View Filing Data

$ 0

6,024

6,141

$ 13,261

^[1]

$ 12,223

^[1]

Purchased power and fuel

2,346

2,132

6,352

4,795

287

400

605

2,166

1,892

4,024

3,656

590

533

1,154

1,076

288

271

580

548

5,456

5,115

12,510

10,680

261

(21)

(20)

(30)

829

1,005

992

1,513

(228)

(246)

(445)

(863)

(10)

(6)

(20)

(13)

243

(17)

348

155

(269)

(117)

(721)

834

736

875

792

277

239

224

294

Net income (loss) attributable to noncontrolling interests and preferred security dividends

557

497

498

(35)

(7)

(39)

(12)

Net income on common stock

522

490

612

486

Pension and non-pension postretirement benefit plans:

Prior service benefit reclassified to periodic benefit cost, net of tax

(1)

Actuarial loss reclassified to periodic cost, net of tax

(38)

(50)

(72)

(100)

Transition obligation reclassified to periodic cost, net of tax

Pension and non-pension postretirement benefit plans valuation adjustment

258

246

Deferred Compensation Unit Valuation Adjustment

Change in unrealized gain (loss) on cash-flow hedges

(48)

(65)

(73)

(123)

Change in unrealized income (loss) on equity investments

Change in unrealized income (loss) on foreign currency translation

(5)

(1)

(6)

Change in unrealized gain (loss) on marketable securities

(1)

Reversal of CENG Equity Method AOCI

(116)

Other comprehensive income (loss)

131

Average shares of common stock outstanding:

$ 688

$ 497

$ 785

$ 592

Basic

860

856

860

856

Diluted

864

860

863

859

Earnings per average common share - basic

Earnings per average common share - diluted

$ 0.61

$ 0.57

$ 0.71

$ 0.57

Dividends per common share

0.60

0.57

0.71

0.57

$ 0.31

$ 0.62

$ 0.84

$ 3,588

$ 3,718

$ 7,644

$ 6,859

201

352

535

744

3,789

4,070

8,179

7,603

Purchased power and fuel from affiliate

Purchased power and fuel

1,766

1,656

4,774

3,503

290

417

611

1,255

1,041

2,194

2,007

158

148

305

295

254

210

466

424

118

101

223

194

3,620

3,446

8,379

7,034

261

(268)

(1)

(21)

(20)

(30)

429

603

539

(74)

(77)

(147)

(142)

228

(33)

318

142

(126)

146

(81)

571

477

187

458

199

149

(1)

148

Income (Loss) attributable to noncontrolling interest

372

328

188

310

(32)

(33)

Net income on membership interest

340

330

155

311

Pension and non-pension postretirement benefit plans:

Change in unrealized gain (loss) on cash-flow hedges

(45)

(137)

(70)

(267)

Change in unrealized income (loss) on equity investments

Change in unrealized income (loss) on foreign currency translation

(5)

(1)

(6)

Change in unrealized gain (loss) on marketable securities

(1)

Reversal of CENG Equity Method AOCI

(116)

Other comprehensive income (loss)

(155)

(134)

(238)

217

194

1,128

1,080

2,261

2,238

1,128

1,080

2,262

2,239

Purchased power

204

127

416

364

121

173

266

316

319

603

611

174

170

347

337

149

145

870

848

1,766

1,799

258

232

496

440

(76)

(72)

(153)

(422)

(4)

(7)

(75)

(70)

(150)

(418)

183

162

346

137

Pension and non-pension postretirement benefit plans:

111

209

111

209

656

672

1,648

1,567

656

672

1,649

1,567

Purchased power

193

161

570

426

135

238

160

155

416

319

117

113

522

534

1,366

1,226

134

138

283

341

(25)

(50)

(51)

(3)

(6)

(27)

(28)

(53)

(54)

107

110

230

287

Preferred security dividends

173

200

(6)

(7)

Net income on common stock

173

193

Pension and non-pension postretirement benefit plans:

173

200

651

649

1,689

1,525

653

1,707

1,533

Purchased power and fuel from affiliate

Purchased power and fuel

183

189

592

501

205

212

163

139

326

266

197

175

113

109

598

584

1,483

1,300

224

233

(23)

(28)

(47)

(58)

(22)

(28)

(46)

(57)

178

176

Preferred security dividends

106

(3)

(6)

Net income on common stock

100

Pension and non-pension postretirement benefit plans:

$ 19

$ 25

$ 106

[1]

For the six months ended June 30, 2014 and 2013, utility taxes of $45 million and $39 million, respectively, are included in revenues and expenses for Generation. For the six months ended June 30, 2014 and 2013, utility taxes of $119 million and $117 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2014 and 2013, utility taxes of $65 million and $64 million, respectively, are included in revenues and expenses for PECO. For the six months ended June 30, 2014 and 2013, utility taxes of $43 million and $41 million, respectively, are included in revenues and expenses for BGE.

Consolidated Statements of Operations and Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Prior service costs	$ 5	$ 0	$ 5	$ 1
Actuarial loss reclassified to periodic cost, taxes	(23)	(32)	(46)	(66)
Transition obligation		(1)
Pension and non-pension postretirement benefit plan valuation adjustment, taxes	(166)		(159)	(50)
Change in unrealized gain (loss) on cash flow hedges, taxes	28	45	48	77
Change in unrealized gain (loss) on equity investments taxes	77	(5)	70	(23)
Deferred Compensation Unit Valuation Adjustment tax		(6)		(6)
Actuarial loss reclassified to periodic cost, net of tax	(38)	(50)	(72)	(100)
Other Comprehensive Income (Loss), Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service (Cost) Credit, Net of Tax	(6)	0	(6)	1
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Transition (Asset) Obligation, Net of Tax		0		0
Exelon Generation Co L L C [Member]
Change in unrealized gain (loss) on cash flow hedges, taxes	25	89	44	175
Change in unrealized gain (loss) on marketable securities, taxes			(2)
Change in unrealized gain (loss) on equity investments taxes	$ 77	$ (5)	$ 70	$ (23)

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Cash flows from operating activities
Net income		$ 498
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	$ 1,925	1,972
Impairment of assets held for sale	0
Deferred income taxes and amortization of investment tax credits	133	(468)
Net fair value changes related to derivatives	751	(28)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(168)	(27)
Other non-cash operating activities	567	576
Changes in assets and liabilities:
Accounts receivable	48	131
Inventories	(150)	(18)
Accounts payable, accrued expenses and other current liabilities	(358)	(583)
Option premiums paid, net	21	(10)
Counterparty collateral (posted) received, net	(606)	(259)
Income taxes	(16)	705
Pension and non-pension postretirement benefit contributions	(499)	(284)
Other assets and liabilities	(280)	133
Net cash flows provided by operating activities	1,751	2,338
Cash flows from investing activities
Capital expenditures	(2,501)	(2,518)
Cash Proceeds from Direct Finance Lease Contract Termination	335
Proceeds from nuclear decommissioning trust fund sales	4,219	1,448
Investment in nuclear decommissioning trust funds	(4,238)	(1,565)
Net cash acquired from consolidation of CENG	0
Proceeds from sale of long-lived assets	32	4
Cash acquired from Constellation	129
Acquisitions	(66)	(3)
Proceeds from sales of investments	0
Change in restricted cash	(40)	22
Other investing activities	(57)	63
Net cash flows provided by (used in) investing activities	(2,187)	(2,549)
Cash flows from financing activities
Payment of accounts receivable agreement	0
Changes in short-term debt	293	662
Redemption of preferred securities	0	(93)
Issuance of long-term debt	2,100	509
Retirement or repayment of long-term debt	(1,191)	(616)
Dividends paid on common stock	(533)	(716)
Dividends paid to former Constellation shareholders	0
Proceeds from employee stock plans	18	32
Dividends paid to non-controlling interest of consolidated VIE	(415)	63
Other financing activities	(83)	(62)
Net cash flows used in financing activities	189	(284)
Increase (decrease) in cash and cash equivalents	(247)	(495)
Cash and cash equivalents at beginning of period	1,609	1,486
Cash and cash equivalents at end of period	1,362	991
CityPublicServiceBoardSanAntonio [Member] \| EquipmentLeasedToOtherPartyMember
Cash flows from investing activities
Cash Proceeds from Direct Finance Lease Contract Termination	335	0
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	188	310
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	1,242	1,358
Impairment of assets held for sale	0	0
Deferred income taxes and amortization of investment tax credits	(15)	(44)
Net fair value changes related to derivatives	760	(21)
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(168)	(27)
Other non-cash operating activities	209	315
Gain on consolidation of CENG	268
Changes in assets and liabilities:
Accounts receivable	63	88
Receivables from and payables to affiliates, net	20	(29)
Inventories	(170)	(38)
Accounts payable, accrued expenses and other current liabilities	(273)	(426)
Option premiums paid, net	21	(10)
Counterparty collateral (posted) received, net	(633)	(303)
Income taxes	72	265
Pension and non-pension postretirement benefit contributions	(210)	(120)
Other assets and liabilities	(56)	(168)
Net cash flows provided by operating activities	742	1,150
Cash flows from investing activities
Capital expenditures	(1,103)	(1,277)
Changes in intercompany money pool	190	263
Proceeds from nuclear decommissioning trust fund sales	4,219	1,448
Investment in nuclear decommissioning trust funds	(4,238)	(1,565)
Net cash acquired from consolidation of CENG	129
Proceeds from sale of long-lived assets	32
Acquisitions	66
Change in restricted cash	(17)	(11)
Other investing activities	(14)	27
Net cash flows provided by (used in) investing activities	(1,014)	(1,378)
Cash flows from financing activities
Changes in short-term debt	46	288
Issuance of long-term debt	300	209
Retirement or repayment of long-term debt	(538)	(458)
Distribution to member	(235)	(474)
Contributions from member	0	0
Dividends paid to non-controlling interest of consolidated VIE	(415)	63
Other financing activities	(29)	(49)
Net cash flows used in financing activities	(681)	(221)
Increase (decrease) in cash and cash equivalents	(953)	(449)
Cash and cash equivalents at beginning of period	1,258	671
Cash and cash equivalents at end of period	305	222
Exelon Generation Co L L C [Member] \| EquipmentLeasedToOtherPartyMember
Cash flows from investing activities
Changes in intercompany money pool	(44)
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	209	14
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	347	337
Deferred income taxes and amortization of investment tax credits	63	(226)
Other non-cash operating activities	99	39
Changes in assets and liabilities:
Accounts receivable	(83)	18
Receivables from and payables to affiliates, net	(46)	(26)
Inventories	(4)	(11)
Accounts payable, accrued expenses and other current liabilities	27	20
Income taxes	5	240
Pension and non-pension postretirement benefit contributions	(236)	(119)
Other assets and liabilities	48	217
Net cash flows provided by operating activities	429	503
Cash flows from investing activities
Capital expenditures	(747)	(711)
Proceeds from sales of investments	7	4
Purchases of investments	(3)	(3)
Change in restricted cash	(2)	(3)
Other investing activities	14	20
Net cash flows provided by (used in) investing activities	(731)	(693)
Cash flows from financing activities
Changes in short-term debt	314	374
Issuance of long-term debt	650	0
Retirement or repayment of long-term debt	(617)	(125)
Contributions from parent	112	0
Dividends paid on common stock	(153)	(110)
Other financing activities	(2)	0
Net cash flows used in financing activities	304	139
Increase (decrease) in cash and cash equivalents	2	(51)
Cash and cash equivalents at beginning of period	36	144
Cash and cash equivalents at end of period	38	93
PECO Energy Co [Member]
Cash flows from operating activities
Net income	173	200
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	117	113
Deferred income taxes and amortization of investment tax credits	6	25
Other non-cash operating activities	50	50
Changes in assets and liabilities:
Accounts receivable	34	55
Receivables from and payables to affiliates, net	(21)	(18)
Inventories	22	27
Accounts payable, accrued expenses and other current liabilities	30	35
Income taxes	54	39
Pension and non-pension postretirement benefit contributions	(11)	(10)
Other assets and liabilities	(114)	(49)
Net cash flows provided by operating activities	340	467
Cash flows from investing activities
Capital expenditures	(308)	(254)
Change in restricted cash	0	(1)
Other investing activities	6	4
Net cash flows provided by (used in) investing activities	(302)	(514)
Cash flows from financing activities
Changes in short-term debt	0	0
Redemption of preferred securities	0	(93)
Issuance of long-term debt	0	0
Dividends paid on common stock	(160)	(166)
Dividends paid on preferred securities	0	(1)
Other financing activities	(2)	1
Net cash flows used in financing activities	(162)	(259)
Increase (decrease) in cash and cash equivalents	(124)	(306)
Cash and cash equivalents at beginning of period	217	362
Cash and cash equivalents at end of period	93	56
PECO Energy Co [Member] \| EquipmentLeasedToOtherPartyMember
Cash flows from investing activities
Changes in intercompany money pool	0	(263)
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	106	106
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion	197	175
Deferred income taxes and amortization of investment tax credits	47	98
Other non-cash operating activities	89	61
Changes in assets and liabilities:
Accounts receivable	44	(58)
Receivables from and payables to affiliates, net	(12)	(11)
Inventories	0	4
Accounts payable, accrued expenses and other current liabilities	(74)	(28)
Counterparty collateral (posted) received, net	27	0
Income taxes	(14)	(33)
Pension and non-pension postretirement benefit contributions	(8)	(11)
Other assets and liabilities	8	63
Net cash flows provided by operating activities	410	366
Cash flows from investing activities
Capital expenditures	(313)	(264)
Change in restricted cash	(30)	3
Other investing activities	11	4
Net cash flows provided by (used in) investing activities	(332)	(257)
Cash flows from financing activities
Changes in short-term debt	(65)	0
Issuance of long-term debt	0	300
Retirement or repayment of long-term debt	(35)	(33)
Contributions from parent	0	0
Dividends paid on common stock	0	0
Dividends paid on preferred securities	(6)	(6)
Change in restricted cash for dividends	0	0
Other financing activities	12	(2)
Net cash flows used in financing activities	(94)	259
Increase (decrease) in cash and cash equivalents	(16)	368
Cash and cash equivalents at beginning of period	31	89
Cash and cash equivalents at end of period	$ 15	$ 457

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

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

$ 1,362

$ 1,609

Restricted cash and investments

1,362

1,609

$ 991

207

167

2,973

2,981

1,005

1,175

629

727

264

374

409

276

1,041

829

426

573

732

760

775

666

9,823

10,137

51,747

47,330

5,545

5,910

10,437

8,071

839

1,165

Investment in CENG

1,925

2,674

2,625

482

607

402

458

593

710

1,092

964

22,086

22,457

83,656

79,924

621

341

2,047

1,509

2,633

2,484

1,382

1,633

116

368

327

228

159

239

261

994

858

8,567

7,728

18,133

17,623

648

Deferred income taxes and unamortized investment tax credits

13,192

12,905

7,054

5,194

1,804

1,876

Spent nuclear fuel obligation

1,419

2,190

1,021

4,670

4,388

262

300

Payable for Zion Station decommissioning

260

266

264

305

2,133

2,540

32,079

30,985

59,427

56,984

Treasury stock, at cost (35 and 35 shares held at December 31, 2010 and December 31, 2009, respectively)

16,651

16,741

(2,327)

10,435

10,358

^[1]

(1,906)

(2,040)

BGE preference stock not subject to mandatory redemption

22,853

22,732

193

Noncontrolling interest

1,183

Total equity

24,229

22,940

83,656

79,924

Consolidated Variable Interest Entities

^[1]

(1,906)

(2,040)

126

296

260

133

103

165

959

457

4,603

1,171

2,030

125

127

6,806

7,765

1,755

243

170

165

657

320

258

298

1,731

133

136

178

2,454

338

3,111

658

Removal Costs [Member]

107

1,449

1,423

305

1,258

Cash and cash equivalents of variable interest entities

305

1,258

222

Restricted cash and investments of variable interest entity

1,733

1,689

Accounts receivable of variable interest entities

441

353

Mark-to-market derivative assets with affiliates

629

727

Receivables from affiliates

108

264

374

328

164

872

671

476

475

524

505

5,727

6,439

23,743

20,111

10,437

8,071

432

400

Investment in CENG

1,925

Mark-to-market derivative assets with affiliates

464

600

1,888

1,873

402

458

593

710

687

645

14,952

14,682

44,422

41,232

Long-term debt to PECO Energy Transition Trust due within one year

561

563

Long-term debt of variable interest entities due within one year

Accounts payable of variable interest entities

1,508

1,322

819

976

Borrowings from Exelon intercompany money pool

108

181

190

215

142

233

249

473

389

4,215

3,867

Long-term debt to affiliate

5,944

5,645

948

1,523

Long-term debt of variable interest entity

Deferred income taxes and unamortized investment tax credits

6,334

6,295

6,907

5,047

125

Spent nuclear fuel obligation

941

850

1,021

2,917

2,740

135

120

Payable for Zion Station decommissioning

260

266

264

305

761

811

19,665

17,455

Commitments and contingencies

30,772

28,490

^[1]

214

Noncontrolling interest

1,185

Membership interest

8,895

8,898

Undistributed earnings

3,533

3,613

Total liabilities and equity

^[1]

214

Total member's equity

12,465

12,725

Total equity

13,650

12,742

44,422

41,232

Exelon Generation Co L L C [Member] | Consolidated Variable Interest Entities

126

296

260

133

103

165

924

418

4,603

1,171

2,030

106

6,787

1,277

7,711

1,695

243

170

165

575

236

1,731

133

136

178

2,280

126

2,855

362

516

451

428

584

Inventories, net

112

109

Counterparty collateral deposited

172

304

329

1,434

1,540

15,121

14,666

850

933

2,625

2,606

2,469

1,626

1,583

275

291

7,989

7,912

24,544

24,118

498

184

260

617

505

449

274

307

117

Customer deposits

130

133

164

170

Mark-to-market derivative liabilities with affiliate

2,080

2,048

5,448

5,058

206

Deferred income taxes and unamortized investment tax credits

4,080

4,116

100

284

381

3,686

3,512

121

176

841

994

9,112

9,278

Commitments and contingencies

16,846

16,590

1,588

Other paid-in capital

5,304

5,190

806

750

7,698

7,528

24,544

24,118

Commonwealth Edison Co [Member] | Removal Costs [Member]

1,248

1,219

217

217

Restricted cash and investments of variable interest entity

304

360

107

Prepaid utility taxes

803

906

6,545

6,384

1,495

1,448

490

447

359

363

2,413

2,327

9,761

9,617

Short-term notes payable - accounts receivable agreement

250

298

285

167

106

Customer deposits

106

922

891

1,947

184

Deferred income taxes and unamortized investment tax credits

2,545

2,487

292

286

671

629

3,630

3,530

6,683

6,552

Preferred securities

2,415

662

649

^[1]

3,078

3,065

9,761

9,617

PECO Energy Co [Member] | Removal Costs [Member]

^[1]

$ 457

419

480

102

114

Income taxes receivable

Prepaid utility taxes

178

181

916

1,011

6,030

5,864

499

524

396

423

931

986

7,877

7,861

135

205

270

111

Customer deposits

747

827

1,904

1,941

258

Deferred income taxes and unamortized investment tax credits

1,814

1,773

215

217

202

204

2,313

2,280

Commitments and contingencies

5,222

5,306

1,360

1,105

1,005

BGE preference stock not subject to mandatory redemption

2,465

2,365

190

Total equity

2,655

2,555

Baltimore Gas and Electric Company [Member] | Consolidated Variable Interest Entities

7,877

7,861

158

195

158

195

Baltimore Gas and Electric Company [Member] | Removal Costs [Member]

234

269

Significant Accounting Policies [Line Items]

$ 201

$ 204

[1]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013
Accounts Receivable [Abstract]
Gross accounts receivable pledged as collateral	$ 0	$ 0
Shareholders' equity
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	893,940,600	857,000,000
Treasury Stock, Shares held	35,000,000	35,000,000
PECO Energy Co [Member]
Accounts Receivable [Abstract]
Gross accounts receivable pledged as collateral	$ 0	$ 0

Consolidated Statement of Changes in Shareholders Equity (Unaudited) - 6 months ended Jun. 30, 2014 - USD ($) shares in Thousands, $ in Millions	Total	Common Stock [Member]	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive (Loss) Income, Net	Noncontrolling Interest	Preference Stock Not Subject To Mandatory Redemption [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member] Undistributed Earnings [Member]	Exelon Generation Co L L C [Member] Membership Interest [Member]	Exelon Generation Co L L C [Member] Accumulated Other Comprehensive (Loss) Income, Net	Exelon Generation Co L L C [Member] Noncontrolling Interest	PECO Energy Co [Member]	PECO Energy Co [Member] Common Stock [Member]	PECO Energy Co [Member] Retained Earnings	PECO Energy Co [Member] Accumulated Other Comprehensive (Loss) Income, Net	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member] Common Stock [Member]	Commonwealth Edison Co [Member] Other Paid-In Capital	Commonwealth Edison Co [Member] Retained Deficit Unappropriated	Commonwealth Edison Co [Member] Retained Earnings Appropriated	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member] Common Stock [Member]	Baltimore Gas and Electric Company [Member] Nonredeemable Preferred Stock [Member]	Baltimore Gas and Electric Company [Member] Retained Earnings
Beginning Balance at Dec. 31, 2013								$ 12,742	$ 3,613	$ 8,898	$ 214	$ 17
Beginning Balance at Dec. 31, 2013	$ 22,940	$ 16,741	$ (2,327)	$ 10,358	$ (2,040)	$ 15	$ 193															$ 2,555
Beginning Balance at Dec. 31, 2013		892,034
Beginning Balance at Dec. 31, 2013	22,732												$ 3,065	$ 2,415	$ 649	$ 1	$ 7,528	$ 1,588	$ 5,190	$ (1,639)	$ 2,389	2,365	$ 1,360	$ 190	$ 1,005
Net income				612			6	188	155			33	173		173		209			209		106			106
Net income on common stock	612												173									100
Long-term incentive plan activity		1,408
Employee stock purchase plan issuances		499
Appropriation of retained earnings for future dividends																				(209)	209
Long-term incentive plan activity	32	$ 32
Employee stock purchase plan issuances	14	14
Common stock dividends	(535)			(535)									(160)		(160)		(153)				(153)
Contribution from parent								0		0		0					112		112
Distribution to members								(235)	(235)
Allocation of tax benefit from members								(3)		(3)
Preferred stock redemption premium													0		0
Allocation of tax benefit from parent																	2		2
Consolidated VIE dividend to non-controlling interest	(415)					(415)		(415)				(415)
Preferred security dividends	6						0						0		0							(6)		(6)
Noncontrolling interest acquired	1,548					1,548		1,548				1,548
Reversal of CENG Equity Method AOCI	(116)				(116)			(116)			(116)
Other comprehensive income (loss), net of tax					250						(61)
Sale of noncontrolling interest								2		0		2
Ending Balance at Jun. 30, 2014								13,650	$ 3,533	8,895	$ 37	1,185
Ending Balance at Jun. 30, 2014	24,229	$ 16,651	$ (2,327)	$ 10,435	$ (1,906)	$ 1,183	$ 193															2,655
Ending Balance at Jun. 30, 2014		893,941
Ending Balance at Jun. 30, 2014	22,853												$ 3,078	$ 2,415	$ 662	$ 1	$ 7,698	$ 1,588	$ 5,304	$ (1,639)	$ 2,445	$ 2,465	$ 1,360	$ 190	$ 1,105
ImpairmentOfLongLivedAssetsToBeDisposedOf								0				0
Deconsolidation of VIE								$ 0		$ 0		$ 0
Reduction of Equity for present value of contract payments	$ (131)	$ (131)

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Other comprehensive income, income taxes	$ (79)	$ 1	$ (82)	$ (67)
Accumulated Other Comprehensive (Loss) Income, Net
Other comprehensive income, income taxes			159
Exelon Generation Co L L C [Member]
Other comprehensive income, income taxes	$ 102	$ 84	112	$ 152
Exelon Generation Co L L C [Member] \| Accumulated Other Comprehensive (Loss) Income, Net
Other comprehensive income, income taxes			$ 35

Basis of Presenation (Exelon, Generation, Come, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)

1. Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG's nuclear fleet. As a result, Exelon and Generation consolidated CENG's financial position and results of operations into their businesses. Prior to April 1, 2014, Exelon and Generation accounted for CENG as an equity method investment. Refer to Note 6 – Investment in CENG for further information regarding the integration transaction.

