member]

^[28]

142

Equity in earnings (losses) of unconsolidated affiliates

Atlantic City Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

139

^[29]

Atlantic City Electric Company [Member] | PHI Service Co Affiliate [Member]

^[30],[31]

^[30],[31]

135

155

Atlantic City Electric Company [Member] | Exelon Corporation Affiliate [Member]

^[30]

Atlantic City Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

139

^[30]

Atlantic City Electric Company [Member] | Other Affiliate [Member]

^[30]

$ 2

$ 3

[1]	The intersegment profit associated with the 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 authoritative guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations. See Note 4—Regulatory Matters for additional information.
[2]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.
[3]	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
[4]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.
[5]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
[6]	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
[7]	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.
[8]	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
[9]	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.
[10]	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[11]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation.
[12]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[13]	PECO provides energy to Generation for Generation’s own use.
[14]	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively.
[15]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[16]	BGE provides energy to Generation for Generation’s own use.
[17]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
[18]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[19]	PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[20]	Pepco provides energy to Generation for Generation’s own use.
[21]	Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs.
[22]	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.
[23]	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[24]	PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.
[25]	DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs.
[26]	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[27]	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.
[28]	PES performed underground transmission construction services, including services that are treated as capital costs, for DPL.
[29]	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process.
[30]	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[31]	Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in Operating and maintenance from affiliates in 2018.

Related Party Transactions - Related Party Transactions included in Consolidated Balance Sheet (Details) - USD ($)

Dec. 31, 2018

Dec. 31, 2017

$ 5,000,000

390,000,000

389,000,000

4,000,000

PECO Trust III Affiliate [Member]

206,000,000

205,000,000

1,000,000

PECO Trust IV Affiliate [Member]

81,000,000

103,000,000

173,000,000

140,000,000

100,000,000

54,000,000

Long-term debt due to affiliates

139,000,000

123,000,000

898,000,000

910,000,000

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

2,606,000,000

3,065,000,000

^[1]

30,000,000

26,000,000

^[1]

4,000,000

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

^[2]

389,000,000

537,000,000

^[3]

69,000,000

28,000,000

Due to Related Parties, Current

19,000,000

12,000,000

^[3]

14,000,000

Exelon Generation Co L L C [Member] | Delmarva Power & Light Co Affiliate [Member]

^[2]

2,217,000,000

2,528,000,000

Exelon Generation Co L L C [Member] | Potomac Electric Power Co Affiliate [Member]

^[4]

7,000,000

12,000,000

Exelon Generation Co L L C [Member] | Atlantic City Electric Co Affiliate [Member]

^[5]

28,000,000

36,000,000

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

^[6]

5,000,000

6,000,000

Exelon Generation Co L L C [Member] | PHI Service Co Affiliate [Member]

^[7]

24,000,000

Exelon Generation Co L L C [Member] | Potomac Capital Investment Affiliate [Member]

^[8]

1,000,000

Exelon Generation Co L L C [Member] | Other Affiliate [Member]

54,000,000

10,000,000

7,000,000

Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]

8,000,000

12,000,000

100,000,000

Long-term debt due to affiliates

^[9]

17,000,000

21,000,000

^[10]

898,000,000

910,000,000

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

^[8]

95,000,000

74,000,000

20,000,000

13,000,000

2,217,000,000

2,528,000,000

119,000,000

74,000,000

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

205,000,000

19,000,000

12,000,000

^[11]

2,217,000,000

2,528,000,000

Commonwealth Edison Co [Member] | ComEd Financing III Affiliate [Member]

^[12]

55,000,000

28,000,000

4,000,000

Commonwealth Edison Co [Member] | Voluntary Employee Beneficiary Association Trust Affiliate [Member]

205,000,000

Prepaid voluntary employee beneficiary association trust

^[13]

5,000,000

2,000,000

Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]

1,000,000

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

4,000,000

3,000,000

^[14]

56,000,000

39,000,000

389,000,000

537,000,000

59,000,000

53,000,000

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[15]

184,000,000

^[16]

389,000,000

537,000,000

PECO Energy Co [Member] | PECO Trust III Affiliate [Member]

^[17]

30,000,000

22,000,000

1,000,000

PECO Energy Co [Member] | PECO Trust IV Affiliate [Member]

81,000,000

PECO Energy Co [Member] | Voluntary Employee Beneficiary Association Trust Affiliate [Member]

103,000,000

Prepaid voluntary employee beneficiary association trust

^[18]

1,000,000

PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

2,000,000

1,000,000

^[19]

26,000,000

29,000,000

1,000,000

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

65,000,000

52,000,000

Baltimore Gas and Electric Company [Member] | Other Affiliate [Member]

^[20]

24,000,000

1,000,000

Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]

1,000,000

2,000,000

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

2,000,000

1,000,000

^[21]

38,000,000

25,000,000

Pepco Holdings LLC [Member] | Exelon Generation Co LLC Affiliate [Member]

94,000,000

90,000,000

Pepco Holdings LLC [Member] | Baltimore Gas And Electric Company Affiliate [Member]

40,000,000

54,000,000

Pepco Holdings LLC [Member] | Other Affiliate [Member]

1,000,000

Pepco Holdings LLC [Member] | Exelon Corporation Affiliate [Member]

7,000,000

5,000,000

Pepco Holdings LLC [Member] | Exelon Business Services Co Affiliate [Member]

6,000,000

^[22]

41,000,000

24,000,000

1,000,000

Potomac Electric Power Company [Member] | Exelon Generation Co LLC Affiliate [Member]

62,000,000

74,000,000

Potomac Electric Power Company [Member] | Delmarva Power & Light Co Affiliate [Member]

^[23]

28,000,000

36,000,000

Potomac Electric Power Company [Member] | PHI Service Co Affiliate [Member]

1,000,000

Potomac Electric Power Company [Member] | Exelon Corporation Affiliate [Member]

^[24]

14,000,000

27,000,000

Potomac Electric Power Company [Member] | Exelon Business Services Co Affiliate [Member]

1,000,000

^[24]

19,000,000

11,000,000

Delmarva Power & Light Company [Member] | Exelon Generation Co LLC Affiliate [Member]

33,000,000

46,000,000

Delmarva Power & Light Company [Member] | Potomac Electric Power Co Affiliate [Member]

^[25]

7,000,000

12,000,000

Delmarva Power & Light Company [Member] | Atlantic City Electric Co Affiliate [Member]

1,000,000

Delmarva Power & Light Company [Member] | PHI Service Co Affiliate [Member]

1,000,000

Delmarva Power & Light Company [Member] | Exelon Corporation Affiliate [Member]

^[26]

12,000,000

27,000,000

Delmarva Power & Light Company [Member] | Exelon Business Services Co Affiliate [Member]

1,000,000

^[26]

11,000,000

7,000,000

1,000,000

Atlantic City Electric Company [Member] | Delmarva Power & Light Company [Member]

28,000,000

29,000,000

Atlantic City Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

1,000,000

Atlantic City Electric Company [Member] | PHI Service Co Affiliate [Member]

^[27]

5,000,000

6,000,000

Atlantic City Electric Company [Member] | Other Affiliate [Member]

^[28]

13,000,000

18,000,000

Atlantic City Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

2,000,000

^[28]

8,000,000

5,000,000

Parent Company [Member]

44,000,000

33,000,000

216,000,000

217,000,000

Parent Company [Member] | Exelon Generation Co L L C [Member]

360,000,000

17,000,000

21,000,000

Parent Company [Member] | PHI Service Co Affiliate [Member]

^[29]

100,000,000

Parent Company [Member] | Exelon Business Services Co Affiliate [Member]

6,000,000

^[30]

13,000,000

1,000,000

^[30]

$ 116,000,000

$ 217,000,000

[1]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.
[2]	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations for additional information.
[3]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.
[4]	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.
[5]	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
[6]	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
[7]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
[8]	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[9]	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.
[10]	In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.
[11]	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.
[12]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from Generation.
[13]	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
[14]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[15]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[16]	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.
[17]	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively.
[18]	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.
[19]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[20]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
[21]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[22]	PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[23]	Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs.
[24]	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[25]	DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs.
[26]	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[27]	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process.
[28]	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[29]	In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.
[30]	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.