The energy generation business includes:

Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions.

The energy delivery businesses include:

ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.
PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore.

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

Certain prior year amounts in the Exelon, Generation and BGE Consolidated Statement of Operations have been reclassified between line items for comparative purposes and correction of prior period classification errors identified in 2013. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities. Exelon corrected the presentation of Purchased power and fuel from affiliates of $287 million and $605 million on its Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2013, respectively. Generation corrected the presentation of Purchased power and fuel from affiliates of $290 million and $611 million on its Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2013, respectively. Generation also corrected the presentation of Interest expense to affiliates, net of $16 million and $34 million on its Statement of Operations and Comprehensive Income for the three and six months ended June 30, 2013, respectively. BGE corrected its presentation of Interest expense to affiliates, net of $4 million and $8 million on the Statement of Operations and Comprehensive Income for the three and six months ended June 30, 2013, respectively.

The accompanying consolidated financial statements as of June 30, 2014 and 2013 and for the six months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants' respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2013 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2014. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Combined Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2013 Form 10-K Reports.

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

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New Accounting Pronouncements And Changes In Accounting Principles [Line Items]

New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Schedule Of New Accounting Pronouncements And Changes In Accounting Principles (Exelon, Generation, ComEd, PECO and BGE)

2. New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)

The following recently issued accounting standards were adopted by or are effective for the Registrants during 2014.

Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist

In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants' results of operations or cash flows.

Tabular disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

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Variable Interest Entities Disclosure [Line Items]

Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)

3. Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)

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

At June 30, 2014 and December 31, 2013, Exelon, Generation, and BGE collectively consolidated six and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary (see detail by Registrant below). As of June 30, 2014 and December 31, 2013, the Registrants had significant interests in nine and eight other VIEs, respectively, for which the Registrants do not have the power to direct the entities' activities and, accordingly, were not the primary beneficiary.

Through March 31, 2014, CENG was operated as a joint venture with EDFI and was governed by a board of ten directors, five of which were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control of Generation and EDFI; therefore, CENG was not subject to VIE guidance. Accordingly, Generation's 50.01% interest in CENG was accounted for as an equity method investment. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the 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 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 EDFI. As a result of executing the NOSA, CENG now 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 conveyed through the NOSA. Further, since Generation is conducting the operational activities of CENG, Generation qualifies as the primary beneficiary of CENG and, therefore, is required to consolidate the financial position and results of operations of CENG. On April 1, 2014, Exelon and Generation derecognized Generation's equity method investment in CENG and reflected all assets, liabilities, and the EDFI non-controlling interest in CENG at fair value on the consolidated balance sheets of Exelon and Generation, resulting in the recognition of a $261 million gain in their respective consolidated statements of operations and comprehensive income for the three and six months ended June 30, 2014. For additional information on this transaction refer to Note 6 – Investment in Constellation Energy Nuclear Group, LLC.

In March 2014, Generation began consolidating retail power 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. These entities are included in Generation's consolidated financial statements and the consolidation of the VIEs did not have a material impact on Generation's financial results or financial condition.

Consolidated Variable Interest Entities

Exelon, Generation and BGE's consolidated VIEs consist of:

BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, and issue and service bonds secured by rate stabilization property,
a retail gas group formed by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier,
a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities,
several wind project companies designed by Generation to develop, construct and operate wind generation facilities,
certain retail power companies for which Generation is the sole supplier of energy, and
Constellation Energy Nuclear Group, Inc. (CENG).

As of June 30, 2014 and December 31, 2013, ComEd and PECO do not have any material consolidated VIEs.

As of June 30, 2014 and December 31, 2013, Exelon, Generation, and BGE provided the following support to the consolidated VIEs:

In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three and six months ended June 30, 2014, BGE remitted $21 million and $42 million, respectively, to BondCo. During the three and six months ended June 30, 2013, BGE remitted $17 million and $39 million, respectively, to BondCo.
Generation provides operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to the Antelope Valley project.
Generation and Exelon, where indicated, provide the following support to CENG (see Note 25 – Related Party Transactions of the Exelon 2013 Form 10-K and Note 6 – Investment in Constellation Energy Nuclear Group, LLC for additional information regarding Generation and Exelon's transactions with CENG).

under the Nuclear Operating Services Agreement (NOSA), Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services 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 Inc. (EDFI) (a subsidiary of EDF),
under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to CENG fleet for the remaining life of the CENG nuclear plants,
under power purchase agreements with CENG, Generation will purchase 85% of the available output generated by CENG nuclear plants for the remainder of 2014 and 50.01% from 2015 through the end of the life of each respective plant under power purchase agreements with CENG,
Generation provided a $400 million loan to CENG,
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 18 – Commitments and Contingencies for more details),
in connection with CENG's severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid in 2013 through 2016. As of June 30, 2014, the remaining obligation is approximately $4 million (see Integration-Related Severance under Note 14 – Severance for additional details),
Generation and EDFI share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance (See Note 18 Commitments and Contingencies for more details),
Generation provides a $7 million guarantee associated with hazardous waste management facilities and underground storage tanks. In addition, EDFI executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,
Generation and EDFI are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (See Note 18 Commitments and Contingencies for more details), 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.

Generation provides approximately $4 million in credit support for the retail power companies, and
Generation provides a $75 million parental guarantee to the third-party gas supplier in support of its retail gas group.

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

The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
Exelon, Generation and BGE did not provide any additional material financial support to the VIEs;
Exelon, Generation and BGE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and
the creditors of the VIEs did not have recourse to Exelon's, Generation's or BGE's general credit.

The carrying amounts and classification of the consolidated VIEs' assets and liabilities included in Exelon's, Generation's, and BGE's consolidated financial statements at June 30, 2014 and December 31, 2013 are as follows:

		June 30, 2014						December 31, 2013
		Exelon (a) (b)		Generation (b)		BGE		Exelon (a)		Generation		BGE
Current assets		$	991	$	956	$	28	$	484	$	446	$	28
Noncurrent assets			7,426		7,407		3		1,905		1,884		3
	Total assets	$	8,417	$	8,363	$	31	$	2,389	$	2,330	$	31

Current liabilities		$	815	$	732	$	76	$	566	$	481	$	74
Noncurrent liabilities			2,911		2,738		158		774		562		195
	Total liabilities	$	3,726	$	3,470	$	234	$	1,340	$	1,043	$	269

		June 30, 2014						December 31, 2013
		Exelon		Generation		BGE		Exelon		Generation		BGE
Cash and cash equivalents		$	126	$	126	$	-	$	62	$	62	$	-
Restricted cash			75		47		28		80		52		28
Accounts receivable, net
	Customer		296		296		-		260		260		-
	Other		133		133		-		-		-		-
Inventory
	Fossil fuel		103		103		-		2		2		-
	Materials and supplies		165		165		-		-		-		-
Other current assets			61		54		-		53		42		-
	Total current assets		959		924		28		457		418		28

Property, plant and equipment, net			4,603		4,603		-		1,171		1,171		-
Nuclear decommissioning trust funds			2,030		2,030		-		-		-		-
Goodwill			48		48		-		-		-		-
Other noncurrent assets			125		106		3		127		106		3
	Total noncurrent assets		6,806		6,787		3		1,298		1,277		3
	Total assets	$	7,765	$	7,711	$	31	$	1,755	$	1,695	$	31

Short-term borrowings		$	40	$	40	$	-	$	-	$	-	$	-
Long-term debt due within one year			84		5		72		85		5		70
Accounts payable			243		243		-		170		170		-
Accrued expenses			89		86		4		26		22		4
Mark-to-market derivative liabilities			24		24		-		29		29		-
Unamortized energy contracts			12		12		-		5		5		-
Other current liabilities			165		165		-		5		5		-
	Total current liabilities		657		575		76		320		236		74

Long-term debt			258		84		158		298		86		195
Asset retirement obligations			1,731		1,731		-		-		-		-
Pension obligation^(a)			133		133		-		-		-		-
Non-pension postretirement benefit			136		136		-		-		-		-
Unamortized energy contracts			18		18		-		12		12		-
Other noncurrent liabilities			178		178		-		28		28		-
	Noncurrent liabilities		2,454		2,280		158		338		126		195
	Total liabilities	$	3,111	$	2,855	$	234	$	658	$	362	$	269

___________

Includes the CNEG Retail Gas' pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation's balance sheet. See Note 13 for additional details.

Unconsolidated Variable Interest Entities

Exelon's and Generation's variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon's and Generation's Consolidated Balance Sheets in Investments in affiliates, Investments, and Other Assets. For the energy purchase and sale contracts and the fuel purchase commitments (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.

The Registrants' unconsolidated VIEs consist of:

Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.
ZionSolutions, LLC asset sale agreement with EnergySolutions, Inc. and certain subsidiaries in which Generation has a variable interest but has concluded that consolidation is not required.
Equity investments in energy development projects and energy generating facilities for which Generation has concluded that consolidation is not required.

As of June 30, 2014 and December 31, 2013, Exelon and Generation had significant unconsolidated variable interests in nine and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The increase in the number of unconsolidated VIEs is due to an investment in another unconsolidated VIE and the execution of an energy purchase and sale agreement with an unconsolidated VIE, offset by the sale of Generation's ownership interest in one unconsolidated VIE. The following tables present summary information about Exelon and Generation's significant unconsolidated VIE entities:


		Commercial		Equity
		Agreement		Investment
June 30, 2014		VIEs		VIEs		Total
Total assets ^(a)		$	119	$	325	$	444
Total liabilities^(a)			2		120		122
Exelon's ownership interest in VIE^(a)			0		63		63
Other ownership interests in VIE^(a)			117		142		259
Registrants' maximum exposure to loss:
	Carrying amount of equity method investments		0		73		73
	Contract intangible asset		9		0		9
	Debt and payment guarantees		0		3		3
	Net assets pledged for Zion Station decommissioning ^(b)		45		0		45


		Commercial		Equity
		Agreement		Investment
December 31, 2013		VIEs		VIEs		Total
Total assets ^(a)		$	128	$	332	$	460
Total liabilities^(a)			17		123		140
Exelon's ownership interest in VIE^(a)			0		86		86
Other ownership interests in VIE^(a)			111		123		234
Registrants' maximum exposure to loss:
	Carrying amount of equity method investments		7		67		74
	Contract intangible asset		9		0		9
	Debt and payment guarantees		0		5		5
	Net assets pledged for Zion Station decommissioning^(b)		44		0		44

These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $402 million and $458 million as of June 30, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $357 million and $414 million as of June 30, 2014 and December 31, 2013, 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 assess the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

Merger and Acquisitions (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Business Acquisition [Line Items]

Mergers and Acquisitions (Exelon, Generation, ComEd, PECO and BGE)

4. Mergers, Acquisitions and Dispositions

Proposed Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI's shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it purchased $90 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI, in the second quarter of 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any. The $90 million of PHI preferred securities are included in Other non-current assets on Exelon's Consolidated Balance Sheet as of June 30, 2014. Exelon expects total cash required to fund the acquisition of common stock and preferred securities plus other related acquisition costs to total approximately $7.2 billion.

The transaction must be approved by the shareholders of PHI. Completion of the transaction is also conditioned upon approval by the FERC, the District of Columbia Public Service Commission and several state commissions including Delaware Public Service Commission, MDPSC, the New Jersey Board of Public Utilities and the Virginia Department of Public Utilities. In addition, under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Federal Trade Commission (FTC) and/or the Antitrust Division of the United States Department of Justice (DOJ) and until specified waiting period requirements have expired.

Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors' breaches. The suits seek to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. Exelon intends to vigorously defend these suits. Exelon does not believe these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon's results of operations.

Through June 30, 2014, Exelon has incurred approximately $25 million of expense associated with the transaction, primarily related to fees incurred as part of the acquisition. As part of the applications for approval of the merger, Exelon and PHI have proposed a package of benefits to PHI utilities' customers which results in a direct investment of more than $100 million. The Merger Agreement also provides for termination rights on behalf of both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement does not close due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities (described above), by means of PHI redeeming the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock. The companies anticipate closing the transaction in the second or third quarter of 2015, subject to receipt of required regulatory approvals.

Merger Financing

Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1.0 billion cash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). On June 11, 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 forward sales agreements and $1.2 billion of junior subordinated notes in the form of 23 million equity units. In addition, Exelon signed a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which has subsequently been reduced to $4.2 billion as a result of the equity issuances. See Note 10—Debt and Credit Agreements and Note 16—Common Stock for more information.

Safe Harbor Water Power Corporation (Exelon and Generation)

On May 15, 2014, Generation entered into a Purchase and Sale Agreement with Brookfield Renewable Energy Partners L.P. to sell Generation's 67% economic equity interest in the 417 MW Safe Harbor Water Power Corporation hydroelectric facility on the Susquehanna River in Pennsylvania (Safe Harbor). The total purchase price for the transaction is approximately $613 million. The transaction, which is subject to customary closing conditions and regulatory approvals, is expected to be completed in the third quarter of 2014, at which time Generation anticipates recording a pre-tax gain of approximately $332 million. The after-tax net cash proceeds of $375 million are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes.

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

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Public Utilities, General Disclosures [Line Items]

Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

5. Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)

Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)

Except for the matters noted below, the disclosures set forth in Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd). Since 2011, ComEd's distribution rates are established through a performance-based rate formula, pursuant to EIMA. Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. ComEd's earned rate of return on common equity is required to be within plus or minus 50 basis points (“the collar”) of the target rate of return determined as the annual average rate on 30-year treasury notes plus 580 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. In addition, ComEd's target rate of return on common equity is subject to reduction if ComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investment program. ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd's best estimate of the revenue requirement expected to be approved by the ICC for that year's reconciliation. As of June 30, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $439 million and $463 million, respectively. The regulatory asset associated with the distribution true-up will be amortized as the associated amounts are recovered through rates.

On April 16, 2014, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2015 after the ICC's review and approval, which is due by December 2014. The revenue requirement requested is based on 2013 actual costs plus projected 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred that year. ComEd's 2014 filing request includes a total increase to the net revenue requirement of $269 million, reflecting an increase of $174 million for the initial revenue requirement for 2014 and an increase of $95 million related to the annual reconciliation for 2013. The revenue requirement for 2014 provides for a weighted average debt and equity return on distribution rate base of 7.06% inclusive of an allowed return on common equity of 9.25%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2013 provided for a weighted average debt and equity return on distribution rate base of 7.04% inclusive of an allowed return on common equity of 9.20%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points.

EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. Participating utilities are required to file an annual update on their AMI implementation progress. On April 1, 2014, ComEd filed an annual progress report on its AMI Implementation Plan with the ICC. The ICC ruled that no investigation would be opened in regards to that April filing. In March, 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI meters. On June 11, 2014, the ICC approved ComEd's accelerated deployment plan which allows for the installation of more than four million smart meters throughout ComEd's service territory by 2018, three years in advance of the originally scheduled 2021 completion date. To date, nearly 350,000 smart meters have been installed in the Chicago area.

Appeal of the 2012 Formula Rate Tariff (Exelon and ComEd). On April 30, 2012, ComEd filed its annual distribution formula rate update. On December 20, 2012, the ICC issued its final order, which increased the revenue requirement by $73 million, in conformity with the formula rate structure provided in the ICC's May 2012 and Rehearing Orders. The $73 million reflected an increase of $80 million for the initial revenue requirement for 2012 and a decrease of $7 million for the annual reconciliation for 2011. The rate increase was set using an allowed return on capital of 7.54% (inclusive of an allowed return on common equity of 9.81%). The rates took effect in January 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court.

On June 30, 2014, the Illinois Appellate Court issued its opinion in the Appeal of the 2012 Formula Rate Tariff. Two of the three issues appealed (billing determinants and the use of certain allocators) were the same issues previously rejected by the Court in the Appeal of Initial Formula Rate Tariff (see Appeal of Initial Formula Rate Tariff discussed below). The Court re-affirmed the ICC's order and rejected ComEd's arguments. However, on the third issue (rate case expenses), the Court allowed for the possibility of future recovery. The Court's opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC's final Order.

Appeal of Initial Formula Rate Tariff (Exelon and ComEd). On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd's appeal of the ICC's order relating to ComEd's initial formula rate tariff. The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9). Therefore, only a subset of the issues originally appealed remained. The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court's opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC's final Order.

ComEd has asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. On June 4, 2014, ComEd filed a Petition for Leave to Appeal with the Illinois Supreme Court solely on the issue of allocation between FERC and ICC jurisdictional costs. On July 2, the ICC filed its Answer to the Petition, arguing that Supreme Court review is not necessary or appropriate. Under the rules, ComEd is not allowed to reply to the ICC filing. There is no set time by which the Court must decide rule on the Petition. ComEd cannot predict whether the Court will grant the appeal, or if it does, the ultimate outcome.

Advanced Metering Program Proceeding (Exelon and ComEd). As part of ComEd's 2007 electric distribution rate case, the ICC approved recovery of costs associated with ComEd's System Modernization Program (Rider SMP) for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd's AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through June 30, 2014. In ComEd's 2010 electric distribution rate case, the ICC approved ComEd's transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates.

Several parties, including the Illinois Attorney General, appealed the ICC's orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC's approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC's approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied.

In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC's approval of the cost recovery provisions of Rider SMP. ComEd believes no refund is appropriate and that any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Illinois Appellate Court's order on Rider AMP, or March 19, 2012, which would represent a refund of approximately $0.4 million. During the second quarter of 2014, ComEd reached a tentative proposed agreement to jointly resolve the disputed refund claim. Any joint agreement must ultimately be approved by the ICC through its investigation. At June 30, 2014, ComEd recorded a regulatory liability of approximately $9 million based on its assessment of the likely outcome of the matter. ComEd cannot predict the ultimate outcome of the ICC's investigation and therefore, actual refunds, if any, may differ from the estimated liability recorded at June 30, 2014.

Grand Prairie Gateway Transmission Line (ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC's approval to construct a 57-mile, overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. Numerous stakeholders are participating in the proceeding and ComEd expects the ICC to rule on its request by October 27, 2014. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd's request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd's transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd's control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd's transmission rate base.

Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, as a result of the Illinois Settlement Legislation, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. On December 18, 2013, the ICC approved the IPA's procurement plan covering the period June 2014 through May 2019.

The Illinois Settlement Legislation requires ComEd to purchase an increasing percentage of the electricity for customer deliveries from renewable energy resources. Purchases by customers of electricity from competitive generation suppliers, whether as a result of the customers' own actions or as a result of municipal aggregation, are not included in this calculation and have the effect of reducing ComEd's purchase obligation. ComEd entered into several 20-year contracts with unaffiliated suppliers in December 2010 regarding the procurement of long-term renewable energy and associated RECs in order to meet its obligations under the state's RPS. Under the Illinois Settlement Legislation, all associated costs are recoverable from customers. The ICC did not require the acquisition of additional renewable resources for the period June 2014 through May 2015 due to ComEd expecting to exceed the renewable cost cap.

The IPA's 2014-2019 plan provides for two separate energy procurements during 2014 to address potential fluctuations in energy demand due to customer switching between ComEd and competitive electric generation suppliers. The ICC also approved the IPA's expansion of energy efficiency programs for both ComEd and Ameren. As of June 30, 2014, ComEd has completed the first ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017. See Note 18 – Commitments and Contingencies for additional information on ComEd's energy commitments.

During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The sourcing agreement provides that the Utilities will pay FutureGen's contract prices, which are set annually pursuant to a formula rate. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from selling capacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of the facility. The order also directs the Utilities to recover (or pass along) these costs from the Utilities' distribution system customers, regardless of whether they purchase electricity from the utility or from competitive electric generation suppliers. In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC's order requiring ComEd to enter into the contract with FutureGen and allowing ComEd to recover the associated costs from retail customers purchasing electricity from both ComEd and competitive electric generation suppliers. ComEd is assessing the Court's order and is in process of determining the appropriate course of action.

On August 22, 2013, the Utilities executed the sourcing agreement with FutureGen in accordance with the ICC order. However, in the event the order is reversed as a result of the appeal, ComEd's obligations under the sourcing agreement would be suspended. In June 2014, ComEd filed a petition with the ICC seeking approval of a tariff allowing ComEd to recover its costs associated with the FutureGen contract from all of its delivery service customers. An order approving that tariff is expected before the end of 2014. Depending on the ultimate outcome of the outstanding appeals, and petitions, the eventual market conditions and the cost of the facility, the sourcing agreement could have a material adverse impact on Exelon's and ComEd's cash flows and financial positions.

Pennsylvania Regulatory Matters

Pennsylvania Procurement Proceedings (Exelon and PECO). On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO's second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129.

In the second DSP Program, PECO is procuring electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in June 2013. In September 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small and medium commercial classes that began in December 2013. In January 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential and small, medium, and large commercial classes that began in June 2014. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Statement of Operations and Comprehensive Income.

In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning April 2014. On May 1, 2013, PECO filed its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO's plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, low-income advocacy groups filed an appeal and emergency request for a stay with the Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income customers. On March 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court's review, PECO will not implement CAP Shopping. The Commonwealth Court's decision is expected in late 2014.

On March 10, 2014, PECO filed its third DSP Program with the PAPUC. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. A PAPUC ruling is expected in late 2014.

Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO's Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million smart meters and an AMI communication network by 2020. The first phase of PECO's SMPIP, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO's universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO's SMPIP, under which PECO will deploy substantially all of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 of which $200 million will be funded by SGIG as discussed below. As of June 30, 2014, PECO has spent $480 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date.

Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate to PECO's existing mortgage. The SGIG funds are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of June 30, 2014, PECO has received $198 million, including $4 million for sub-recipients, of the $200 million in reimbursements. PECO's outstanding receivable from the DOE for reimbursable costs was $2 million as of June 30, 2014, which has been recorded in Other accounts receivable, net on Exelon's and PECO's Consolidated Balance Sheets.

On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor's meters. PECO is moving forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment.

Following PECO's decision, as of October 9, 2012, PECO will no longer use the original smart meters. For the meters that will no longer be used, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period's earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any settlement with the vendor will not be considered project income. In addition, PECO remains eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and received $12 million in return. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals. As of December 31, 2013, $5 million was recorded on Exelon's and PECO's Consolidated Balance Sheets. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which was fully collected as of June 30, 2014, with no gain or loss impacts on future results of operations.

Energy Efficiency Programs (Exelon and PECO). PECO's PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I Plan set forth how PECO would meet the required reduction targets established by Act 129's EE&C provisions, which included a 3% reduction in electric consumption in PECO's service territory and a 4.5% reduction in PECO's annual system peak demand in the 100 hours of highest demand by May 31, 2013.

The peak demand period ended on September 30, 2012 and PECO filed its final compliance report on Phase 1 targets with the PAPUC on November 15, 2013. On March 20, 2014, the PAPUC issued its final report stating that PECO was in full compliance with all Phase I targets.

On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO's EE&C Plan subsequent to its Phase II Plan.

On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO's Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO's Petition. The Order became final on May 5, 2014.

Pennsylvania Retail Electricity Market (Exelon and PECO). The extreme weather experienced in early 2014 resulted in increased commodity costs causing certain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers to provide more consumer education regarding their contract. The second rulemaking order requires electric distribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated switching are to be in place within 30 days and six months of approval of the orders, respectively. The Independent Regulatory Review Commission granted approval of the orders on May 22, 2014. The orders became final on June 14, 2014.

Maryland Regulatory Matters

2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, BGE filed an application for increases of $118 million and $68 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.65% and 10.55% for electric and gas distribution, respectively. The new electric and gas distribution base rates are expected to take effect in late January 2015. BGE cannot predict the outcome of this proceeding or how much of the requested increases the MDPSC will approve.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE's application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE's proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. On December 13, 2013, the MDPSC issued an order in BGE's 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after December 13, 2013. As part of its December 13, 2013 decision granting BGE increases for its gas and electric distribution rates, the MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements. Such a decision, however, was premised upon the condition that the MDPSC approve specific projects scheduled for each year of the five-year program in advance of cost recovery through the surcharge mechanism. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. As a result of the MDPSC's decision, BGE estimates 2014 capital and operating and maintenance costs associated with the ERI initiative of $14.8 million and a revenue requirement of $1.4 million. The ERI initiative surcharge became effective June 1, 2014. BGE is required to file an update on the 2014 work plan and reliability performance information for the specific projects, along with its work plan and cost estimates for 2015, on or before November 1, 2014.

In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE's 2013 electric and gas distribution rate cases. The nature of the appeal will not be known until further pleadings are filed by the residential consumer advocate. 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 includes the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million has been recovered through a grant from the DOE. 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. As of June 30, 2014 and December 31, 2013, BGE recorded a regulatory asset of $94 million and $66 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. Additionally, the MDPSC has determined that the cost recovery for the non-AMI meters that BGE retires will be considered in a future depreciation proceeding.

On February 26, 2014, the MDPSC issued an Order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customers electing to opt-out, effective the later of the first full billing cycle following July 1, 2014, or the AMI installation date in a customer's community. The fees authorized by the order will be reviewed after an initial 12 to 18 month period. The ultimate impact of opt-out could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system.

Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law, which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC's approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would 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 included in gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE's plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE's proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to Exelon and BGE as of June 30, 2014.

In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE's infrastructure replacement plan. The residential consumer advocate filed its related legal memorandum on July 7, 2014, claiming that the MDPSC did not apply the appropriate consideration in approving BGE's infrastructure replacement plan and associated surcharge. BGE has until August 7, 2014 to submit a response, and a hearing has been scheduled for September 5, 2014. BGE cannot predict the outcome of this appeal.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd and BGE). ComEd's and BGE's transmission rates are each established based on a FERC-approved formula. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd's and BGE's best estimate of the revenue requirement expected to be approved by the FERC for that year's reconciliation. As of June 30, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the transmission formula rate of $10 million and $17 million, respectively, and BGE had recorded a net regulatory asset associated with the transmission formula rate of $4 million and a net regulatory liability of $0 million, respectively. The regulatory asset associated with the transmission true-up will be amortized as the associated amounts are recovered through rates.

On April 16, 2014, ComEd filed its annual formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2014, subject to review by the FERC and other parties, which is due by November 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $524 million plus an $11 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $535 million. This compares to the 2013 revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a total revenue requirement of $513 million. The increase in the revenue requirement was primarily driven by increased capital investment and higher operating and maintenance costs.

ComEd's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.62%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. As part of the FERC-approved settlement of ComEd's 2007 transmission rate case, the rate of return on common equity is 11.50% 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%.

On April 28, 2014, BGE filed its annual formula rate update with the FERC. The filings established the revenue requirement used to set rates that took effect in June 2014, subject to review by the FERC and other parties, which is due by October 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $167 million plus a $4 million adjustment related to the reconciliation of 2013 actual costs for a net revenue requirement of $171 million. This compares to the 2013 revenue requirement of $158 million offset by a $1 million reduction related to the reconciliation of 2012 actual costs for a net revenue requirement of $157 million. The increase in the revenue requirement is primarily driven by higher depreciation expense and an increased level of return on investment associated with a higher equity ratio and increased rate base.

BGE's updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% average debt and equity return previously authorized. As part of the FERC-approved settlement of BGE's 2005 transmission rate case in 2006, the rate of return on common equity for BGE's electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.3%, inclusive of a 50 basis point incentive for participating in PJM.

FERC Transmission Complaint (Exelon and BGE). On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the PHI companies relating to their respective transmission formula rates. BGE's formula rate includes a 10.8% base rate of return on common equity (ROE) for most investments included in its rate base and 11.3% for the remaining transmission investment (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the revenues subject to refund are limited to a fifteen month period, and the earliest date from which the base return on equity could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint. On June 19, 2014, FERC issued an order in another case involving New England Transmission Owners (NETOs), changing its methodology to determine ROE rates for public utilities. The result was a reduction in the NETO's ROE from 11.14% to 10.57%, with a possible further adjustment in either direction based on additional paper hearing submissions. On July 21, 2014, the NETOs filed a Request for Rehearing and Clarification with FERC of the June 19, 2014 order. Among other things, the NETOs assert that the 11.14% is reasonable based on the new methodology. As of June 30, 2014, BGE believes it is probable that BGE's base ROE rate will be subject to the revised methodology and may result in a potential refund to customers of transmission revenue for a maximum fifteen month period. In evaluating FERC's revised methodology, management believes it is reasonably possible no refunds will be required for BGE, and as such, no refund liability has been recorded as of June 30, 2014. If FERC were to order a reduction of BGE's base return on equity to 8.7% as sought in the complaint (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the result would be a refund to customers of approximately $13 million, as well as an estimated ongoing annual reduction in revenues of approximately $10 million.

PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM's current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, that court issued its decision affirming FERC's order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above. On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order. On March 22, 2013, FERC issued an order denying rehearing and made it clear that the cost allocation at issue concerns only projects approved prior to February 1, 2013. A number of entities have filed appeals of the FERC orders. On June 25, 2014, the U.S. Court of Appeals for the Seventh Circuit issued a decision once again remanding to FERC the cost allocation of new facilities 500 kV and above. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd's results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO's 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO's results of operations, cash flows or financial position. To the extent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO's results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE's results of operations, cash flows or financial position.

PJM Minimum Offer Price Rule (Exelon and Generation). PJM's capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014.

Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM.

Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE). On May 23, 2014, the D.C. Circuit Court issued an opinion vacating the FERC Order No. 745 (“D.C. Circuit Decision”). Order No. 745 established uniform compensation levels for demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective.

In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained that demand response is part of the retail market and FERC is restricted from regulating retail markets. The full implication of the D.C. Circuit Decision for both energy and capacity markets regulated by FERC is not yet known and will depend on how FERC and the RTOs and ISOs implement the decision. In addition, on July 7, 2014, FERC and several other parties sought rehearing of the D.C. Circuit Decision. Therefore, FERC will not be required to implement the D.C. Circuit Decision until at the earliest a determination is made on the rehearing request. If rehearing is denied, FERC or other parties will have an opportunity to appeal the decision to the United States Supreme Court. The final outcome of this litigation is therefore not expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material to Exelon, Generation, ComEd, PECO and BGE's results of operations and cash flows.

Reliability Pricing Model (Exelon, Generation and BGE). PJM's RPM Base Residual Auctions take place approximately 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2018 occurred in May 2014.

FERC Deficiency Letter Related to New England Capacity Market Results (Exelon and Generation). Each year, ISO New England, Inc. (ISO-NE) files the results of its annual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction. Consistent with this requirement, on February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 30, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE's February 28, 2014 filing is deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE has 30 days to file the information and then FERC will determine how to proceed. Exelon cannot predict when the FERC will accept the capacity auction results for filing or what further action FERC may take concerning the results of that auction, but any FERC action could be material to Exelon's expected revenues from the capacity auction.

License Renewals (Exelon and Generation). On June 22, 2011, Generation submitted applications to the NRC to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The current operating licenses for Limerick Units 1 and 2 expire in 2024 and 2029, respectively. In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC's temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court's decision is addressed. In September 2012, the NRC directed NRC Staff to revise the temporary storage rule which is now not expected until October 3, 2014. Generation does not expect the NRC to issue license renewals until the end of 2014, at the earliest.

On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 at the earliest.

On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility Project (Muddy Run), respectively.

Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Exelon filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. Resolution of these issues relating to Conowingo may have a material effect on Generation's results of operations and financial position through an increase in capital expenditures and operating costs.

On June 3, 2014, PA DEP issued its water quality certificate for Muddy Run, which is a necessary step in the FERC licensing process and included certain commitments made by Generation. On July 3, 2014, PPL Holtwood, LLC, the owner of the next upstream dam from Muddy Run, filed an appeal of PA DEP's issuance of its water quality certificate. The financial impact associated with these commitments is estimated to be in the range of $25 million to $35 million, and will include both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects.

Based on the latest FERC procedural schedule, the FERC licensing process is not expected to be completed prior to the expiration of Muddy Run's current license on August 31, 2014, and the expiration of Conowingo's license on September 1, 2014. However, the stations would continue to operate under annual licenses until FERC takes action on the 46-year license applications. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of June 30, 2014, $36 million of direct costs associated with licensing efforts have been capitalized.

Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)

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

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of June 30, 2014 and December 31, 2013. For additional information on the specific regulatory assets and liabilities, refer to Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K.

June 30, 2014		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent
Pension and other postretirement
	benefits	$	208	$	2,510	$	0	$	0	$	0	$	0	$	0		$	0
Deferred income taxes			13		1,495		1		68		0		1,358		12			69
AMI programs			7		222		7		56		0		72		0			94
Under-recovered distribution service
	costs		219		220		219		220		0		0		0			0
Debt costs			10		51		8		49		2		2		1			8
Fair value of BGE long-term debt ^(a)			7		198		0		0		0		0		0			0
Fair value of BGE supply contract^(b)			6		0		0		0		0		0		0			0
Severance			4		11		0		0		0		0		4			11
Asset retirement obligations			1		110		1		73		0		26		0			11
MGP remediation costs			40		196		33		165		6		30		1			1
RTO start-up costs			1		0		1		0		0		0		0			0
Under-recovered uncollectible
	accounts		0		70		0		70		0		0		0			0
Renewable energy			13		121		13		121		0		0		0			0
Energy and transmission programs			17		4		12		0		0		0		5	^(f)		4
Deferred storm costs			3		1		0		0		0		0		3			1
Electric generation-related
	regulatory asset		13		24		0		0		0		0		13			24
Rate stabilization deferral			73		119		0		0		0		0		73			119
Energy efficiency and demand
	response programs		63		148		0		0		0		0		63			148
Merger integration costs			2		7		0		0		0		0		2			7
Conservation voltage reduction			0		1		0		0		0		0		0			1
Other			32		37		9		28		21		7		1			1

Total regulatory assets		$	732	$	5,545	$	304	$	850	$	29	$	1,495	$	178		$	499

June 30, 2014		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Other postretirement benefits		$	53	$	111	$	0	$	0	$	0		$	0	$	0		$	0
Nuclear decommissioning			0		2,917		0		2,427		0			490		0			0
Removal costs			107		1,449		83		1,248		0			0		24			201
Energy efficiency and demand
	response programs		14		2		14		0		0			2		0			0
DLC Program Costs			1		9		0		0		1			9		0			0
Energy efficiency Phase 2			0		32		0		0		0			32		0			0
Electric distribution tax repairs			20		104		0		0		20			104		0			0
Gas distribution tax repairs			8		34		0		0		8			34		0			0
Energy and transmission programs			89		11		19		11		52	^(c)		0		18	^(f)		0
Over-recovered gas and electric
	universal service fund costs		5		0		0		0		5			0		0			0
Revenue subject to refund ^(d)			47		0		47		0		0			0		0			0
Over-recovered gas and electric
	revenue decoupling^(e)		21		0		0		0		0			0		21			0
Other			3		1		1		0		2			0		0			1

Total regulatory liabilities		$	368	$	4,670	$	164	$	3,686	$	88		$	671	$	63		$	202

December 31, 2013		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent
Pension and other postretirement
	benefits	$	221	$	2,794	$	0	$	0	$	0	$	0	$	0		$	0
Deferred income taxes			10		1,459		2		65		0		1,317		8			77
AMI programs			5		159		5		35		0		58		0			66
AMI meter events			0		5		0		0		0		5		0			0
Under-recovered distribution service
	costs		178		285		178		285		0		0		0			0
Debt costs			12		56		9		53		3		3		1			8
Fair value of BGE long-term debt^(a)			0		219		0		0		0		0		0			0
Fair value of BGE supply contract ^(b)			12		0		0		0		0		0		0			0
Severance			16		12		12		0		0		0		4			12
Asset retirement obligations			1		102		1		67		0		25		0			10
MGP remediation costs			40		212		33		178		6		33		1			1
RTO start-up costs			2		0		2		0		0		0		0			0
Under-recovered uncollectible
	accounts		0		48		0		48		0		0		0			0
Renewable energy			17		176		17		176		0		0		0			0
Energy and transmission programs			53		0		52		0		0		0		1	(f)		0
Deferred storm costs			3		3		0		0		0		0		3			3
Electric generation-related
	regulatory asset		13		30		0		0		0		0		13			30
Rate stabilization deferral			71		154		0		0		0		0		71			154
Energy efficiency and demand
	response programs		73		148		0		0		0		0		73			148
Merger integration costs			2		9		0		0		0		0		2			9
Other			31		39		18		26		8		7		4			6

Total regulatory assets		$	760	$	5,910	$	329	$	933	$	17	$	1,448	$	181		$	524

December 31, 2013		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Other postretirement benefits		$	2	$	43	$	0	$	0	$	0		$	0	$	0		$	0
Nuclear decommissioning			0		2,740		0		2,293		0			447		0			0
Removal costs			99		1,423		78		1,219		0			0		21			204
Energy efficiency and demand
	response programs		53		0		45		0		8			0		0			0
DLC Program Costs			1		10		0		0		1			10		0			0
Energy efficiency phase II			0		21		0		0		0			21		0			0
Electric distribution tax repairs			20		114		0		0		20			114		0			0
Gas distribution tax repairs			8		37		0		0		8			37
Energy and transmission programs			78		0		9		0		58	^(c)		0		11	^(f)		0
Over-recovered gas and electric
	universal service fund costs		8		0		0		0		8			0		0			0
Revenue subject to refund ^(d)			38		0		38		0		0			0		0			0
Over-recovered electric and gas
	revenue decoupling^(e)		16		0		0		0		0			0		16			0
Other			4		0		0		0		3			0		0			0

Total regulatory liabilities		$	327	$	4,388	$	170	$	3,512	$	106		$	629	$	48		$	204

Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt. See Note 10 – Debt and Credit Agreements for additional information.
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.
Includes $26 million related to the DSP program, $19 million related to the over-recovered natural gas costs under the PGC and $7 million related to over-recovered electric transmission costs as of June 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.
Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC's order in the 2007 Rate Case. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for further information.
Represents the electric and gas distribution costs recoverable from customers under BGE's decoupling mechanism. As of June 30, 2014, BGE had a regulatory liability of $3 million related to over-recovered electric revenue decoupling and $18 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling.
Relates to $1 million of under-recovered electric supply costs, $4 million associated with the transmission formula rate and $18 million of over-recovered natural gas supply costs as of June 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs, $0 million associated with the transmission formula rate and $11 million of over-recovered natural gas supply costs.

Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE)

ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities' consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO and BGE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon's, ComEd's, PECO's and BGE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of June 30, 2014 and December 31, 2013.

As of June 30, 2014	Exelon		ComEd		PECO		BGE
Purchased receivables^(a)	$	270	$	116	$	75	$	79
Allowance for uncollectible accounts ^(b)		(32)		(17)		(8)		(7)
Purchased receivables, net	$	238	$	99	$	67	$	72

As of December 31, 2013	Exelon		ComEd		PECO		BGE
Purchased receivables^(a)	$	263	$	105	$	72	$	86
Allowance for uncollectible accounts ^(b)		(30)		(16)		(7)		(7)
Purchased receivables, net	$	233	$	89	$	65	$	79

__________

(a) PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.

(b) For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

^[1]

[1]	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC’s order in the 2007 Rate Case. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for further information.

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

6 Months Ended

Jun. 30, 2014

Equity Method Investments and Joint Ventures [Line Items]

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

6. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements, see Note 25 – Related Party Transactions of the Exelon 2013 Form 10-K.