Quarterly Data (Unaudited) - Quarterly Operating Results (Details) - USD ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
Operating Revenues	$ 8,814	$ 9,403	$ 8,076	$ 9,693	$ 8,384	$ 8,768	$ 7,665	$ 8,747	$ 35,985	$ 33,565	$ 31,366
Operating income (loss)	708	1,146	942	1,101	1,288	1,499	300	1,308	3,898	4,395	3,212
Net income attributable to common shareholders	152	733	539	585	1,880	823	95	990	2,010	3,786	1,121
Net income (loss)									2,084	3,876	1,196
Exelon Generation Co L L C [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	5,069	5,278	4,579	5,512	4,657	4,750	4,216	4,878	20,437	18,500	17,757
Operating income (loss)	35	311	282	347	504	497	(427)	373	975	947	820
Net income (loss) attributable to membership interest	(178)	234	178	136	2,224	304	(235)	418	370	2,710	483
Net income (loss)									443	2,798	550
Commonwealth Edison Co [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	1,373	1,598	1,398	1,512	1,309	1,571	1,357	1,298	5,882	5,536	5,254
Operating income (loss)	242	323	288	292	286	404	319	314	1,146	1,323	1,205
Net income (loss)	141	193	164	165	120	189	118	141	664	567	378
PECO Energy Co [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	765	757	653	866	729	715	630	796	3,038	2,870	2,994
Operating income (loss)	165	154	127	142	157	169	137	192	587	655	702
Net income (loss)	124	126	96	113	107	112	88	127	460	434	438
Baltimore Gas and Electric Company [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	799	731	662	977	813	738	674	951	3,169	3,176	3,233
Operating income (loss)	109	103	85	177	163	124	98	228	474	614	550
Net income attributable to common shareholders									313	307	286
Net income (loss)	71	63	51	128	76	62	45	125	313	307	294
Pepco Holdings LLC [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	1,117	1,361	1,076	1,251	1,121	1,310	1,074	1,175	4,805	4,679
Operating income (loss)	126	245	153	126	159	285	148	180	650	769
Net income (loss) attributable to membership interest	62	187	84	65	4	153	66	140	398	362
Net income (loss)									398	362
Potomac Electric Power Company [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	531	628	523	557	510	604	514	530	2,239	2,158	2,186
Operating income (loss)	65	112	85	56	87	149	84	79	320	399	174
Net income (loss)	36	89	54	31	17	87	43	58	210	205	42
Delmarva Power & Light Company [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	331	328	289	384	330	327	282	362	1,332	1,300	1,277
Operating income (loss)	48	51	42	49	52	59	41	78	190	229	50
Net income (loss)	30	33	26	31	14	31	19	57	120	121	(9)
Atlantic City Electric Company [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	254	406	265	310	271	370	270	275	1,236	1,186	1,257
Operating income (loss)	14	84	25	23	28	79	25	25	149	157	7
Net income (loss)	$ (1)	$ 61	$ 8	$ 7	$ 0	$ 41	$ 8	$ 28	$ 75	$ 77	$ (42)

Quarterly Data (Unaudited) - Quarterly Per Share Information (Details) - $ / shares	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Quarterly Financial Data [Abstract]
Net Income per Basic Share	$ 0.16	$ 0.76	$ 0.56	$ 0.61	$ 1.95	$ 0.86	$ 0.10	$ 1.07	$ 2.08	$ 4.00	$ 1.21
Net Income per Diluted Share	$ 0.16	$ 0.76	$ 0.56	$ 0.60	$ 1.94	$ 0.85	$ 0.10	$ 1.06	$ 2.07	$ 3.99	$ 1.21

Subsequent Events Subsequent Events - Narrative (Details) - Exelon Generation Co L L C [Member] - Subsequent Event [Member] $ in Millions	Dec. 31, 2018 USD ($)
Subsequent Event [Line Items]
Net long-lived assets	$ 750
Non-recourse debt	510
Antelope Valley [Member]
Subsequent Event [Line Items]
Net long-lived assets	1,990
Antelope Valley [Member] \| ExGenRenewablesIVNov2024 [Member]
Subsequent Event [Line Items]
Non-recourse debt	$ 830

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Operations and Other Comprehensive Income (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2018

Sep. 30, 2018

Jun. 30, 2018

Mar. 31, 2018

Dec. 31, 2017

Sep. 30, 2017

Jun. 30, 2017

Mar. 31, 2017

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Operating Expenses [Abstract]

Total operating expenses

$ 32,143

$ 29,619

$ 28,106

Operating income (loss)

$ 708

$ 1,146

$ 942

$ 1,101

$ 1,288

$ 1,499

$ 300

$ 1,308

3,898

4,395

3,212

Other income and (deductions)