On April 1, 2014, Generation and subsidiaries of Generation, EDF, EDF, Inc. (EDFI) (a subsidiary of EDF) and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI's rights as a member of CENG (the Integration Transaction). CENG will reimburse Generation for its direct and allocated costs for such services. As part of the arrangement, Nine Mile Point Nuclear Station, LLC, a subsidiary of CENG, also assigned to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with the co-owner. In addition, on April 1, 2014, the Power Services Agency Agreement (PSAA) was amended and extended until the permanent cessation of power generation by the CENG generation plants.

In addition, on April 1, 2014, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and, in any event, payable upon the settlement of the Put Option Agreement discussed below (if the put option is exercised) or payable upon the maturity date of April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDFI.

The parties also executed a Fourth Amended and Restated Operating Agreement for CENG on April 1, 2014, pursuant to which, among other things, CENG committed to make preferred distributions to Generation (after repayment of the $400 million loan and associated interest) quarterly out of specified available cash flows until Generation has received aggregate distributions of $400 million plus a return of 8.5% per annum from April 1, 2014 (Preferred Distribution Rights).

Generation and EDFI also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDFI has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF's 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation's rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation's rights to other distributions. The beginning of the exercise period will be accelerated if Exelon's affiliates cease to own a majority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months.

On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified 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.

In addition, on April 1, 2014, Generation, EDFI, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to Generation or one of its affiliates (the Generation Parties) and the assumption of the employee benefit plans and their related trusts by Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the underfunded balance of the pension and other postretirement welfare benefit plans measured as of July 14, 2014 by making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF's disposition of a majority of its interest in CENG.

As a condition to obtaining regulatory approval for the NOSA and related transactions from the NRC, Exelon executed a support agreement pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to CENG (Exelon Support Agreement). The Exelon Support Agreement supersedes a previous support agreement under which Generation had agreed to provide up to $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified circumstances to provide up to $165 million in additional financial support for CENG. A previous support agreement executed by an affiliate of EDF remains in effect under which the EDF affiliate may be required to provide up to approximately $145 million of financial support for CENG under specified circumstances. The agreements were executed on April 1, 2014 when the NRC licenses were transferred to Generation. No liability has been recognized by Exelon for the guarantees.

Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in losses of unconsolidated affiliates related to its investment in CENG and recorded $17 million of revenues from CENG. For the three and six months ended June 30, 2013, Generation recorded $19 million and $31 million, respectively, of equity in losses of unconsolidated affiliates related to its investment in CENG and $23 million and $34 million, respectively, of revenues from CENG. The book value of Generation's investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million.

As a result of the consolidation of CENG, there are several transactions included in Exelon's and Generation's Consolidated Financial Statements between CENG and EDF that are considered related party transactions to Generation. As further described in Note 25 – Related Party Transactions of the Exelon 2013 Form 10-K, EDF and Generation have a PPA with CENG under which they purchase 15% and 85%, respectively, of the nuclear output owned by CENG that is not sold to third parties under pre-existing PPAs. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. Sales to EDF of $38 million are included within Exelon's and Generation's Consolidated Statements of Operations for the three and six months ended June 30, 2014. See discussion above and Note 3 – Variable Interest Entities for additional information regarding other related party transactions, between CENG and EDF included within Exelon and Generation's financial statements.

See Note 3 – Variable Interest Entities for additional information about the Registrants VIEs.

Accounting for the Consolidation of CENG

The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF's non-controlling interest in CENG at fair value on Exelon's and Generation's Consolidated Balance Sheets. As a result of the consolidation, Exelon and Generation recorded a net gain of $261 million within their respective Consolidated Statements of Operations and Comprehensive Income. This gain consists of approximately $136 million related to the step up to fair value basis of our ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactions between CENG and Generation. The net gain on the consolidation of CENG of $261 million is net of a $7 million payment to EDF.

The fair value of CENG's assets and liabilities recorded in consolidation was 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 market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed.

The valuations necessary to assess the fair values of certain assets and liabilities are considered preliminary as a result of the short time period between the execution of the NOSA and the end of the second quarter of 2014. The estimates of the fair value of assets and liabilities may be modified up to one year from April 1, 2014, as more information is obtained about the fair value of assets and liabilities. The principal items that are expected to be revised include the asset retirement obligation liabilities and related asset retirement costs. These items are expected to be updated with inputs from a third party engineering firm with corresponding adjustments recorded by the end of 2014. In the period of such revisions, these and any other material changes to the fair value assessments could result in adjustments to the amounts recorded upon consolidation, including the overall gain recorded by Generation. In addition, any asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation date would impact Generation's post-consolidation results of operations.

Generation recorded the assets and liabilities of CENG at fair value as of April 1, 2014. The following assets and liabilities of CENG were recorded within Generation's Consolidated Balance Sheets as of the date of integration:

Preliminary Fair Values	Exelon and Generation
Current assets	$	499
Nuclear decommissioning trust fund		1,955
Property, plant and equipment		2,958
Nuclear fuel		482
Other assets		10
Total assets		5,904

Current liabilities		237
Asset retirement obligation		1,701
Pension and other employee benefit obligations		281
Unamortized energy contract liabilities		171
Other liabilities		114
Total liabilities		2,504
Total net assets	$	3,400

Preliminary Fair Values	Exelon and Generation
Current assets	$	499
Nuclear decommissioning trust fund		1,955
Property, plant and equipment		2,958
Nuclear fuel		482
Other assets		10
Total assets		5,904

Current liabilities		237
Asset retirement obligation		1,701
Pension and other employee benefit obligations		281
Unamortized energy contract liabilities		171
Other liabilities		114
Total liabilities		2,504
Total net assets	$	3,400

	Three Months			Three Months
	Ended March 31,			Ended March 31,
	2014		2013
Equity investment income	$	(2)	$	15
Amortization of basis difference in CENG		(17)		(27)
Total equity in earnings - CENG	$	(19)	$	(12)

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

Equity Method Investments and Joint Ventures [Line Items]

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

6. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

See Note 3 – Variable Interest Entities for additional information about the Registrants VIEs.

Accounting for the Consolidation of CENG

	Three Months			Three Months
	Ended March 31,			Ended March 31,
	2014		2013
Equity investment income	$	(2)	$	15
Amortization of basis difference in CENG		(17)		(27)
Total equity in earnings - CENG	$	(19)	$	(12)

Impairment of Long-lived Assets (Exelon and Generation)

6 Months Ended

Jun. 30, 2014

Impaired Long-Lived Assets Held and Used [Line Items]

Impairment Of Long Lived Assets Held [Text Block]

7. Impairment of Long-Lived Assets (Exelon and Generation)

Long-Lived Assets (Exelon and Generation)

Generation evaluates 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 2014, updates to the long-term fundamental energy prices, which included a thorough evaluation of key assumptions including gas prices, load growth, plant retirements and renewable growth, suggested that the carrying value of certain merchant wind assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014. The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 million was recorded during the second quarter in Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. Changes in the assumptions described above could potentially result in future impairments of Exelon's long-lived assets, which could be material.

Nuclear Uprate Program (Exelon and Generation)

Generation is engaged in individual projects as part of a planned power uprate program across its nuclear fleet. When economically viable, the projects take advantage of new production and measurement technologies, new materials and application of expertise gained from a half-century of nuclear power operations. Based on ongoing reviews, the nuclear uprate implementation plan was adjusted in both the first and second quarters of 2013 to cancel certain projects. During the first quarter of 2013, the Measurement Uncertainty Recapture (MUR) uprate projects at the Dresden and Quad Cities nuclear stations were cancelled as a result of the cost of additional plant modifications identified during final design work which, when combined with then current market conditions, made the projects not economically viable. For these cancelled projects, Generation recorded approximately $21 million to Operating and maintenance expense during the first quarter of 2013 to accrue remaining costs and reverse previously capitalized costs. During the second quarter of 2013, market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. For these cancelled projects, Generation recorded a pre-tax charge during the second quarter of 2013 to Operating and maintenance expense and Interest expense of approximately $92 million and $8 million, respectively, to accrue remaining costs and reverse the previously capitalized costs.

Like-Kind Exchange Transaction (Exelon)

Prior to the PECO/Unicom Merger in October 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon, entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in coal-fired generating station leases located in Georgia and Texas with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. See Note 11 – Income Taxes for further information. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the power itself or require the lessees to arrange for a third-party to bid on a service contract for a period following the lease term. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon's exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In the fourth quarter of 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases.

On February 26, 2014, UII and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases on the generating station located in Texas, as described above, prior to its expiration dates. As a result of the lease termination, UII received a net early termination amount of $335 million from CPS and wrote off the net investment in the CPS long-term lease of $336 million in Investments in the Consolidated Balance Sheet in the first quarter of 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income in the first quarter of 2014.

Pursuant to the applicable accounting 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 under the income approach, which uses a discounted cash flow analysis, which takes 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.

Based on the annual reviews performed in the second quarter 2014 and 2013, the estimated residual value of Exelon's direct financing leases for the Georgia generating stations experienced other than temporary declines given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $24 million and $14 million pre-tax impairment charge in the second quarter of 2014 and 2013, respectively, for these stations. These impairment charges were recorded in Investments and Operating and maintenance expense in Exelon's Consolidated Balance Sheet and the Consolidated Statement of Operations and Comprehensive Income, respectively. Changes in the assumptions described above could potentially result in future impairments of Exelon's direct financing lease investments, which could be material.

At June 30, 2014 and December 31, 2013, the components of the net investment in long-term leases were as follows:

	June 30, 2014		December 31, 2013
Estimated residual value of leased assets	$	685	$	1,465
Less: unearned income		332		767
Net investment in long-term leases	$	353	$	698

Impaired Long-Lived Assets Held and Used [Line Items]

Impairment Of Long Lived Assets Held [Text Block]

7. Impairment of Long-Lived Assets (Exelon and Generation)

Long-Lived Assets (Exelon and Generation)

Nuclear Uprate Program (Exelon and Generation)

Like-Kind Exchange Transaction (Exelon)

At June 30, 2014 and December 31, 2013, the components of the net investment in long-term leases were as follows:

Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Fair Value of Financial Assets and Liabilities [Line items]

Fair Value Disclosures [Text Block]

8. Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)

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 June 30, 2014 and December 31, 2013:

Exelon

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	624	$	3	$	621	$	0	$	624
Long-term debt (including amounts due within one year)		20,180		1,150		19,373		1,135		21,658
Long-term debt to financing trusts		648		0		0		668		668
SNF obligation		1,021		0		814		0		814

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	344	$	3	$	341	$	0	$	344
Long-term debt (including amounts due within one year)		19,132		0		18,672		1,079		19,751
Long-term debt to financing trusts		648		0		0		631		631
SNF obligation		1,021		0		790		0		790

Generation

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	53	$	0	$	53	$	0	$	53
Long-term debt (including amounts due within one year)		7,507		0		6,881		1,135		8,016
SNF obligation		1,021		0		814		0		814

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	22	$	0	$	22	$	0	$	22
Long-term debt (including amounts due within one year)		7,729		0		6,586		1,062		7,648
SNF obligation		1,021		0		790		0		790

ComEd

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	498	$	0	$	498	$	0	$	498
Long-term debt (including amounts due within one year)		5,708		0		6,452		0		6,452
Long-term debt to financing trust		206		0		0		211		211

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	184	$	0	$	184	$	0	$	184
Long-term debt (including amounts due within one year)		5,675		0		6,238		17		6,255
Long-term debt to financing trust		206		0		0		202		202

PECO

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)	$	2,197	$	0	$	2,436	$	0	$	2,436
Long-term debt to financing trusts		184		0		0		198		198

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)	$	2,197	$	0	$	2,358	$	0	$	2,358
Long-term debt to financing trusts		184		0		0		180		180

BGE

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1			Level 2	Level 3		Total
Short-term liabilities	$	73	$	3	$	70	$	0	$	73
Long-term debt (including amounts due within one year)		1,976		0		2,206		0		2,206
Long-term debt to financing trusts		258		0		0		259		259

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1			Level 2	Level 3		Total
Short-term liabilities	$	138	$	3	$	135	$	0	$	138
Long-term debt (including amounts due within one year)		2,011		0		2,148		0		2,148
Long-term debt to financing trusts		258		0		0		249		249

Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (Level 2) and dividends payable (included in other current liabilities) (Level 1). 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) 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 electric 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.

The fair value of Generation's non-government-backed fixed rate project financing debt (Level 3) is based on market and quoted prices for its own and other project financing debt with similar risk profiles. Given the low trading volume in the project financing 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 project financing debt resets on a quarterly 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 estimated to be settled in 2025 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 2025.

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 access as of the reporting date. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded corporate units, equity securities and funds, certain exchange-based derivatives, and money market funds.
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. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, derivatives, commingled and mutual investment funds priced at NAV per fund share and fair value hedges.
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. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded securities and derivatives, and investments priced using an alternative pricing mechanism or third party valuation.

Transfers in and out of levels are recognized as of the end of the reporting period the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts. There were no transfers between Level 1 and Level 2 during the six months ended June 30, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.

Exelon

The following tables present assets and liabilities measured and recorded at fair value on Exelon's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2014 and December 31, 2013:

As of June 30, 2014	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	1,034	$	0	$	0	$	1,034
Nuclear decommissioning trust fund investments
Cash equivalents		151		66		0		217
Equity
Individually held		2,572		0		0		2,572
Exchange traded funds		164		0		0		164
Commingled funds		0		2,529		0		2,529
Equity funds subtotal		2,736		2,529		0		5,265
Balanced funds - commingled funds		0		273		0		273
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		990		0		0		990
Debt securities issued by states of the United States
and political subdivisions of the states		0		416		0		416
Debt securities issued by foreign governments		0		114		0		114
Corporate debt securities		0		2,059		181		2,240
Federal agency mortgage-backed securities		0		84		0		84
Commercial mortgage-backed securities (non-agency)		0		43		0		43
Residential mortgage-backed securities (non-agency)		0		3		0		3
Mutual funds		0		18		0		18
Commingled funds		0		325		0		325
Fixed income subtotal		990		3,062		181		4,233
Middle market lending		0		0		376		376
Private Equity		0		0		35		35
Other debt obligations		0		24		0		24
Nuclear decommissioning trust fund investments subtotal^(b)		3,877		5,954		592		10,423

Pledged assets for Zion Station decommissioning
Cash equivalents		0		45		0		45
Equity
Individually held		4		2		0		6
Equity funds subtotal		4		2		0		6
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		12		3		0		15
Debt securities issued by states of the United States
and political subdivisions of the states		0		19		0		19
Corporate debt securities		0		172		0		172
Commingled funds		0		5		0		5
Fixed income subtotal		12		199		0		211
Middle market lending		0		0		133		133
Pledged assets for Zion Station decommissioning subtotal^(c)		16		246		133		395

Rabbi trust investments^(e)
Cash equivalents		2		0		0		2
Mutual funds^(d)		43		0		0		43
Rabbi trust investments subtotal		45		0		0		45

Commodity derivative assets
Economic hedges		434		2,969		1,413		4,816
Proprietary trading		178		712		184		1,074
Effect of netting and allocation of collateral^(f)		(569)		(3,119)		(1,127)		(4,815)
Commodity derivative assets subtotal		43		562		470		1,075

Interest rate and foreign currency derivative assets		24		40		0		64
Effect of netting and allocation of collateral		(21)		(7)		0		(28)
Interest rate and foreign currency derivative assets subtotal		3		33		0		36

Other investments		13		0		10		23

Total assets		5,031		6,795		1,205		13,031

Liabilities
Commodity derivative liabilities
Economic hedges		(434)		(2,803)		(1,465)		(4,702)
Proprietary trading		(182)		(707)		(176)		(1,065)
Effect of netting and allocation of collateral^(f)		618		3,408		1,279		5,305
Commodity derivative liabilities subtotal		2		(102)		(362)		(462)

Interest rate and foreign currency derivative liabilities		(24)		(34)		0		(58)
Effect of netting and allocation of collateral		24		6		0		30
Interest rate and foreign currency derivative liabilities subtotal		0		(28)		0		(28)

Deferred compensation obligation		0		(104)		0		(104)

Total liabilities		2		(234)		(362)		(594)

Total net assets	$	5,033	$	6,561	$	843	$	12,437

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	1,230	$	0	$	0	$	1,230
Nuclear decommissioning trust fund investments
Cash equivalents		459		0		0		459
Equity
Individually held		1,776		0		0		1,776
Exchange traded funds		115		0		0		115
Commingled funds		0		2,271		0		2,271
Equity funds subtotal		1,891		2,271		0		4,162
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		882		0		0		882
Debt securities issued by states of the United States
and political subdivisions of the states		0		294		0		294
Debt securities issued by foreign governments		0		87		0		87
Corporate debt securities		0		1,753		31		1,784
Federal agency mortgage-backed securities		0		10		0		10
Commercial mortgage-backed securities (non-agency)		0		40		0		40
Residential mortgage-backed securities (non-agency)		0		7		0		7
Mutual funds		0		18		0		18
Fixed income subtotal		882		2,209		31		3,122
Middle market lending		0		0		314		314
Private Equity		0		0		5		5
Other debt obligations		0		14		0		14
Nuclear decommissioning trust fund investments subtotal^(b)		3,232		4,494		350		8,076

Pledged assets for Zion decommissioning
Cash equivalents		0		26		0		26
Equity
Individually held		16		0		0		16
Equity funds subtotal		16		0		0		16
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		45		4		0		49
Debt securities issued by states of the United States
and political subdivisions of the states		0		20		0		20
Corporate debt securities		0		227		0		227
Fixed income subtotal		45		251		0		296
Middle market lending		0		0		112		112
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal^(c)		61		278		112		451

Rabbi trust investments^(e)
Cash equivalents		2		0		0		2
Mutual funds^(d)		54		0		0		54
Rabbi trust investments subtotal		56		0		0		56

Commodity derivative assets
Economic hedges		493		2,582		885		3,960
Proprietary trading		324		1,315		122		1,761
Effect of netting and allocation of collateral^(f)		(863)		(3,131)		(430)		(4,424)
Commodity derivative assets subtotal		(46)		766		577		1,297

Interest rate and foreign currency derivative assets		30		39		0		69
Effect of netting and allocation of collateral		(30)		(2)		0		(32)
Interest rate and foreign currency derivative assets subtotal		0		37		0		37

Other Investments		0		0		15		15
Total assets		4,533		5,575		1,054		11,162

Liabilities
Commodity derivative liabilities
Economic hedges		(540)		(1,890)		(590)		(3,020)
Proprietary trading		(328)		(1,256)		(119)		(1,703)
Effect of netting and allocation of collateral^(f)		869		3,007		404		4,280
Commodity derivative liabilities subtotal		1		(139)		(305)		(443)

Interest rate and foreign currency derivative liabilities		(31)		(17)		0		(48)
Effect of netting and allocation of collateral		31		1		0		32
Interest rate and foreign currency derivative liabilities subtotal		0		(16)		0		(16)

Deferred compensation obligation		0		(114)		0		(114)

Total liabilities		1		(269)		(305)		(573)

Total net assets	$	4,534	$	5,306	$	749	$	10,589

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(b) Excludes net assets (liabilities) of $14 million and $(5) million at June 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(c) Excludes net assets of $7 million at both June 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d) The mutual funds held by the Rabbi trusts include $42 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at June 30, 2014, and $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013.

(e) Excludes $34 million and $32 million of the cash surrender value of life insurance investments at June 30, 2014 and December 31, 2013, respectively.

(f) Includes collateral postings to counterparties. Collateral posted to counterparties, net of collateral paid to counterparties, totaled $49 million, $289 million and $152 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2014 and 2013:

Three Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2014		$	486	$	137	$	119		$	10	$	752
Total realized / unrealized gains (losses)
	Included in net income		2		0		(48)	^(a)		0		(46)
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		8		0		34			0		42
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral			0		0		34			0		34
Purchases, sales, issuances and settlements
	Purchases		109		13		5			0		127
	Sales		(1)		(21)		(4)			0		(26)
	Settlements		(12)		0		0			0		(12)
Transfers into Level 3			0		0		(4)			0		(4)
Transfers out of Level 3			0		0		(28)			0		(28)

Balance as of June 30, 2014		$	592	$	133	$	108		$	10	$	843
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2014	$	2	$	0	$	19		$	0	$	21

Six Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2013		$	350	$	112	$	272		$	15	$	749
Total realized / unrealized gains (losses)
	Included in net income		3		0		(360)	^(a)		0		(357)
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		11		0		59			0		70
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral			0		0		178			0		178
Purchases, sales, issuances and settlements
	Purchases		249		42		15			2		308
	Sales		(2)		(25)		(6)			0		(33)
	Settlements		(19)		0		0			0		(19)
Transfers into Level 3			0		0		(30)			0		(30)
Transfers out of Level 3			0		0		(20)			(7)		(27)

Balance as of June 30, 2014		$	592	$	133	$	108		$	10	$	843
The amount of total losses included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended June 30, 2014	$	2	$	0	$	(427)		$	0	$	(425)

(a) Includes the increase for the reclassification of $67 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended June 30, 2014.

Three Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2013		$	210	$	104	$	260		$	9	$	583
Total realized / unrealized gains (losses)
	Included in net income		1		0		158	^(a)		0		159
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		8		0		(10)	^(b)		0		(2)
	Included in payable for Zion Station
	decommissioning		0		1		0			0		1
Change in collateral			0		0		10			0		10
Purchases, sales, issuances and settlements
	Purchases		35		11		13			2		61
	Sales		(11)		(5)		(4)			0		(20)
	Settlements		(3)		0		0			0		(3)
Transfers into Level 3			0		0		3			0		3
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	431		$	11	$	793
The amount of total losses included in income
	attributed to the change in unrealized losses related to assets and liabilities held for the three months ended June 30, 2013	$	1	$	0	$	187		$	0	$	188

Six Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2012		$	183	$	89	$	367		$	17	$	656
Total realized / unrealized gains (losses)
	Included in net income		2		0		31	^(a)		0		33
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		9		0		(18)	^(b)		0		(9)
	Included in payable for Zion Station
	decommissioning		0		1		0			0		1
Change in collateral			0		0		43			0		43
Purchases, sales, issuances and settlements
	Purchases		67		33		8	^(c)		2		110
	Sales		(13)		(12)		(8)			(8)		(41)
	Settlements		(8)		0		0			0		(8)
Transfers into Level 3			0		0		7			0		7
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	431		$	11	$	793
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2013	$	1	$	0	$	108		$	0	$	109

(a) Includes the reclassification of $29 million and $77 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2013, respectively.

(b) Excludes decreases in fair value of $3 million and $11 million and realized losses reclassified due to settlements of $82 million and $215 million associated with Generation's financial swap contract with ComEd for the three and six months ended June 30, 2013. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.

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 six months ended June 30, 2014 and 2013:


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

Total gains (losses) included in income for the three months ended
	June 30, 2014	$	(62)	$	14	$	2
Total gains (losses) included in income for the six months ended
	June 30, 2014	$	(330)	$	(30)	$	3
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended June 30, 2014	$	(10)	$	29	$	2
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the six months ended June 30, 2014	$	(435)	$	8	$	2

		Operating Revenue		Purchased Power and Fuel		Other, net^(a)
Total gains included in income for the three months
	ended June 30, 2013	$	137	$	21	$	1
Total gains (losses) included in income for the six months ended
	June 30, 2013	$	(22)	$	53	$	2
Change in the unrealized gains relating to assets and
	liabilities held for the three months ended June 30, 2013	$	156	$	31	$	1
Change in the unrealized gains relating to assets and
	liabilities held for the six months ended June 30, 2013	$	39	$	69	$	1

(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

Generation

The following tables present assets and liabilities measured and recorded at fair value on Generation's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2014 and December 31, 2013:

As of June 30, 2014	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	65	$	0	$	0	$	65
Nuclear decommissioning trust fund investments
Cash equivalents		151		66		0		217
Equity
Individually held		2,572		0		0		2,572
Exchange traded funds		164		0		0		164
Commingled funds		0		2,529		0		2,529
Equity funds subtotal		2,736		2,529		0		5,265
Balanced funds - commingled funds		0		273		0		273
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		990		0		0		990
Debt securities issued by states of the United States and
political subdivisions of the states		0		416		0		416
Debt securities issued by foreign governments		0		114		0		114
Corporate debt securities		0		2,059		181		2,240
Federal agency mortgage-backed securities		0		84		0		84
Commercial mortgage-backed securities (non-agency)		0		43		0		43
Residential mortgage-backed securities (non-agency)		0		3		0		3
Mutual funds		0		18		0		18
Commingled funds		0		325		0		325
Fixed income subtotal		990		3,062		181		4,233
Middle market lending		0		0		376		376
Private Equity		0		0		35		35
Other debt obligations		0		24		0		24
Nuclear decommissioning trust fund investments subtotal^(b)		3,877		5,954		592		10,423

Pledged assets for Zion Station decommissioning
Cash equivalents		0		45		0		45
Equity
Individually held		4		2		0		6
Equity funds subtotal		4		2		0		6
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		12		3		0		15
Debt securities issued by states of the United States and
political subdivisions of the states		0		19		0		19
Corporate debt securities		0		172		0		172
Commingled funds		0		5		0		5
Fixed income subtotal		12		199		0		211
Middle market lending		0		0		133		133
Pledged assets for Zion Station decommissioning subtotal^(c)		16		246		133		395

Rabbi trust investments^(d)
Cash equivalents		1		0		0		1
Mutual funds		14		0		0		14
Rabbi trust investments subtotal		15		0		0		15

Commodity derivative assets
Economic hedges		434		2,969		1,413		4,816
Proprietary trading		178		712		184		1,074
Effect of netting and allocation of collateral^(e)		(569)		(3,119)		(1,127)		(4,815)
Commodity derivative assets subtotal		43		562		470		1,075

Interest rate and foreign currency derivative assets		24		22		0		46
Effect of netting and allocation of collateral		(21)		(7)		0		(28)
Interest rate and foreign currency derivative assets subtotal		3		15		0		18

Other investments		13		0		10		23

Total assets		4,032		6,777		1,205		12,014

Liabilities
Commodity derivative liabilities
Economic hedges		(434)		(2,803)		(1,331)		(4,568)
Proprietary trading		(182)		(707)		(176)		(1,065)
Effect of netting and allocation of collateral^(e)		618		3,408		1,279		5,305
Commodity derivative liabilities subtotal		2		(102)		(228)		(328)

Interest rate and foreign currency derivative liabilities		(24)		(28)		0		(52)
Effect of netting and allocation of collateral		24		6		0		30
Interest rate and foreign currency derivative liabilities subtotal		0		(22)		0		(22)

Deferred compensation obligation		0		(29)		0		(29)

Total liabilities		2		(153)		(228)		(379)

Total net assets	$	4,034	$	6,624	$	977	$	11,635

As of December 31, 2013	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	1,006	$	0	$	0	$	1,006
Nuclear decommissioning trust fund investments
Cash equivalents		459		0		0		459
Equity
Individually held		1,776		0		0		1,776
Exchange traded funds		115		0		0		115
Commingled funds		0		2,271		0		2,271
Equity funds subtotal		1,891		2,271		0		4,162
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		882		0		0		882
Debt securities issued by states of the United States and
political subdivisions of the states		0		294		0		294
Debt securities issued by foreign governments		0		87		0		87
Corporate debt securities		0		1,753		31		1,784
Federal agency mortgage-backed securities		0		10		0		10
Commercial mortgage-backed securities (non-agency)		0		40		0		40
Residential mortgage-backed securities (non-agency)		0		7		0		7
Mutual funds		0		18		0		18
Fixed income subtotal		882		2,209		31		3,122
Middle market lending		0		0		314		314
Private Equity		0		0		5		5
Other debt obligations		0		14		0		14
Nuclear decommissioning trust fund investments subtotal^(b)		3,232		4,494		350		8,076

Pledged assets for Zion Station decommissioning
Cash equivalents		0		26		0		26
Equity
Individually held		16		0		0		16
Equity funds subtotal		16		0		0		16
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		45		4		0		49
Debt securities issued by states of the United States and
political subdivisions of the states		0		20		0		20
Corporate debt securities		0		227		0		227
Fixed income subtotal		45		251		0		296
Middle market lending		0		0		112		112
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal^(c)		61		278		112		451

Rabbi trust investments^(d)
Mutual funds		13		0		0		13
Rabbi trust investments subtotal		13		0		0		13

Commodity derivative assets
Economic hedges		493		2,582		885		3,960
Proprietary trading		324		1,315		122		1,761
Effect of netting and allocation of collateral^(e)		(863)		(3,131)		(430)		(4,424)
Commodity and foreign currency assets subtotal		(46)		766		577		1,297

Interest rate and foreign currency derivative assets		30		32		0		62
Effect of netting and allocation of collateral		(30)		(2)		0		(32)
Interest rate and foreign currency derivative assets subtotal		0		30		0		30

Other investments		0		0		15		15

Total assets		4,266		5,568		1,054		10,888

Liabilities
Commodity derivative liabilities
Economic hedges		(540)		(1,890)		(397)		(2,827)
Proprietary trading		(328)		(1,256)		(119)		(1,703)
Effect of netting and allocation of collateral^(e)		869		3,007		404		4,280
Commodity derivative liabilities subtotal		1		(139)		(112)		(250)

Interest rate derivative liabilities		(31)		(13)		0		(44)
Effect of netting and allocation of collateral		31		1		0		32
Interest rate and foreign currency derivative liabilities		0		(12)		0		(12)

Deferred compensation obligation		0		(29)		0		(29)

Total liabilities		1		(180)		(112)		(291)

Total net assets	$	4,267	$	5,388	$	942	$	10,597

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(d) Excludes $10 million of the cash surrender value of life insurance investments at both June 30, 2014 and December 31, 2013.

(e) Includes collateral postings to counterparties. Collateral posted to counterparties, net of collateral paid to counterparties, totaled $49 million, $289 million and $152 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2014 and 2013:

Three Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2014		$	486	$	137	$	287		$	10	$	920
Total realized / unrealized gains (losses)
	Included in net income		2		0		(48)	^(a)		0		(46)
	Included in noncurrent payables to affiliates		8		0		0			0		8
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral			0		0		34			0		34
Purchases, sales, issuances and settlements
	Purchases		109		13		5			0		127
	Sales		(1)		(21)		(4)			0		(26)
	Settlements		(12)		0		0			0		(12)
Transfers into Level 3			0		0		(4)			0		(4)
Transfers out of Level 3			0		0		(28)			0		(28)

Balance as of June 30, 2014		$	592	$	133	$	242		$	10	$	977
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2014	$	2	$	0	$	19		$	0	$	21

Six Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2013		$	350	$	112	$	465		$	15	$	942
Total realized / unrealized gains (losses)
	Included in net income		3		0		(360)	^(a)		0		(357)
	Included in noncurrent payables to affiliates		11		0		0			0		11
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral					0		178			0		178
Purchases, sales, issuances and settlements
	Purchases		249		42		15			2		308
	Sales		(2)		(25)		(6)			0		(33)
	Settlements		(19)		0		0			0		(19)
Transfers into Level 3			0		0		(30)			0		(30)
Transfers out of Level 3			0		0		(20)			(7)		(27)

Balance as of June 30, 2014		$	592	$	133	$	242		$	10	$	977
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2014	$	2	$	0	$	(427)		$	0	$	(425)

(a) Includes an increase for the reclassification of $67 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2014, respectively.

Three Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2013		$	210	$	104	$	420		$	9	$	743
Total realized / unrealized gains (losses)
	Included in net income		1		0		168	^(a)(b)		0		169
	Included in other comprehensive income		0		0		(95)	^(b)		0		(95)
	Included in noncurrent payables to affiliates		8		0		0			0		8
	Included in payable for Zion Station decommissioning		0		1		0			0		1
Changes in collateral			0		0		10			0		10
Purchases, sales, issuances and settlements
	Purchases		35		11		13			2		61
	Sales		(11)		(5)		(4)			0		(20)
	Settlements		(3)		0		0			0		(3)
Transfers into Level 3			0		0		3			0		3
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	516		$	11	$	878

The amount of total losses included in income
	attributed to the change in unrealized losses related to assets and liabilities held for the three months ended June 30, 2013	$	1	$	0	$	183		$	0	$	184

Six Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2012		$	183	$	89	$	660		$	17	$	949
Total realized / unrealized gains (losses)
	Included in net income		2		0		24	^(a)(b)		0		26
	Included in other comprehensive income		0		0		(219)	^(b)		0		(219)
	Included in noncurrent payables to affiliates		9		0		0					9
	Included in payable for Zion Station decommissioning		0		1		0			0		1
Changes in collateral			0		0		43			0		43
Purchases, sales, issuances and settlements												0
	Purchases		67		33		8	^(c)		2		110
	Sales		(13)		(12)		(8)			(8)		(41)
	Settlements		(8)		0		0			0		(8)
Transfers into Level 3			0		0		7			0		7
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	516		$	11	$	878

The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2013	$	1	$	0	$	97		$	0	$	98

(a) Includes the reclassification of $15 million and $73 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2013, respectively.

(b) Includes $3 million of decreases in fair value and $11 million of increases in fair value and realized losses due to settlements of $82 million and $215 million associated with Generation's financial swap contract with ComEd for the three and six months ended June 30, 2013, respectively. This position eliminates upon consolidation in Exelon's Consolidated Financial Statements.

		Operating Revenue		Purchased Power and Fuel		Other, net (a)
Total gains (losses) included in net income for the three months		$	(62)	$	14	$	2
	ended June 30, 2014
Total losses included in net income for the six months
	ended June 30, 2014	$	(330)	$	(30)	$	3
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended June 30, 2014	$	(10)	$	29	$	2
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the six months ended June 30, 2014	$	(435)	$	8	$	2

		Operating Revenue		Purchased Power and Fuel		Other, net (a)
Total gains included in net income for the three months		$	148	$	20	$	1
	ended June 30, 2013
Total gains (losses) included in net income for the six months		$	(28)	$	52	$	2
	ended June 30, 2013
Change in the unrealized gains relating to assets and		$	153	$	30	$	1
	liabilities held for the three months ended June 30, 2013
Change in the unrealized gains relating to assets and		$	29	$	68	$	1
	liabilities held for the nine months ended June 30, 2013

(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

ComEd

The following tables present assets and liabilities measured and recorded at fair value on ComEd's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2014 and December 31, 2013:

As of June 30, 2014		Level 1		Level 2		Level 3		Total
Assets
Rabbi trust investments
Mutual funds		$	1	$	0	$	0	$	1
	Rabbi trust investments subtotal		1		0		0		1

Total assets		$	1	$	0	$	0	$	1

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities^(a)			0		0		(134)		(134)

Total liabilities			0		(8)		(134)		(142)

Total net assets (liabilities)		$	1	$	(8)	$	(134)	$	(141)

As of December 31, 2013		Level 1		Level 2		Level 3		Total
Assets
Rabbi trust investments
Mutual funds		$	5	$	0	$	0	$	5
	Rabbi trust investments subtotal		5		0		0		5

Total assets			5		0		0		5

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities^(a)			0		0		(193)		(193)

Total liabilities			0		(8)		(193)		(201)

Total net assets (liabilities)		$	5	$	(8)	$	(193)	$	(196)

(a) The Level 3 balance includes the current and noncurrent liability of $13 million and $121 million at June 30, 2014, respectively, and $17 million and $176 million at December 31, 2013, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2014 and 2013:

Three Months Ended June 30, 2014	Mark-to-Market Derivatives
Balance as of March 31, 2014	$	(168)
Total realized / unrealized gains included in regulatory assets^(a)		34
Balance as of June 30, 2014	$	(134)

Six Months Ended June 30, 2014	Mark-to-Market Derivatives
Balance as of December 31, 2013	$	(193)
Total realized / unrealized gains included in regulatory assets^(b)		59
Balance as of June 30, 2014	$	(134)

Includes $34 million decreases in the fair value partially offset by immaterial realized losses due to settlements recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2014.
Includes $64 million of decreases in the fair value partially offset by realized gains due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2014.

Three Months Ended June 30, 2013	Mark-to-Market Derivatives
Balance as of March 31, 2013	$	(160)
Total realized / unrealized gains included in regulatory assets^(a)(b)		75
Balance as of June 30, 2013	$	(85)

Six Months Ended June 30, 2013	Mark-to-Market Derivatives
Balance as of December 31, 2012	$	(293)
Total realized / unrealized gains included in regulatory assets^(a)(b)		208
Balance as of June 30, 2013	$	(85)

Includes $3 million of increases in fair value and $11 million of decreases in fair value and realized gains due to settlements of $82 million and $215 million of associated with ComEd's financial swap contract with Generation for the three and six months ended June 30, 2013, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
Includes $9 million and $20 million of increases in the fair value and realized losses due to settlements of $1 million and $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and six months ended June 30, 2013, respectively.

PECO

The following tables present assets and liabilities measured and recorded at fair value on PECO's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2014 and December 31, 2013:

As of June 30, 2014	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	50	$	0	$	0	$	50
Rabbi trust investments^(a)
Mutual funds		9		0		0		9
Rabbi trust investments subtotal		9		0		0		9

Total assets		59		0		0		59

Liabilities
Deferred compensation obligation		0		(15)		0		(15)

Total liabilities		0		(15)		0		(15)

Total net assets (liabilities)	$	59	$	(15)	$	0	$	44

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	175	$	0	$	0	$	175
Rabbi trust investments^(a)
Mutual funds		9		0		0		9
Rabbi trust investments subtotal		9		0		0		9

Total assets		184		0		0		184

Liabilities
Deferred compensation obligation		0		(17)		0		(17)

Total liabilities		0		(17)		0		(17)

Total net assets (liabilities)	$	184	$	(17)	$	0	$	167

(a) Excludes $14 million of the cash surrender value of life insurance investments at both June 30, 2014 and December 31, 2013.

PECO had no Level 3 assets or liabilities measured at fair value on a recurring basis during the six months ended June 30, 2014 and 2013.

BGE

The following tables present assets and liabilities measured and recorded at fair value on BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 2014 and December 31, 2013:

As of June 30, 2014		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents		$	53	$	0	$	0	$	53
Rabbi trust investments
	Mutual funds		5		0		0		5
Rabbi trust investments subtotal			5		0		0		5

Total assets			58		0		0		58

Liabilities
Deferred compensation obligation			0		(5)		0		(5)

Total liabilities			0		(5)		0		(5)

Total net assets (liabilities)		$	58	$	(5)	$	0	$	53

As of December 31, 2013		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents		$	31	$	0	$	0	$	31
Rabbi trust investments
	Mutual funds		6		0		0		6
Rabbi trust investments subtotal			6		0		0		6

Total assets			37		0		0		37

Liabilities
Deferred compensation obligation			0		(6)		0		(6)

Total liabilities			0		(6)		0		(6)

Total net assets (liabilities)		$	37	$	(6)	$	0	$	31

BGE had no Level 3 assets or liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 2014 and 2013.

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

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation's and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's and CENG's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies 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 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 are based on quoted prices in active markets and are categorized in Level 1. 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. 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 are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3.

Equity, balanced and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon, Generation and CENG invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. Comingled and mutual funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities. See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.

Middle market lending are investments in loans or managed funds which invest in 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 middle market lending 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. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

As of June 30, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $430 million. These commitments will be funded by Generation's existing nuclear decommissioning trust funds.

Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). 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 investments in the Rabbi trusts are included in investments in the Registrants' Consolidated Balance Sheets and consist primarily of mutual funds. These 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. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices.

Mark-to-Market Derivatives (Exelon, Generation, and ComEd). 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 predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 9 — Derivative Financial Instruments for further discussion on mark-to-market derivatives.

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). 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 notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd)

Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon's RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon's business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. 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, coal purchases, certain transmission congestion contracts, and project financing debt. 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 is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument's market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.57 and $0.41 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. See Item 3. – Quantitative and Qualitative Disclosures About Market Risk for information regarding the maturity by year of the Registrant's mark-to-market derivative assets and liabilities.

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 9 – Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.

Type of trade	Fair Value at June 30, 2014 (c)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) (a)	$	82	Discounted Cash Flow	Forward power price	$	16		-	$	170	(d)
			Discounted Cash Flow	Forward gas price	$	2.19		-	$	19.84	(d)
			Option Model	Volatility percentage		8	%	-		260	%

Mark-to-market derivatives – Proprietary trading (Generation) (a)	$	8	Discounted Cash Flow	Forward power price	$	13		-	$	168	(d)
			Option Model	Volatility percentage		8	%	-		260	%

Mark-to-market derivatives (ComEd)	$	(134)	Discounted Cash Flow	Forward heat rate (b)		8	x	-		9	x
				Marketability reserve		3.5	%	-		8	%
				Renewable factor		86	%	-		123	%

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
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 fair values do not include cash collateral held on level three positions of $152 million as of June 30, 2014.

The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas economic hedges would be approximately $106 and $10.29, respectively, and would be approximately $93 for power proprietary trading.

Type of trade	Fair Value at December 31, 2013^(c)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) ^(a)	$	488	Discounted Cash Flow	Forward power price	$	8		-	$	176	^(d)
			Discounted Cash Flow	Forward gas price	$	2.98		-	$	16.63	^(d)
			Option Model	Volatility percentage		15	%	-		142	%

Mark-to-market derivatives – Proprietary trading (Generation)^(a)	$	3	Discounted Cash Flow	Forward power price	$	10		-	$	176	^(d)
			Option Model	Volatility percentage		14	%	-		19	%

Mark-to-market derivatives (ComEd)	$	(193)	Discounted Cash Flow	Forward heat rate ^(b)		8	x	-		9	x
				Marketability reserve		3.5	%	-		8	%
				Renewable factor		84	%	-		128	%

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
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 fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively.

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

Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). For middle market lending, certain corporate debt securities, and private equity 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 valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.

Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its' Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers' inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its' Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

Derivative Financial Instruments [Line Items]

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)

9. Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)

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

Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)

To the extent the amount of energy Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations 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 energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices.

Derivative accounting 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 each period. 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 hedge, and fair value hedge. For commodity transactions, effective with the date of merger with Constellation, Generation no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the merger. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation's designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivative economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 22 – Commitments and Contingencies of the Exelon 2013 Form 10-K. 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.

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. 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 energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management's policies and hedging objectives, the market, weather conditions, operational and other factors. 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.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation's owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of June 30, 2014, the percentage of expected generation hedged for the major reportable segments was 92%-95%, 75%-78%, and 46%-49% for 2014, 2015, and 2016, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation represents the amount of energy estimated to be generated or purchased through owned or contracted capacity. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including, Generation's sales to ComEd, PECO and BGE to serve their retail load.