Equity in earnings (losses) of unconsolidated affiliates

(1,529)

(1,524)

(1,495)

(28)

(32)

(24)

Total other income and (deductions)

(112)

947

297

(1,666)

(613)

(1,239)

$ 26

120

(126)

753

Pension and non-pension postretirement benefit plans:

2,084

3,876

1,196

Prior service benefit reclassified to periodic benefit cost

(66)

(56)

(48)

Actuarial loss reclassified to periodic cost, net of tax

247

197

184

Unrealized gain on cash flow hedges

Unrealized gain on marketable securities

Unrealized (loss) gain on foreign currency translation

(10)

171

(36)

Comprehensive Income

2,051

3,959

1,085

Operating Expenses [Abstract]

(5)

221

^[1]

Total operating expenses

276

Operating income (loss)

(8)

(39)

(276)

Other income and (deductions)

Equity in earnings (losses) of unconsolidated affiliates

(312)

(315)

(312)

2,188

4,414

1,508

Total other income and (deductions)

1,921

4,140

1,242

Income before income taxes

1,913

4,101

966

(97)

315

(155)

Pension and non-pension postretirement benefit plans:

2,010

3,786

1,121

Prior service benefit reclassified to periodic benefit cost

(66)

(56)

(48)

Actuarial loss reclassified to periodic cost, net of tax

247

197

184

Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), after Tax

(143)

(181)

Unrealized gain on cash flow hedges

Unrealized gain (loss) on equity investments

(4)

Unrealized gain on marketable securities

Unrealized (loss) gain on foreign currency translation

(10)

173

(36)

Comprehensive Income

$ 2,051

$ 3,959

$ 1,085

[1]	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Net cash flows provided by (used in) operating activities	$ 8,644	$ 7,480	$ 8,461
Cash flows from investing activities
Other investing activities	58	(43)	(153)
Net cash flows provided by (used in) investing activities	(7,834)	(7,971)	(15,450)
Cash flows from financing activities
Issuance of long-term debt	3,115	3,470	4,716
Proceeds from short-term borrowings with maturities greater than 90 days	126	621	240
Retirement of long-term debt	(1,786)	(2,490)	(1,936)
Common stock issued from treasury stock	0	1,150	0
Dividends paid on common stock	(1,332)	(1,236)	(1,166)
Proceeds from employee stock plans	105	150	55
Other financing activities	(108)	(83)	(85)
Net cash flows provided by (used in) financing activities	(219)	767	1,191
Increase (Decrease) in cash, cash equivalents and restricted cash	591	276	(5,798)
Cash, cash equivalents and restricted cash at beginning of period	898	635	6,502
Cash, cash equivalents and restricted cash at end of period	1,349	898	635
Exelon Corporate [Member]
Net cash flows provided by (used in) operating activities	2,581	1,921	1,029
Cash flows from investing activities
Changes in Exelon intercompany money pool	1	(129)	1,390
Investment in affiliates	(1,236)	(1,717)	(1,757)
Acquisition of business	0	0	6,962
Other investing activities	0	(5)	5
Net cash flows provided by (used in) investing activities	(1,235)	(1,851)	(7,324)
Cash flows from financing activities
Issuance of long-term debt	0	0	1,800
Proceeds from short-term borrowings with maturities greater than 90 days	0	500	0
Retirement of long-term debt	0	(569)	(46)
Common stock issued from treasury stock	0	1,150	0
Dividends paid on common stock	(1,332)	(1,236)	(1,166)
Proceeds from employee stock plans	105	150	55
Other financing activities	(4)	(9)	(20)
Net cash flows provided by (used in) financing activities	(1,231)	(14)	623
Increase (Decrease) in cash, cash equivalents and restricted cash	115	56	(5,672)
Cash, cash equivalents and restricted cash at beginning of period	74	18	5,690
Cash, cash equivalents and restricted cash at end of period	$ 189	$ 74	$ 18

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Feb. 17, 2012

$ 1,349

$ 898

$ 635

$ 6,502

Other accounts receivable

1,256

1,132

1,222

1,267

1,238

1,260

13,360

11,896

76,707

74,202

8,237

8,021

1,575

1,330

^[1]

119,666

116,770

714

929

1,349

2,088

3,800

3,532

2,112

1,837

644

523

1,035

1,069

11,404

10,798

34,075

32,176

9,559

9,865

3,988

3,736

1,928

2,093

2,130

2,097

40,727

41,220

^[1]

86,596

84,583

$ 1,000

19,116

18,964

Treasury stock, at cost

(123)

14,766

14,081

(2,995)

(3,026)

30,764

29,896

119,666

116,770

189

$ 18

$ 5,690

Other accounts receivable

431

216

217

182

284

683

1,043

3,742

3,697

40,448

39,311

Notes receivable from affiliates, noncurrent

1,455

1,431

898

910

235

234

46,778

45,583

47,509

46,676

500

184

360

1,137

1,088

7,147

7,161

7,795

7,792

199

322

233

220

202

180

8,461

8,529

16,745

16,778

19,116

18,966

Treasury stock, at cost

(123)

14,766

14,081

(2,995)

(3,026)

30,764

29,898

Line of Credit Facility [Line Items]

$ 47,509

$ 46,676

[1]

Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities for additional information.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet - Parenthetical (Details) - $ / shares	Dec. 31, 2018	Dec. 31, 2017
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	968,187,955	963,335,888
Treasury stock, shares held	2,000,000	2,000,000
Exelon Corporate [Member]
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Treasury stock, shares held	35,000,000	35,000,000

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Basis of Presentation - Narrative (Details) - Exelon Corporate [Member]	Dec. 31, 2018
Schedule of Equity Method Investments [Line Items]
Ownership interest	100.00%
Commonwealth Edison Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	99.00%
Baltimore Gas and Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	100.00%
Baltimore Gas and Electric Company [Member] \| Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	0.00%

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Narrative (Details)
$ in Millions

12 Months Ended

Dec. 31, 2018

USD ($)

Maximum Program Size

$ 9,704

^[1]

Line of Credit Facility, Capacity Available for Trade Purchases

7,687

Revolving Credit Facility [Member] | Exelon Corporate [Member]

Line of Credit Facility [Line Items]

Maximum Program Size

600

^[1]

Line of Credit Facility, Capacity Available for Trade Purchases

591

Corporate, Non-Segment [Member] | Exelon Corporate [Member]

Line of Credit Facility [Line Items]

$ 500

LIBOR plus 1%

[1]

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Outstanding Long-term Debt (Details) - USD ($)
$ in Millions

Dec. 31, 2018

Dec. 31, 2017

Jun. 30, 2014

$ 34,911

$ 33,657

Unamortized debt issuance costs

(66)

(57)

216

201

Junior Subordinated Debt [Member]

34,075

32,176

1,150

$ 1,150

3.497%

2.50%

Senior Notes [Member]

Maximum [Member] | Junior Subordinated Debt [Member]

$ 11,285

Maximum [Member] | Senior Notes [Member]

3.50%

Minimum [Member] | Senior Notes [Member]

7.60%

2.45%

$ 7,039

7,039

Unamortized debt issuance costs

(7)

(8)

(47)

(49)

Fair value adjustment of consolidated subsidiary

162

179

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

7,147

7,161

Exelon Corporate [Member] | Senior Notes [Member]

1,150

Exelon Corporate [Member] | Maximum [Member] | Junior Subordinated Debt [Member]

^[1]

$ 5,889

Exelon Corporate [Member] | Maximum [Member] | Senior Notes [Member]

3.50%

Exelon Corporate [Member] | Minimum [Member] | Senior Notes [Member]

^[1]

7.60%

^[1]

2.45%

[1]	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Debt Maturities (Details)
$ in Millions

Dec. 31, 2018

USD ($)

$ 1,349

3,528

1,511

3,084

850

24,979

^[1]

35,301

Equity in earnings (losses) of unconsolidated affiliates

1,450

300

1,150

4,139

$ 7,039

[1]	Includes $390 million due to ComEd and PECO financing trusts.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Related Party Transactions - Summary of Related Party Transactions (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

$ (28)

$ (32)

$ (24)

^[1]

Equity in earnings (losses) of unconsolidated affiliates

2,188

4,414

1,508

2,302

1,879

1,912

216

217

Notes receivable from affiliates, noncurrent

40,448

39,311

898

910

Exelon Corporate [Member] | Exelon Business Services Co Affiliate [Member]

360

^[1]

Equity in earnings (losses) of unconsolidated affiliates

^[1]

^[1]

116

217

Exelon Corporate [Member] | Other Affiliate [Member]