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. Delivery under the contracts began in June 2012. Pursuant to the ICC's Order on December 19, 2012, ComEd's commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC's December 18, 2013 Order approved the reduction of ComEd's commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved in March 2014. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for additional information.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 - Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO's price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.

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 in order 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 2013 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 2013 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO's gas-hedging program is designed to cover about 30% 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 financial position or results of operations 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. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE's 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. All of BGE's natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.

Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon's RMC. The proprietary trading activities, which included settled physical sales volumes of 2,629 GWhs and 5,123 GWhs for the three and six months ended June 30, 2014, respectively, and 1,995 GWhs and 3,567 for the three and six months ended June 30, 2013, respectively, are a complement to Generation's energy marketing portfolio but represent a small portion of Generation's revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes.

Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO and BGE)

The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At June 30, 2014, Exelon and Generation had $1,550 million and $700 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $1,111 million and $411 million of notional amounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $4 million decrease in Exelon Consolidated pre-tax income for the six months ended June 30, 2014. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign currency hedges as of June 30, 2014.

		Generation										Other		Exelon
	Description	Derivatives Designated as Hedging Instruments		Economic Hedges		Proprietary Trading^(a)		Collateral and Netting^(b)		Subtotal		Derivatives Designated as Hedging Instruments		Total

Mark-to-market derivative assets
	(current assets)	$	0	$	2	$	14	$	(18)	$	(2)	$	0	$	(2)
Mark-to-market derivative assets
	(noncurrent assets)		16		2		12		(10)		20		18		38
Total mark-to-market derivative
	assets	$	16	$	4	$	26	$	(28)	$	18	$	18	$	36

Mark-to-market derivative liabilities
	(current liabilities)	$	(1)	$	(4)	$	(15)	$	19	$	(1)	$	0	$	(1)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(19)		(2)		(11)		11		(21)		(6)		(27)
Total mark-to-market derivative
	liabilities	$	(20)	$	(6)	$	(26)	$	30	$	(22)	$	(6)	$	(28)
Total mark-to-market derivative
	net assets (liabilities)	$	(4)	$	(2)	$	0	$	2	$	(4)	$	12	$	8

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
Represents the netting of fair value balances with the same counterparty and any associated cash collateral.

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2013:

		Generation										Other		Exelon
	Description	Derivatives Designated as Hedging Instruments		Economic Hedges		Proprietary Trading^(a)		Collateral and Netting^(b)		Subtotal		Derivatives Designated as Hedging Instruments		Total

Mark-to-market derivative assets
	(current assets)	$	0	$	3	$	15	$	(19)	$	(1)	$	0	$	(1)
Mark-to-market derivative assets
	(noncurrent assets)		26		3		15		(13)		31		7		38
Total mark-to-market derivative
	assets	$	26	$	6	$	30	$	(32)	$	30	$	7	$	37

Mark-to-market derivative liabilities
	(current liabilities)	$	(1)	$	(1)	$	(18)	$	19	$	(1)	$	0	$	(1)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(10)		(1)		(13)		13		(11)		(4)		(15)
Total mark-to-market derivative
	liabilities	$	(11)	$	(2)	$	(31)	$	32	$	(12)	$	(4)	$	(16)
Total mark-to-market derivative
	net assets (liabilities)	$	15	$	4	$	(1)	$	0	$	18	$	3	$	21

Fair Value Hedges. For derivative instruments that are designated and qualify 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 current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
Represents the netting of fair value balances with the same counterparty and any associated cash collateral.

		Three Months Ended June 30,
	Income Statement	2014		2013		2014		2013
	Location	Gain (Loss) on Swaps				Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(3)	$	(5)	$	2	$	2
Exelon	Interest expense		3		(6)		(3)		3

		Six Months Ended June 30,
	Income Statement	2014		2013		2014		2013
	Location	Gain (Loss) on Swaps				Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(8)	$	(9)	$	1	$	1
Exelon	Interest expense		5		(12)		(7)		4

__________

For the three and six months ended June 30, 2014, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing. For the three and six months ended June 30, 2013, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing.

During the first six months of 2014, Exelon entered into $50 million and $75 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2019 and 2020, respectively. At June 30, 2014, Exelon and Generation had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,400 million and $550 million, with unrealized gains of $33 million and $16 million, respectively. At December 31, 2013, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,275 million and $550 million, with unrealized gains of $26 million and $23 million, respectively. During the three and six months ended June 30, 2014, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $5 million and a $8 million gain, respectively. During the three and six months ended June 30, 2013, the impact on the results of operations as a result of ineffectiveness from fair value hedges was immaterial.

Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley project financings, as discussed in Note 13 – Debt and Credit Agreements of the Exelon 2013 Form 10-K, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of September 30, 2014. The swap hedges approximately 75% of Generation's future interest rate exposure associated with the financing and was designated as a cash flow hedge. As such, the effective portion of the hedge is recorded in other comprehensive income within Generation's Consolidated Balance Sheets, with any ineffectiveness recorded in Generation's Consolidated Statements of Operations and Comprehensive Income. Net gains (or losses) from settlement of the hedges, to the extent effective, are amortized as an adjustment to the interest expense over the term of the DOE guaranteed loan.

Every time Generation draws down on the loan, an offsetting hedge (fixed-to-floating) is executed and a portion of the cash flow hedge with a notional amount equal to the offsetting hedge, is de-designated and the related gains or losses going forward are reflected in earnings, which are largely offset by the losses or gains in the offsetting hedge.

Antelope Valley received its first loan advance on April 5, 2012, and a series of additional advances subsequently. Generation has entered into a series of fixed-to-floating interest rate swaps with an aggregated notional amount of $350 million, approximately 75% of the loan advance amount to offset portions of the original interest rate hedge, which are not designated as cash flow hedges. The remaining cash flow hedge has a notional amount of $135 million. At June 30, 2014, Generation's mark-to-market derivative liability relating to the interest rate swaps in connection with the loan agreement to fund Antelope Valley was $15 million.

During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Sacramento PV Energy. The swaps have a total notional amount of $27 million as of June 30, 2014 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At June 30, 2014, the subsidiary had a $2 million derivative liability related to these swaps.

During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed interest rate swap to manage a portion of the interest rate exposure of anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $26 million as of June 30, 2014 and expires in 2030. This swap is designated as a cash flow hedge. At June 30, 2014, the subsidiary had a $1 million derivative asset related to the swap.

During the first quarter of 2014, a subsidiary of Exelon Generation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure with long-term borrowings to finance ExGen Renewables I, LLC. See Note 10 – Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $223 million as of June 30, 2014 and expire in 2020. The swaps are designated as cash flow hedges. At June 30, 2014, the subsidiary had a $2 million derivative liability related to the swaps.

During the first six months of 2014, Exelon entered into $400 million of floating-to-fixed interest rate hedges to refinance existing debt. The swaps are designated as cash flow hedges. At June 30, 2014, Exelon had a $6 million derivative liability related to the swaps.

During the three and six months ended June 30, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.

Economic Hedges. During the second quarter of 2014, Exelon entered into $300 million of floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed merger with PHI. At June 30, 2014, Exelon had an immaterial derivative asset related to the swaps.

At June 30, 2014, Exelon and Generation had $150 million in notional amounts of fixed-to-floating interest rate swaps that are marked-to-market, with unrealized gains of $1 million. These swaps, which were acquired as part of the merger with Constellation, expire in 2014. During the six months ended June 30, 2014 and 2013, the impact on the results of operations was immaterial.

At June 30, 2014, Generation had $257 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $121 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.

Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO and BGE)

Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the 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 and 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, is aggregated in the collateral and netting column. As of June 30, 2014 and December 31, 2013, $7 million of cash collateral held and $10 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives or as of the balance sheet date there were no positions to offset. 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 a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of June 30, 2014:

		Generation								ComEd		Exelon
		Economic		Proprietary		Collateral and				Economic		Total
Derivatives		Hedges		Trading		Netting^(a)		Subtotal^(b)		Hedges^(c)		Derivatives

Mark-to-market derivative assets
	(current assets)	$	3,422	$	925	$	(3,716)	$	631	$	0	$	631
Mark-to-market derivative assets
	(noncurrent assets)		1,394		149		(1,099)		444		0		444
Total mark-to-market derivative
	assets	$	4,816	$	1,074	$	(4,815)	$	1,075	$	0	$	1,075

Mark-to-market derivative liabilities
	(current liabilities)	$	(3,354)	$	(900)	$	4,040	$	(214)	$	(13)	$	(227)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(1,214)		(165)		1,265		(114)		(121)		(235)
Total mark-to-market derivative
	liabilities	$	(4,568)	$	(1,065)	$	5,305	$	(328)	$	(134)	$	(462)
Total mark-to-market derivative
	net assets (liabilities)	$	248	$	9	$	490	$	747	$	(134)	$	613

__________

(a) Exelon and Generation net all available amounts allowed under the derivative accounting 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 $(126) million and $(56) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(198) million and $(110) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $490 million at June 30, 2014.

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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2013:

		Generation								ComEd		Exelon
		Economic		Proprietary		Collateral and				Economic		Total
Description		Hedges		Trading		Netting^(a)		Subtotal^(b)		Hedges^(c)		Derivatives

Mark-to-market derivative assets
	(current assets)	$	2,616	$	1,476	$	(3,364)	$	728	$	0	$	728
Mark-to-market derivative assets
	(noncurrent assets)		1,344		285		(1,060)		569		0		569
Total mark-to-market derivative
	assets	$	3,960	$	1,761	$	(4,424)	$	1,297	$	0	$	1,297

Mark-to-market derivative liabilities
	(current liabilities)	$	(2,023)	$	(1,410)	$	3,292	$	(141)	$	(17)	$	(158)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(804)		(293)		988		(109)		(176)		(285)
Total mark-to-market derivative
	liabilities	$	(2,827)	$	(1,703)	$	4,280	$	(250)	$	(193)	$	(443)
Total mark-to-market derivative
	net assets (liabilities)	$	1,133	$	58	$	(144)	$	1,047	$	(193)	$	854

__________

(a) Exelon and Generation net all available amounts allowed under the derivative accounting 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. These are not reflected in the table above.

(b) Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.

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

Cash Flow Hedges (Exelon and Generation). As discussed previously, effective prior to the merger with Constellation, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and is reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. Approximately $94 million of these net pre-tax unrealized gains within accumulated OCI are expected to be reclassified from accumulated OCI during the next twelve months by Generation. Generation expects the settlement of the majority of its cash flow hedges will occur during 2014.

The tables below provide the activity of accumulated OCI related to cash flow hedges for the three months ended June 30, 2014 and 2013, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended June 30, 2014	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2014		$	95	^(a)	$	95
Effective portion of changes in fair value			0			(10)
Reclassifications from accumulated OCI to net income	Operating Revenues		(38)	^(b)		(38)
Accumulated OCI derivative gain at June 30, 2014		$	57	^(a)	$	47

Excludes $6 million and $3 million of gains, net of taxes, related to interest rate swaps and treasury rate locks as of June 30, 2014 and March 31, 2014.

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Total Cash Flow Hedge OCI Activity, Net of Income Tax
			Generation			Exelon
Six Months Ended June 30, 2014	Income Statement Location		Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2013			$	119	^(a)	$	120
Effective portion of changes in fair value				0			(11)
Reclassifications from accumulated OCI to net income	Operating Revenues			(62)	^(b)		(62)
Accumulated OCI derivative gain at June 30, 2014			$	57	^(a)	$	47

__________

Excludes $9 million of gains and $15 million of losses, net of taxes, related to interest rate swaps and treasury locks as of June 30, 2014 and December 31, 2013, respectively.

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended June 30, 2013	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at March 31, 2013		$	397	^(a)(c)	$	310
Effective portion of changes in fair value			0			21	^(d)
Reclassifications from accumulated OCI to net income	Operating Revenues		(142)	^{(b) (e)}		(86)
Accumulated OCI derivative gain at June 30, 2013		$	255	^(c)	$	245

(a) Includes $58 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of March 31, 2013.

(b) Includes $58 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(c) Excludes $11 million and $16 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of June 30, 2013 and March 31, 2013, respectively.

(d) Includes $18 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the three months ended June 30, 2013.

		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Six Months Ended June 30, 2013	Income Statement Location	Energy-Related Hedges			Total Cash Flow Hedges
Accumulated OCI derivative gain at December 31, 2012		$	532	^(a)(c)	$	368
Effective portion of changes in fair value			0			21	^(d)
Reclassifications from accumulated OCI to net income	Operating Revenues		(277)	^{(b) (e)}		(144)
Accumulated OCI derivative gain at June 30, 2013		$	255	^(c)	$	245

_____________

(a) Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012.

(b) Includes $133 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(c) Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of June 30, 2013 and December 31, 2012, respectively.

(d) Includes $22 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.

During the three and six months ended June 30, 2014 and 2013, Generation's former energy related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $63 million and a $102 pre-tax gain and a $236 million and a $459 pre-tax gain, respectively. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include power and gas options or sales, the ineffectiveness of Generation's cash flow hedges was primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units.

The effect of Exelon's former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $63 million and $102 million pre-tax gain for the three months ended June 30, 2014, and a $141 million and $240 million pre-tax gain for the three and six months ended June 30, 2013. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as all energy-related cash flow hedge positions were de-designated prior to the merger date.

Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps (“treasury”) to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed merger with PHI. For the three and six months ended June 30, 2014 and 2013, the following pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues, purchased, power and fuel expense, or interest expense. For the three and six months ended June 30, 2014 and 2013, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel expense at Exelon and Generation 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. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Three Months Ended June 30, 2014		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	(124)	$	111	$	0	$	(13)	$	0	$	0	$	(13)
Reclassification to realized at settlement
	of commodity positions		45		(42)		0		3		0		0		3
Net commodity mark-to-market gains (losses)		$	(79)	$	69	$	0	$	(10)	$	0	$	0	$	(10)

Change in fair value of treasury positions		$	(3)	$	0	$	(1)	$	(4)	$	0	$	0	$	(4)
Reclassification to realized at settlement
	of treasury positions		(1)		0		0		(1)		0		0		(1)
Net treasury mark-to-market gains (losses)		$	(4)	$	0	$	(1)	$	(5)	$	0	$	0	$	(5)

	Net mark-to-market gains (losses)	$	(83)	$	69	$	(1)	$	(15)	$	0	$	0	$	(15)

		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Six Months Ended June 30, 2014		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	(975)	$	282	$	0	$	(693)	$	0	$	0	$	(693)
Reclassification to realized at settlement
	of commodity positions		137		(183)		0		(46)		0		0		(46)
Net commodity mark-to-market gains (losses)		$	(838)	$	99	$	0	$	(739)	$	0	$	0	$	(739)

Change in fair value of treasury positions		$	(4)	$	0	$	(1)	$	(5)	$	0	$	0	$	(5)
Reclassification to realized at settlement
	of treasury positions		(1)		0		0		(1)		0		0		(1)
Net treasury mark-to-market gains (losses)		$	(5)	$	0	$	(1)	$	(6)	$	0	$	0	$	(6)

	Net mark-to-market gains (losses)	$	(843)	$	99	$	(1)	$	(745)	$	0	$	0	$	(745)

		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Three Months Ended June 30, 2013		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	460	$	(77)	$	0	$	383	$	(13)	$	0	$	370
Reclassification to realized at settlement
	of commodity positions		44		1		0		45		3		0		48
Net commodity mark-to-market gains (losses)		$	504	$	(76)	$	0	$	428	$	(10)	$	0	$	418

Change in fair value of treasury positions		$	0	$	0	$	(2)	$	(2)	$	0	$	0	$	(2)
Reclassification to realized at settlement
	of treasury positions		0		0		0		0		0		0		0
Net treasury mark-to-market gains (losses)		$	0	$	0	$	(2)	$	(2)	$	0	$	0	$	(2)

	Net mark-to-market gains (losses)	$	504	$	(76)	$	(2)	$	426	$	(10)	$	0	$	416


		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Six Months Ended June 30, 2013		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	(26)	$	69	$		$	43	$	(6)	$	0	$	37
Reclassification to realized at settlement
	of commodity positions		(56)		38				(18)		13		0		(5)
Net commodity mark-to-market gains (losses)		$	(82)	$	107	$	0	$	25	$	7	$	0	$	32

Change in fair value of treasury positions		$	0	$	0	$	(3)	$	(3)	$	0	$	0	$	(3)
Reclassification to realized at settlement
	of treasury positions		0		0		0		0		0		0		0
Net treasury mark-to-market gains (losses)		$	0	$	0	$	(3)	$	(3)	$	0	$	0	$	(3)

	Net mark-to-market gains (losses)	$	(82)	$	107	$	(3)	$	22	$	7	$	0	$	29

Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation.

Proprietary Trading Activities (Exelon and Generation). For the three and six months ended June 30, 2014 and 2013, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate derivative contracts to hedge risk associated with the interest rate component of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenue 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. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.

			Three Months Ended				Six Months Ended
		Location on Income	June 30,				June 30,
		Statement	2014		2013		2014		2013
Change in fair value of commodity positions		Operating Revenues	$	1	$	5	$	0	$	1
Reclassification to realized at settlement
	of commodity positions	Operating Revenues		(8)		(1)		(7)		5
Net commodity mark-to-market gains (losses)		Operating Revenues	$	(7)	$	4	$	(7)	$	6

Change in fair value of treasury positions		Operating Revenues	$	0	$	0	$	(1)	$	0
Reclassification to realized at settlement
	of treasury positions	Operating Revenues		1		(1)		1		(1)
Net treasury mark-to-market gains (losses)		Operating Revenues	$	1	$	(1)	$	0	$	(1)

Net mark-to-market gains (losses)		Operating Revenues	$	(6)	$	3	$	(7)	$	5

Credit Risk (Exelon, Generation, ComEd, PECO and BGE)

The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation's exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation's credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty's margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation's credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on Generation's credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2014. 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 excludes credit risk exposure from individual retail counterparties, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in Item 3. Quantitative and Qualitative Disclosures About Market Risk. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $6 million, $23 million and $36 million, respectively.

	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of June 30, 2014	Collateral		Collateral^(a)		Exposure		of Net Exposure		of Net Exposure
Investment grade	$	1,095	$	103	$	992		1	$	417
Non-investment grade		12		9		3		0		0
No external ratings
Internally rated - investment grade		286		2		284		1		189
Internally rated - non-investment
grade		21		4		17		0		0
Total	$	1,414	$	118	$	1,296		2	$	606

Net Credit Exposure by Type of Counterparty	As of June 30, 2014
Financial institutions		$	185
Investor-owned utilities, marketers, power producers			360
Energy cooperatives and municipalities			729
Other			22
Total		$	1,296

As of June 30, 2014, credit collateral held from counterparties where Generation had credit exposure included $112 million of cash and $6 million of letters of credit.

ComEd's power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on 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, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd's net credit exposure. As of June 30, 2014, ComEd's net credit exposure to suppliers was approximately $2 million.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for additional information.

PECO's supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier's performance assurance requirements, allow a supplier to meet its credit requirements 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 PECO's net credit exposure. As of June 30, 2014, PECO had no net credit exposure with suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO's counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 5 - Regulatory Matters for additional information.

PECO's natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO's counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of June 30, 2014, PECO had credit exposure of $6 million 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 5 – 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. 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, subject to an unsecured credit cap. 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 BGE's net credit exposure. The seller's credit exposure is calculated each business day. As of June 30, 2014, BGE had a net credit exposure of $38 million to suppliers.

BGE's regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE's recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers' demands, which are not covered by the gas cost adjustment clause. At June 30, 2014, BGE had credit exposure of $1 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.

Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)

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

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

Credit-Risk Related Contingent Feature		June 30, 2014		December 31, 2013
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(1,102)	$	(1,056)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)		825		846
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(277)	$	(210)

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.
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.
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 $623 million and letters of credit posted of $466 million and cash collateral held of $124 million and letters of credit held of $14 million as of June 30, 2014 for counterparties with derivative positions. Generation had cash collateral posted of $72 million and letters of credit posted of $364 million and cash collateral held of $206 million and letters of credit held of $34 million at December 31, 2013 for 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 $2.0 billion as of June 30, 2014 and December 31, 2013. 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 June 30, 2014, Generation's swaps were in a liability position and Exelon's swaps were in an asset position, with a fair value of $(4) million and $8 million, respectively.

See Note 24 – Segment Information of the Exelon 2013 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd's standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of June 30, 2014, ComEd held approximately $2 million from suppliers for the purpose of collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, 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 June 30, 2014, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for additional information.

PECO's natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO's credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of June 30, 2014, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of June 30, 2014, PECO could have been required to post approximately $26 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 full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE 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 June 30, 2014, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of June 30, 2014, BGE could have been required to post approximately $73 million of collateral to its counterparties.

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

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Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Text Block]

10. Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE)

Short-Term Borrowings

Exelon, ComEd and BGE 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 intercompany money pool.