^[1]

197

196

(2)

Exelon Corporate [Member] | Exelon Generation Co L L C [Member]

(6)

Equity in earnings (losses) of unconsolidated affiliates

369

2,710

483

^[2]

100

Notes receivable from affiliates, noncurrent

13,204

13,674

^[2]

898

910

Exelon Corporate [Member] | Commonwealth Edison Co [Member]

Exelon Corporate [Member] | PECO Energy Co [Member]

Exelon Corporate [Member] | Baltimore Gas and Electric Company [Member]

Exelon Corporate [Member] | PHI Service Co Affiliate [Member]

Exelon Corporate [Member] | Exelon Energy Delivery Company LLC [Member]

Equity in earnings (losses) of unconsolidated affiliates

^[3]

^[3]

1,835

1,670

1,041

Exelon Corporate [Member] | Potomac Capital Investment Affiliate [Member]

^[3]

26,702

25,082

Equity in earnings (losses) of unconsolidated affiliates

(17)

Exelon Corporate [Member] | UII LLC [Member]

Equity in earnings (losses) of unconsolidated affiliates

(9)

268

Exelon Corporate [Member] | Exelon Transmission Company LLC [Member]

360

Equity in earnings (losses) of unconsolidated affiliates

(10)

(13)

Exelon Corporate [Member] | VEBA [Member]

Exelon Corporate [Member] | Exelon Enterprise [Member]

(1)

(4)

Equity in earnings (losses) of unconsolidated affiliates

$ (1)

Allowance for Uncollectible Accounts [Member]

$ 22

[1]	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.
[2]	In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation in Exelon’s Consolidated Balance Sheets.
[3]	Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.

Schedule II - Valuation and Qualifying Accounts Schedule II - Valuation and Qualifying Accounts (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2018

Dec. 31, 2017

Dec. 31, 2016

Movement in Valuation Allowances and Reserves [Roll Forward]

^[1]

$ 284

$ 322

$ 334

$ 284

^[1]

159

126

162

^[1],[2]

^[3]

^[1],[4]

197

165

211

Deferred Tax Valuation Allowance [Member]

^[1]

$ 334

319

322

334

Movement in Valuation Allowances and Reserves [Roll Forward]

^[3]

Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

105

174

113

105

(31)

^[5]

^[3]

Exelon Generation Co L L C [Member] | Allowance for Uncollectible Accounts [Member]

113

156

174

113

Movement in Valuation Allowances and Reserves [Roll Forward]

114

Exelon Generation Co L L C [Member] | Deferred Tax Valuation Allowance [Member]

104

114

Movement in Valuation Allowances and Reserves [Roll Forward]

Exelon Generation Co L L C [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

102

166

106

102

(32)

^[6]

Commonwealth Edison Co [Member] | Allowance for Uncollectible Accounts [Member]

106

145

166

106

Movement in Valuation Allowances and Reserves [Roll Forward]

^[7]

^[8]

Commonwealth Edison Co [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

PECO Energy Co [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[9]

^[9]

^[9],[10]

^[9],[11]

PECO Energy Co [Member] | Reserve for Obsolete Materials [Member]

^[9]

Movement in Valuation Allowances and Reserves [Roll Forward]

PECO Energy Co [Member] | Allowance for Doubtful Accounts, Noncurrent [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Baltimore Gas and Electric Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

(2)

(3)

^[12]

Baltimore Gas and Electric Company [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Baltimore Gas and Electric Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Pepco Holdings LLC [Member] | Allowance for Uncollectible Accounts [Member] | Successor [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[13]

^[14]

Pepco Holdings LLC [Member] | Allowance for Uncollectible Accounts [Member] | Predecessor [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[13]

^[14]

Pepco Holdings LLC [Member] | Deferred Tax Valuation Allowance [Member] | Successor [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

(53)

Pepco Holdings LLC [Member] | Deferred Tax Valuation Allowance [Member] | Predecessor [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Pepco Holdings LLC [Member] | Reserve for Obsolete Materials [Member] | Successor [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

(1)

Pepco Holdings LLC [Member] | Reserve for Obsolete Materials [Member] | Predecessor [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Potomac Electric Power Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[15]

^[16]

Potomac Electric Power Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Delmarva Power & Light Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[17]

^[18]

Delmarva Power & Light Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Atlantic City Electric Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[19]

^[20]

Atlantic City Electric Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

$ 0