The Registrants had the following amounts of commercial paper borrowings outstanding as of June 30, 2014 and December 31, 2013:

Commercial Paper Borrowings	June 30, 2014		December 31, 2013
Exelon Corporate	$	0	$	0
Generation		0		0
ComEd		498		184
PECO		0		0
BGE		70		135

Credit Facilities

Exelon had bank lines of credit under committed credit facilities at June 30, 2014 for short-term financial needs, as follows:

Type of Credit Facility		Amount (a)		Expiration Dates	Capacity Type
Exelon Corporate		(In billions)
	Syndicated Revolver^(b)	$	0.5	May 2019	Letters of credit and cash
Generation
	Syndicated Revolver		5.1	May 2019	Letters of credit and cash
	Syndicated Revolver		0.2	August 2018	Letters of credit and cash
	Bilateral		0.3	December 2015 and March 2016	Letters of credit and cash
	Bilateral		0.1	January 2015	Letters of credit
	Bilateral		0.1	October 2014	Letters of credit and cash
ComEd
	Syndicated Revolver		1.0	March 2019	Letters of credit and cash
PECO
	Syndicated Revolver^(b)		0.6	May 2019	Letters of credit and cash
BGE
	Syndicated Revolver^(b)		0.6	May 2019	Letters of credit and cash
	Total	$	8.5

_____________

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd's, PECO's and BGE's service territories. These facilities expire on October 18, 2014 and are solely utilized to issue letters of credit. As of June 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $20 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $7.2 billion to support the PHI transaction discussed below.
Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.

As of June 30, 2014, there were no borrowings under the Registrants' credit facilities, with the exception of CENG, see discussion below

On March 28, 2014, ComEd extended for an additional year the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement expires on March 28, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material.

On April 1, 2014, as a result of the CENG integration, a $100 million bilateral CENG credit facility expiring October 2014 is now consolidated in Exelon's and Generation's consolidated financial statements. This facility will be utilized by CENG to fund working capital and capital projects and obtain letters of credit. As of June 30, 2014, CENG borrowed $40 million against its credit facility.

On May 30, 2014, Exelon, Generation, PECO and BGE extended for an additional year the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $500 million, $5.3 billion, $600 million, $600 million, respectively into May 2019, with the exception of a cumulative amount of $300 million which expires in August 2018. Costs incurred to extend the facility were not material.

Borrowings under Exelon Corporate's, Generation's, ComEd's, PECO's and BGE's 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. Exelon Corporate, Generation, ComEd, PECO and BGE have adders of 27.5, 27.5, 7.5, 0.0 and 0.0 basis points for prime based borrowings and 127.5, 127.5, 107.5, 90.0 and 100.0 basis points for LIBOR-based borrowings. The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 65 basis points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments under the agreement. The fee varies depending upon the respective credit ratings of the borrower.

Credit Agreements

In May 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $4.2 billion as a result of the June 2014 equity issuances discussed below. During the three and six months ended June 30, 2014, Exelon recorded $9 million to interest expense in connection with the bridge facility. It is not currently expected that Exelon will be required to draw upon this credit facility.

Long-Term Debt

Issuance of Long-Term Debt

During the six months ended June 30, 2014, the following long-term debt was issued:

Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon	Junior Subordinated Notes	2.500	%	June 1, 2024	$	1,150	Used to finance a portion of the acquisition of PHI and for general corporate purposes
Generation	Nuclear Fuel Purchase Contract	3.350	%	June 30, 2018	$	38	Used for procurement of uranium
Generation	ExGen Renewables I Project Financing^(a)	LIBOR + 4.250%		February 6, 2021	$	300	Used for general corporate purposes
ComEd	Mortgage Bonds Series 115	2.150	%	January 15, 2019	$	300	Used to refinance existing mortgage bonds
ComEd	Mortgage Bonds Series 116	4.700	%	January 15, 2044	$	350	Used to refinance existing mortgage bonds

_______________

See ExGen Renewables I Project Financing, non recourse debt, discussed below

Junior Subordinated Notes

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. Proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes.

Each equity unit represents an undivided beneficial ownership interest in Exelon's 2.5% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017. In connection with the remarketing, Exelon may modify the maturity date of the notes to a date earlier than June 1, 2024 but not earlier than June 1, 2020, remove redemption provisions of the notes, or change the interest rate on the notes, including changing the interest rate from fixed to floating. Investors that participate in the remarketing receive the remarketing proceeds and may use those funds to either settle the equity forward upon settlement date or invest in the remarketed debt and use other funds for the share purchase. Exelon intends to use the remarketing proceeds to repay debt issued or for other corporate purposes as soon as practical following such settlements. If the remarketing fails, holders of the notes will have the right to put their notes to Exelon for an amount equal to the principal amount plus accrued interest. The equity units carry a total annual distribution rate of 6.5%, which is comprised of a quarterly coupon rate of interest of 2.5% and a quarterly contract payment of 4.0% (contract payments).

Each purchase contract obligates the holder to purchase, and Exelon to sell, for $50.00 a number of shares of Exelon's common stock in accordance with the conversion ratios set forth below:

If the market price equals or exceeds $43.7484, then 1.1429 shares.
If the market price is less than $43.7484 but greater than $35.00, a number of shares of common stock having a value, based on the market price, equal to $50.00.
If the market price is less than or equal to $35.00, then 1.4286 shares.

A holder's ownership interest in the notes is pledged to Exelon to secure the holder's obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder's obligation under the purchase contract must be secured by a U.S. Treasury security.

At the time of issuance, the $1.15 billion of junior subordinated notes were recorded within Long-term debt on Exelon's Consolidated Balance Sheet. Additionally, at the time of issuance, the present value of the contract payments of $131 million were recorded to Long-term debt, representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments will be accreted to interest expense over the 3 year period ending in 2017 in Exelon's Consolidated Statement of Operations and Comprehensive Income. The Long-term debt recorded for the contract payments is considered a non-cash financing transaction that was excluded from Exelon's Consolidated Statements of Cash Flows. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method.

ExGen Renewables Energy I LLC

On February 6, 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal amount pursuant to a non-recourse senior secured loan, due February 6, 2021. The loan bears interest at a variable rate equal to LIBOR plus 4.25%. EGR indirectly owns Continental Wind LLC (Continental Wind). In addition to the financing, EGR entered into interest rate swaps with a notional amount of $240 million to manage a portion of the interest rate exposure in connection with the financing. The assets pledged as collateral related to EGR have a net book value of approximately $796 million as of June 30, 2014, See Note 9 – Derivative Financial Instruments for additional information regarding interest rate swaps.

During the six months ended June 30, 2013, the following long-term debt was issued:

Company	Type	Interest Rate		Maturity		Amount	Use of Proceeds
Generation	Upstream Gas Lending Agreement	2.210	%	July 22, 2016	$	3	Used to fund Upstream gas activities
Generation	DOE Project Financing	2.535 - 2.922	%	January 5, 2037	$	197	Funding for Antelope Valley Solar Development
Generation	Energy Efficiency Project Financing	4.400	%	August 31, 2014	$	9	Funding to install energy conservation measures in Beckley, West Virginia
BGE	Senior Notes	3.350	%	July 1, 2023	$	300	Used to partially refinance Notes due July 1, 2013 and for general corporate purposes

Retirement and Redemptions of Current and Long-Term Debt

During the six months ended June 30, 2014, the following long-term debt was retired and/or redeemed:

Company	Type	Interest Rate		Maturity	Amount
Generation	2003 Senior Notes	5.35	%	January 15, 2014		$	500
Generation	Pollution Control Loan	4.10	%	July 1, 2014		$	20
Generation	Continental Wind Project Financing	6.00	%	February 28, 2033		$	11
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		$	2
Generation	ExGen Renewables I	3mL + 4.25	%	February 6, 2021		$	3
Generation	AVSR	2.33% - 3.55%		January 5, 2037		$	1
Generation	Clean Horizons Solar	2.56	%	September 7, 2030		$	1
Generation	Sacramento Solar	2.56	%	December 31, 2030		$	1
ComEd	Mortgage Bonds Series 110	1.63	%	January 15, 2014		$	600
ComEd	Pollution Control Series 1994C	5.85	%	January 15, 2014		$	17
BGE	Rate Stabilization Bonds	5.72	%	April 1, 2017		$	35

During the six months ended June 30, 2013, the following long-term debt was retired and/or redeemed:

Company		Type	Interest Rate		Maturity	Amount
Generation		Kennett Square Capital Lease	7.830	%	September 20, 2020		$	1
Generation		Solar Revolver	1.950	%	July 7, 2014		$	6
Generation		Clean Horizons Solar	2.563	%	September 7, 2030		$	1
Generation	^(a)	Series A Junior Subordinated Debentures	8.625	%	June 15, 2063		$	450
ComEd		First Mortgage Bonds Series 92	7.625	%	April 15, 2013		$	125
BGE		Rate Stabilization Bonds	5.720	%	April 1, 2017		$	33

______________

(a) Represents debt obligations assumed by Exelon as part of the merger on March 12, 2012 that became callable at face value on June 15, 2013. 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, which are eliminated in consolidation on Exelon's Consolidated Balance Sheets. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013.

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Income Taxes [Line Items]

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

11. Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

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

For the Three Months Ended June 30, 2014		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	2.1		1.7		4.6		(0.5)		4.1
	Qualified nuclear decommissioning trust fund income	4.1		6.0		0.0		0.0		0.0
	Domestic production activities deduction	(2.0)		(2.9)		0.0		0.0		0.0
	Health care reform legislation	0.0		0.0		0.2		0.0		0.2
	Amortization of investment tax credit, net deferred taxes	(0.4)		(0.5)		(0.3)		(0.1)		(0.7)
	Plant basis differences	(1.6)		0.0		(0.4)		(13.2)		5.1
	Production tax credits and other credits	(0.8)		(1.1)		0.0		0.0		0.0
	Noncontrolling interest	(2.0)		(2.9)		0.0		0.0		0.0
	Other	(1.2)		(0.4)		0.2		0.3		(1.3)

Effective income tax rate		33.2	%	34.9	%	39.3	%	21.5	%	42.4	%

For the Six Months Ended June 30, 2014		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	(0.6)		(14.7)		5.0		0.4		5.0
	Qualified nuclear decommissioning trust fund income	5.9		27.7		0.0		0.0		0.0
	Domestic production activities deduction	(3.2)		(14.8)		0.0		0.0		0.0
	Health care reform legislation	0.1		0.0		0.2		0.0		0.2
	Amortization of investment tax credit, net deferred taxes	(1.2)		(4.9)		(0.3)		(0.1)		(0.3)
	Plant basis differences	(3.0)		0.0		(0.5)		(10.8)		0.4
	Production tax credits and other credits	(2.4)		(11.1)		0.0		0.0		0.0
	Noncontrolling interest	(1.9)		(8.8)		0.0		0.0		0.0
	Other	(3.1)		(8.9)		0.2		0.3		0.1

Effective income tax rate		25.6	%	(0.5)	%	39.6	%	24.8	%	40.4	%


For the Three Months Ended June 30, 2013		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	4.1		3.5		5.6		2.9		5.6
	Qualified nuclear decommissioning trust fund income	(1.8)		(2.7)		0.0		0.0		0.0
	Domestic production activities deduction	0.1		0.2		0.0		0.0		0.0
	Tax exempt income	(0.1)		(0.2)		0.0		0.0		0.0
	Health care reform legislation	0.1		0.0		0.4		0.0		(0.3)
	Amortization of investment tax credit, net deferred taxes	(1.8)		(2.5)		(0.3)		(0.1)		(0.6)
	Plant basis differences	(1.4)		0.0		(0.4)		(8.6)		(0.7)
	Production tax credits and other credits	(1.4)		(2.2)		0.0		0.0		0.0
	Other	(0.3)		0.1		0.4		(0.1)		0.0

Effective income tax rate		32.5	%	31.2	%	40.7	%	29.1	%	39.0	%

For the Six Months Ended June 30, 2013		Exelon		Generation		ComEd		PECO		BGE

U.S. Federal statutory rate		35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	8.6		0.4		4.1		2.9		5.7
	Qualified nuclear decommissioning trust fund income	2.8		4.8		0.0		0.0		0.0
	Domestic production activities deduction	0.0		(0.1)		0.0		0.0		0.0
	Tax exempt income	(0.2)		(0.4)		0.0		0.0		0.0
	Health care reform legislation	0.2		0.0		5.7		0.0		0.2
	Amortization of investment tax credit, net deferred taxes	(3.5)		(5.6)		(4.9)		(0.1)		(0.3)
	Plant basis differences	(3.1)		0.0		(8.7)		(7.5)		(0.6)
	Production tax credits and other credits	(2.8)		(4.9)		(0.3)		0.0		0.0
	Other	0.1		3.1		5.5		0.0		(0.2)

Effective income tax rate		37.1	%	32.3	%	36.4	%	30.3	%	39.8	%

_____

(a)

Accounting for Uncertainty in Income Taxes

Exelon, Generation, ComEd, PECO, and BGE have $1,871 million, $1,403 million, $153 million, $44 million, and $0 million, of unrecognized tax benefits as of June 30, 2014, respectively, and $2,175 million, $1,415 million, $324 million, $44 million, and $0 million, of unrecognized tax benefits as of December 31, 2013, respectively. The unrecognized tax benefits as of June 30, 2014 reflect a decrease at Exelon and ComEd primarily attributable to the like-kind exchange and the lease termination position discussed below.

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

Nuclear Decommissioning Liabilities (Exelon and Generation)

AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and has disallowed the claims. In November 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen's refund claims. Generation filed a complaint in the United States Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and the DOJ completed and filed cross motions for summary judgment. On September 17, 2013, the Court granted the government's motion denying AmerGen's claims for refund. In the first quarter of 2014, Exelon filed an appeal of the decision to the United States Court of Appeals for the Federal Circuit.

Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next 12 months.

Settlement of Income Tax Audits

As of June 30, 2014, Exelon and Generation have approximately $225 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing federal and state audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate. In January 2014, certain unrecognized tax benefits as of December 31, 2013 were effectively settled and thus resulted in reduced tax expense of $33 million at Generation in the first quarter of 2014.

Other Income 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. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.

Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $87 million for a substantial understatement of tax.

Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon does not believe a settlement is possible. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like-kind exchange position.

On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison's deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter.

In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon's current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $170 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd's equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid tax liabilities related to the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the IRS's assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded.

On September 30, 2013, the Internal Revenue Service issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlled by the Federal Circuit's decision in Consolidated Edison.

In the event of a fully successful IRS challenge to Exelon's like-kind exchange position, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable as of June 30, 2014 may be as much as $830 million, of which approximately $310 million would be attributable to ComEd after consideration of Exelon's agreement to hold ComEd harmless, and the balance at Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.

In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. The termination will result in a 2014 tax payment of approximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon's like-kind exchange position, Exelon will be required to pay the full amount of tax and after-tax interest discussed in the preceding paragraph but will ultimately be entitled to a refund of the 2014 tax payment. See Note 7 – Impairment of Long Lived Assets for further details.

Accounting for Final Tangible Property Regulations (Exelon, Generation, ComEd, PECO, and BGE)

On September 19, 2013, the Treasury Department and the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce, or improve tangible property. The Registrants have assessed the financial impact of this guidance and do not expect it to have a material impact. Any changes in method of accounting required to conform to the final regulations will be made for the Registrant's 2014 taxable year.

Accounting for Generation Repairs (Exelon and Generation)

On April 30, 2013, the IRS issued Revenue Procedure 2013-24 providing guidance for determining the appropriate tax treatment of costs incurred to repair electric generation assets. Generation will change its method of accounting for deducting repairs in accordance with this guidance beginning with its 2014 tax year. Generation has estimated that adoption of the new method will result in a cash tax detriment of approximately $100 - $120 million.

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligations [Line Items]

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

12. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets from December 31, 2013 to June 30, 2014:

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

(a) Includes $9 million as the current portion of the ARO at June 30, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

(b) Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

During the six months ended June 30, 2014, Generation's ARO increased by approximately $1.9 billion. The increase is largely driven by the consolidation of CENG. The fair value of CENG's assets and liabilities recorded in consolidation, including the ARO, was determined based on significant estimates and assumptions that are judgmental in nature. The valuation to assess the fair value of the ARO is considered an initial estimate and will be updated with inputs from a third party engineering firm with corresponding adjustments recorded by the end of 2014. For additional details on the consolidation of CENG, see Note 6 – Investment in Constellation Energy Nuclear Group, LLC.

Nuclear Decommissioning Trust Fund Investments

NDT funds have been established for each generating 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 the former ComEd, former PECO, former AmerGen and the CENG units have been funded with amounts collected from ComEd customers, PECO customers, and the previous owners of the former AmerGen and the CENG plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO's calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. With respect to the former AmerGen and CENG units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from customers. Apart from the contributions made to the NDT funds from amounts previously collected from ComEd and currently collected from PECO customers, Generation has not made contributions to the NDT funds.

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, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. 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 ComEd customers for the former ComEd units or from the previous owners of the former AmerGen and CENG 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 the former AmerGen units and CENG units, Generation retains any funds remaining in the trust funds 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 nuclear decommissioning trust 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 June 30, 2014 and December 31, 2013, Exelon and Generation had NDT fund investments totaling $10,437 million and $8,071 million, respectively.

The following table provides unrealized gains on NDT funds for the three and six months ended June 30, 2014 and 2013:

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

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

(b) Excludes $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended June 30, 2014 and 2013, respectively, and $20 million and $3 million of net unrealized gains related to the Zion Station pledged assets for the six months ended June 30, 2014 and 2013, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets.

(c) Net unrealized gains (losses) 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.

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

See Note 3 – Regulatory Matters and Note 25 – Related Party Transactions of the Exelon 2013 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to pledged assets for Zion Station decommissioning within Generation's and Exelon's Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a payable to ZionSolutions in Generation's and Exelon's Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be 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, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $85 million, which is included within the nuclear decommissioning ARO at June 30, 2014. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at June 30, 2014 and December 31, 2013:

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

__________

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

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. On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation has in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff's review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. On March 26, 2014, in accordance with a NRC requirement with respect to units involved in a merger or acquisition, CENG submitted its NRC-required decommissioning funding status report as of December 31, 2013 and no additional financial assurance was required.

On March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for shutdown reactors. This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation.

On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation's status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. On May 1, 2014, the NRC issued its final determination. Although the NRC determined that these historical status reports did not provide complete and accurate information, the violation of the regulatory requirements was not a deliberate violation. The NRC noted the low safety significance and Generation's corrective actions to satisfy the NRC Staff's expectations and issued a Severity Level IV violation, with no monetary penalty. A Severity Level IV violation is the lowest level of violation.

In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation's reporting and funding of the future decommissioning of Generation's nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon.

Asset Retirement Obligations [Line Items]

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)

12. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets from December 31, 2013 to June 30, 2014:

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

__________

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

Nuclear Decommissioning (Exelon and Generation)

6 Months Ended

Jun. 30, 2014

Nuclear Decommissioning Disclosure [Line Items]

Nuclear Decommissioning (Exelon and Generation)

12. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets from December 31, 2013 to June 30, 2014:

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

(b) Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

Nuclear Decommissioning Trust Fund Investments

At June 30, 2014 and December 31, 2013, Exelon and Generation had NDT fund investments totaling $10,437 million and $8,071 million, respectively.

The following table provides unrealized gains on NDT funds for the three and six months ended June 30, 2014 and 2013:

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

__________

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

Nuclear Decommissioning Disclosure [Line Items]

Nuclear Decommissioning (Exelon and Generation)

12. Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon's and Generation's Consolidated Balance Sheets from December 31, 2013 to June 30, 2014:

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

__________

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

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

6 Months Ended

Jun. 30, 2014

Retirement Benefits [Line Items]

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

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

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees.

On April 1, 2014, as a result of the consolidation of CENG into Generation, the obligations associated with CENG's pension and other postretirement plans are reflected in the disclosures below based on an April 1, 2014 valuation. The plans include essentially all employees at CENG. Exelon will assume sponsorship of the CENG pension and other postretirement benefit plans in the third quarter of 2014.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2014, Exelon received an updated valuation of several of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $35 million and an increase to the other postretirement benefit obligation of $12 million. Additionally, accumulated other comprehensive loss increased by approximately $12 million (after tax), regulatory assets increased by approximately $34 million, and regulatory liabilities increased by approximately $5 million. During the second quarter of 2014, Exelon received an updated valuation for the remainder of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $13 million and an increase to the other postretirement benefit obligation of $3 million. Additionally, accumulated other comprehensive loss increased by approximately $1 million (after tax) and regulatory assets increased by approximately $15 million.

In April 2014, Exelon announced plan design changes for certain other postretirement benefit plans, which required an interim remeasurement of the benefit obligation for those plans using assumptions as of April 30, 2014, including updated discount rates and asset values. The remeasurement is expected to result in a decrease in the net periodic benefit costs for other postretirement benefits of approximately $149 million for the period May 2014 through December 2014 as compared to the net periodic benefit costs that were anticipated based on the January 1, 2014 valuation. The remeasurement resulted in a decrease in Exelon's non-pension postretirement benefit obligations, regulatory assets, and accumulated other compressive loss of approximately $790 million, $240 million, and $259 million (after tax), respectively, and an increase in regulatory liabilities of approximately $125 million.

The following tables present the components of Exelon's net periodic benefit costs for the three and six months ended June 30, 2014 and 2013. The 2014 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.80%. The 2014 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.59% for funded plans and a discount rate of 4.90% for all plans. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the three and six months ended June 30, 2014 reflect the impact of this remeasurement. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.

		Pension Benefits				Other Postretirement Benefits
		Three Months Ended				Three Months Ended
		June 30,				June 30,
		2014(a)		2013		2014(a)		2013
Service cost		$	69	$	79	$	29	$	40
Interest cost			184		163		45		49
Expected return on assets			(242)		(254)		(38)		(33)
Amortization of:
	Prior service cost (benefit)		4		4		(30)		(6)
	Actuarial loss		104		141		12		21

Net periodic benefit cost		$	119	$	133	$	18	$	71

		Pension Benefits				Other Postretirement Benefits
		Six Months Ended				Six Months Ended
		June 30,				June 30,
		2014(a)		2013		2014(a)		2013
Service cost		$	138	$	159	$	61	$	81
Interest cost			367		326		101		97
Expected return on assets			(483)		(508)		(76)		(66)
Amortization of:
	Prior service cost (benefit)		7		7		(34)		(10)
	Actuarial loss		209		281		20		42

Net periodic benefit cost		$	238	$	265	$	72	$	144

Excludes components of CENG's net periodic benefit costs for the period April 1, 2014 to June 30, 2014 as presented in the below table.

The following tables present the components of net periodic benefit costs for the CENG-sponsored benefit plans for the period April 1, 2014 to June 30, 2014 and reflect the valuation performed as of April 1, 2014. The 2014 pension benefit cost for CENG sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.75% and discount rates ranging from 3.60% - 4.30%. The 2014 other postretirement benefit cost is calculated using a discount rate of 4.55% for all plans.

	Pension Benefits		Other Postretirement Benefits
Service cost	$	5	$	1
Interest cost		6		2
Expected return on assets		(9)		0

Net periodic benefit cost	$	2	$	3

The amounts below represent Generation's, ComEd's, PECO's, BGE's and BSC's allocated portion of the pension and postretirement benefit plan costs, which were included in Capital expenditures and Operating and maintenance expense during the three and six months ended June 30, 2014 and 2013.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Pension and Other Postretirement Benefit Costs	2014		2013		2014		2013
Generation(a)	$	63	$	87	$	139	$	173
ComEd		40		77		96		154
PECO		9		10		21		21
BGE		17		14		33		27
BSC(b)		13		16		26		34

(a) Includes $5 million related to CENG for the period April 1, 2014 to June 30, 2014.

(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.

Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006, management of the pension obligation and regulatory implications. Exelon expects to make qualified pension plan contributions of $317 million to its qualified pension plans in 2014, of which Generation, ComEd, PECO and BGE will contribute $169 million, $119 million, $11 million and $0 million, respectively. Exelon's and Generation's expected qualified pension plan contributions above include $53 million and $51 million, respectively, related to CENG-sponsored plans for the period April 1, 2014 to December 31, 2014. Unlike the qualified pension plans, Exelon's non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $18 million in 2014, of which Generation, ComEd, PECO and BGE will make payments of $9 million, $1 million, $0 million and $1 million, respectively. Exelon's and Generation's expected non-qualified pension plan benefit payments above include $3 million related to CENG-sponsored plans for the period April 1, to December 31, 2014.

Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and certain plans are not funded. Exelon's management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued rate recovery). Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans and considering the impact of recent plan design changes, of approximately $290 million in 2014, of which Generation, ComEd, PECO and BGE expect to contribute $128 million, $121 million, $4 million and $18 million, respectively. Exelon's and Generation's expected other postretirement benefit plan payments above include $5 million related to CENG-sponsored plans for the period April 1, 2014 to December 31, 2014.

Plan Assets

Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.

Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans' liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon's other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

CENG's investment strategy for its qualified pension assets is generally consistent with Exelon's investment strategy as outlined above.

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and six months ended June 30, 2014 and 2013:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Savings Plan Matching Contributions	2014		2013		2014		2013
Exelon(a)	$	19	$	21	$	48	$	43
Generation(a)		10		10		24		21
ComEd		5		5		12		10
PECO		2		2		4		4
BGE		1		2		4		4
BSC(b)		1		2		4		4

Includes $1 million of matching contributions to CENG's 401(k) defined contribution savings plan for the period April 1, 2014 to June 30, 2014.
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Severance And Plants Retirements (exelon and Generation)

6 Months Ended

Jun. 30, 2014

Restructuring Charges [Abstract]

Corporate Restructuring and Plant Retirements (Exelon, Generation, ComEd and PECO)

14. Severance (Exelon, Generation, ComEd, PECO and BGE)

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.

CENG Integration-Related Severance

In connection with the Master Agreement, Generation and CENG recorded a severance accrual in the fourth quarter of 2013 for the anticipated employee position reductions as a result of the integration. The majority of these positions are corporate and support positions at CENG. On April 1, 2014, the date the NOSA was executed, Generation consolidated the CENG severance liability pursuant to the Master Agreement. Generation adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. The estimated amount of severance payments associated with this plan is expected to be approximately $27 million. As of June 30, 2014, management recorded its best estimate of severance benefits, which could be adjusted through the completion of the integration process if additional employee position reductions are identified or if employees resign prior to their agreed upon service termination date. Estimated costs to be incurred after June 30, 2014 are not material.

Exelon and Generation recorded severance benefit costs associated with the employee reductions of $1 million and $2 million within Operating and maintenance expense for the three and six months ended June 30, 2014, respectively, in their Consolidated Statements of Operations and Comprehensive Income.

Amounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration:


Six Months Ended June 30, 2014
Severance Liability		Exelon		Generation
Balance at December 31, 2013	$	2	$	2
Integration of CENG^(a)		19		19
Severance charges		2		2
Payments		(3)		(3)
Balance at June 30, 2014	$	20	$	20

Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. See Note 6 – Investment in CENG for additional information.

Cash payments under the severance plan began in the second quarter of 2014. Substantially all cash payments under the plan are expected to be made by the end of 2014.

Constellation Merger-Related Severance

Six Months Ended June 30, 2014
Severance Liability		Exelon		Generation		ComEd		PECO		BGE
Balance at December 31, 2013	$	53	$	10	$	0	$	0	$	6
Payments		(20)		(2)		0		0		(3)
Balance at June 30, 2014	$	33	$	8	$	0	$	0	$	3

Substantially all cash payments under the plan are expected to be made by the end of 2016.

Ongoing Severance Plans

The Registrants provide severance and health and welfare benefits under Exelon's ongoing severance benefit plans to terminated employees in the normal course of business, which are not directly related to the merger with Constellation or with the integration of CENG. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.

For the three and six months ended June 30, 2014 and 2013, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:

			Exelon		Generation		ComEd		PECO		BGE

Three Months Ending
	June 30, 2014	$	4	$	2	$	0	$	0	$	0
	June 30, 2013	$	1	$	1	$	0	$	0	$	0

Six Months Ending
	June 30, 2014	$	6	$	4	$	0	$	0	$	0
	June 30, 2013	$	2	$	1	$	1	$	0	$	0

For the three and six months ended June 30, 2013, the Registrants recorded the following severance costs associated with these ongoing severance benefits within operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:

Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Stock-Based Compensation Plans [Line Items]

Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)

		Three Months Ended				Six Months Ended
		June 30,				June 30,

Components of Stock-Based Compensation Expense		2014		2013		2014		2013

Performance share awards		$	12	$	5	$	41	$	32
Stock options			1		2		3		13
Restricted stock units			13		12		49		41
Other stock-based awards			1		1		4		3

Total stock-based compensation expense included in
	operating and maintenance expense		27		20		97		89

Income tax benefit			(10)		(8)		(37)		(34)

Total after-tax stock-based compensation expense		$	17	$	12	$	60	$	55

	Three Months Ended				Six Months Ended
	June 30,				June 30,

Subsidiaries	2014		2013		2014		2013

Generation	$	10	$	9	$	38	$	33
ComEd		3		2		7		9
PECO		1		1		4		4
BGE (a)		1		1		5		4
BSC (b)		12		7		43		39

Total (c)	$	27	$	20	$	97	$	89

(a) BGE's stock-based compensation expense (pre-tax) for the six months ended June 30, 2013 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the six months ended June 30, 2013 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above.

(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.

(c) The stock-based compensation expense (pre-tax) for the three and six months ended June 30, 2014 reflects the impact of changes to the retirement eligibility requirements for employees participating in the LTIP. In addition, the stock-based compensation expense at ComEd reflects the adoption of the ComEd Key Manager Long-Term Performance Program in 2013 for certain employees, which is not considered stock-based compensation expense under the applicable authoritative guidance. In 2012, these employees participated in the Exelon Restricted Stock Award Program.

There were no significant stock-based compensation costs capitalized during the three and six months ended June 30, 2014 and 2013.

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 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.

16. Common Stock (Exelon, Generation, ComEd, PECO and BGE)

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. Concurrently, Exelon entered into forward sale agreements requiring Exelon to, at its election, prior to October 29, 2015; i) physically settle the transaction through the issuance of 57.5 million shares of its common stock in exchange for net proceeds at the forward price specified in the agreements of between approximately $1.85 billion and $1.95 billion, after consideration of underwriters discount of approximately $60 million and subject to certain adjustments as provided in the forward sales agreement, or ii) net settle the transaction either through the payment of cash or shares of its common stock based on the then current market value of the shares minus the value of the shares at the forward price, net of the underwriters discount and the daily accretion rate. No amounts have or will be recorded in Exelon's consolidated financial statements until settlement of the forward sale agreements occurs. At June 30, 2014, if Exelon had elected to net share settle the contract, the maximum number of common shares that would have been required to be issued is approximately 4 million shares at a forward price of $33.94. If Exelon elects to cash settle the contract, the transaction costs will be recorded as a charge to earnings in the period in which it becomes probable that Exelon will cash settle. Otherwise, all transaction costs will be reflected as a reduction to the value of the common stock issued in Exelon's Consolidated Balance Sheet. The net proceeds received upon settlement are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes. Until settlement, earnings per share dilution resulting from the forward sales agreement, if any, will be determined under 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. See Note 10 – Debt and Credit Agreements for further information on the equity units.

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

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income Loss [Text Block]

Three Months Ended June 30, 2014
Severance Benefits		Exelon		Generation
Severance charges (a)	$	1	$	1
Total severance benefits	$	1	$	1

Six Months Ended June 30, 2014
Severance Benefits		Exelon		Generation
Severance charges (a)	$	2	$	2
Total severance benefits	$	2	$	2

For The Six Months Ended June 30, 2014			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 Equity Investments		Total
Exelon^(a)
	Beginning balance	$	120	$	2	$	(2,260)	$	(10)	$	108	$	(2,040)
	OCI before reclassifications		(11)		1		246		(1)		11		246
	Amounts reclassified from AOCI^(b)		(62)		0		66		0		(116)		(112)
	Net current-period OCI		(73)		1		312		(1)		(105)		134
	Ending balance	$	47	$	3	$	(1,948)	$	(11)	$	3	$	(1,906)

Generation^(a)
	Beginning balance	$	114	$	2	$	0	$	(10)	$	108	$	214
	OCI before reclassifications		(8)		(1)		0		(1)		11		1
	Amounts reclassified from AOCI^(b)		(62)		0		0		0		(116)		(178)
	Net current-period OCI		(70)		(1)		0		(1)		(105)		(177)
	Ending balance	$	44	$	1	$	0	$	(11)	$	3	$	37

ComEd ^(a)

PECO ^(a)
	Beginning balance	$	0	$	1	$	0	$	0	$	0	$	1
	OCI before reclassifications		0		0		0		0		0		0
	Net current-period OCI		0		0		0		0		0		0
	Ending balance	$	0	$	1	$	0	$	0	$	0	$	1

BGE^(a)

(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

(b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.

	Three Months Ended June 30, 2014
Details about AOCI components			Items reclassified out of AOCI^(a)			Affected line item in the statement where Net Income is presented
			Exelon		Generation

Gains on cash flow hedges
	Energy related hedges	$	63	$	63	Operating revenues
			63		63	Total before tax
			(25)		(25)	Tax (expense)
		$	38	$	38	Net of tax

Gains and (losses) on available for sale securities

Amortization of pension and other
postretirement benefit plan items
	Prior service costs	$	12	$	0	^(b)
	Actuarial losses		(61)		0	^(b)
			(49)		0	Total before tax
			18		0	Tax benefit
		$	(31)	$	0	Net of tax

Equity investments
	Reversal of CENG equity method AOCI	$	193	$	193	Gain on consolidation of CENG
			193		193	Total before tax
			(77)		(77)	Tax benefit
		$	116	$	116	Net of tax

Total Reclassifications
	for the period	$	123	$	154	Net of Tax


	Six Months Ended June 30, 2014
Details about AOCI components			Items reclassified out of AOCI^(a)			Affected line item in the statement where Net Income is presented
			Exelon		Generation

Gains on cash flow hedges
	Energy related hedges	$	102	$	102	Operating revenues
	Other cash flow hedges		0		0	Interest expense
			102		102	Total before tax
			(40)		(40)	Tax (expense)
		$	62	$	62	Net of tax

Gains and (losses) on available for sale securities

Amortization of pension and other
postretirement benefit plan items
	Prior service costs		10		0	^(b)
	Actuarial losses	$	(117)	$	0	^(b)
			(107)		0	Total before tax
			41		0	Tax benefit
		$	(66)	$	0	Net of tax

Equity investments
	Reversal of CENG equity method AOCI	$	193	$	193	Gain on consolidation of CENG
			193		193	Total before tax
			(77)		(77)	Tax benefit
		$	116	$	116	Net of tax

Total Reclassifications
	for the period	$	112	$	178	Net of Tax


	Three Months Ended June 30, 2013
	Details about AOCI components		Items reclassified out of AOCI^(a)			Affected line item in the statement where Net Income is presented
			Exelon		Generation

Gains on cash flow hedges
	Energy related hedges	$	141	$	236	Operating revenues
	Other cash flow hedges		0		1	Interest expense
			141		237	Total before tax
			(52)		(93)	Tax (expense)
		$	89	$	144	Net of tax

	Gains and (losses) on available for sale securities

Amortization of pension and other
postretirement benefit plan items
	Prior service costs	$	(1)	$	0	^(b)
	Actuarial (losses)		(82)		0	^(b)
			(83)		0	Total before tax
			32		0	Tax benefit
		$	(51)	$	0	Net of tax

	Equity investments
	Reversal of CENG equity method AOCI	$	(5)	$	(5)	Equity in losses of unconsolidated affiliates
			(5)		(5)	Total before tax
			2		2	Tax benefit
		$	(3)	$	(3)	Net of tax

	Total Reclassifications
	for the period	$	35	$	141	Net of Tax


	Six Months Ended June 30, 2013
	Details about AOCI components		Items reclassified out of AOCI^(a)			Affected line item in the statement where Net Income is presented
			Exelon		Generation

	Gains on cash flow hedges
	Energy related hedges	$	240	$	459	Operating revenues
	Other cash flow hedges		(1)		1	Interest (expense) or benefit
			239		460	Total before tax
			(92)		(181)	Tax (expense)
		$	147	$	279	Net of tax

	Gains and (losses) on available for sale securities

	Amortization of pension and other
	postretirement benefit plan items
	Prior service costs	$	(1)	$	0	^(b)
	Actuarial (losses)		(165)		0	^(b)
	0		(166)		0	Total before tax
	0		65		0	Tax (expense)
		$	(101)	$	0	Net of tax

	Equity investments
	Reversal of CENG equity method AOCI	$	(8)	$	(8)	Equity in losses of unconsolidated affiliates
			(8)		(8)	Total before tax
			3		3	Tax benefit
		$	(5)	$	(5)	Net of tax

	Total Reclassifications
	for the period	$	41	$	274	Net of Tax

(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income.

(b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 13 for additional details).

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2014		2013		2014		2013
Exelon
Pension and non-pension postretirement benefit plans:
	Prior service benefit reclassified to periodic benefit cost	$	5	$	0	$	5	$	1
	Actuarial loss reclassified to periodic cost		(23)		(32)		(46)		(66)
	Pension and non-pension post retirement benefit plans valuation adjustment		(166)		(1)		(159)		(50)
Change in unrealized loss on cash flow hedges			28		45		48		77
Change in unrealized income on equity investments			77		(5)		70		(23)
Deferred compensation unit valuation adjustment			0		(6)		0		(6)
Total		$	(79)	$	1	$	(82)	$	(67)

Generation
	Change in unrealized loss on cash flow hedges	$	25	$	89	$	44	$	175
	Change in unrealized income on equity investments		77		(5)		70		(23)
	Change in marketable securities		0		0		(2)		0
Total		$	102	$	84	$	112	$	152

^[1]

15. 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 six months ended June 30, 2014 and 2013:

[1]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income.

Common Stock (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Common Stock [Line Items]

Stock-Based Compensation Plans (Exelon, Generation, ComEd, PECO and BGE)

		Three Months Ended				Six Months Ended
		June 30,				June 30,

Components of Stock-Based Compensation Expense		2014		2013		2014		2013

Performance share awards		$	12	$	5	$	41	$	32
Stock options			1		2		3		13
Restricted stock units			13		12		49		41
Other stock-based awards			1		1		4		3

Total stock-based compensation expense included in
	operating and maintenance expense		27		20		97		89

Income tax benefit			(10)		(8)		(37)		(34)

Total after-tax stock-based compensation expense		$	17	$	12	$	60	$	55

	Three Months Ended				Six Months Ended
	June 30,				June 30,

Subsidiaries	2014		2013		2014		2013

Generation	$	10	$	9	$	38	$	33
ComEd		3		2		7		9
PECO		1		1		4		4
BGE (a)		1		1		5		4
BSC (b)		12		7		43		39

Total (c)	$	27	$	20	$	97	$	89

(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.

There were no significant stock-based compensation costs capitalized during the three and six months ended June 30, 2014 and 2013.

Restricted Stock Units

16. Common Stock (Exelon, Generation, ComEd, PECO and BGE)

Equity Securities Offering

Earnings Per Share and Equity (Exelon)

6 Months Ended

Jun. 30, 2014

Earnings Per Share and Equity [Abstract]

Earnings Per Share and Equity (Exelon)

17. Earnings Per Share and Equity (Exelon)

Earnings per Share (Exelon)

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding adjusted to include the potentially dilutive effect of stock options, performance share awards, restricted stock outstanding under Exelon's LTIPs, and Exelon's equity forward sales agreement, which is further described in Note 10 – Debt and Credit Agreements. 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 on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share:

			Three Months Ended June 30,				Six Months Ended June 30,
			2014		2013		2014		2013

Net income attributable to common shareholders		$	522	$	490	$	612	$	486

Average common shares outstanding — basic			860		856		860		856
Potentially dilutive effect of stock options, performance share awards,
	restricted stock, and Exelon's equity forward sales agreement		4		4		3		3

Average common shares outstanding — diluted			864		860		863		859

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 16 million for the three and six months ended June 30, 2014 and 17 million and 18 million for the three and six months ended June 30, 2013, respectively.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of June 30, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases.

Preferred Securities Redemption (Exelon and PECO)

On March 25, 2013, PECO announced that it issued a notice of redemption for all of its outstanding preferred securities with a redemption date of May 1, 2013. PECO had $87 million of cumulative preferred securities that were redeemable at its option at any time for the redemption price established when each series of securities were issued. The redemption premium of $6 million is treated as a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of the earnings per share for Exelon. As a result of the redemption, PECO is now indirectly, wholly-owned by Exelon.

Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Commitments And Contingencies Tables Disclosure [Line Items]

Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)

18. Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)

The following is an update to the current status of commitments and contingencies set forth in Note 22 of the Exelon 2013 Form 10-K.

Commitments

Energy Commitments

As of June 30, 2014, Generation's commitments relating to its purchases from unaffiliated utilities and others of energy, capacity, transmission rights and RECs, are as indicated in the following table:

	Net Capacity			REC			Transmission Rights
	Purchases^(a)			Purchases^(b)			Purchases^(c)			Total

2014		$	208		$	43		$	13		$	264
2015			353			163			13			529
2016			269			122			2			393
2017			208			59			2			269
2018			98			13			2			113
Thereafter			388			4			32			424

Total		$	1,524		$	404		$	64		$	1,992

(a) Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at June 30, 2014, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.

(b) The table excludes renewable energy purchases that are contingent in nature.

(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

ComEd's, PECO's and BGE's electric supply procurement, curtailment services, REC and AEC purchase commitments, as applicable, as of June 30, 2014 are as follows:

			Expiration within
													2019
	Total		2014		2015		2016		2017		2018		and beyond

ComEd
Electric supply procurement^(a)	$	740	$	217	$	232	$	151	$	140	$	0	$	0
Renewable energy and RECs^(b)		1,548		32		73		76		77		78		1,212
PECO
Electric supply procurement^(c)		550		381		169		0		0		0		0
AECs ^(d)		13		1		2		2		2		2		4
BGE
Electric supply procurement ^(e)		1,320		448		632		240		0		0		0
Curtailment services^(f)		136		21		40		34		29		12		0

(a) ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of June 30, 2014, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017.

(b) Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms.

(c) PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2016. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 - Regulatory Matters for additional information.

(d) PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 5 - Regulatory Matters for additional information.

(e) BGE entered into various contracts for the procurement of electricity that expire between 2014 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 5 - Regulatory Matters for additional information.

(f) BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - Regulatory Matters for additional information.

Fuel Purchase Obligations

In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation. Beginning this quarter, all of CENG's nuclear fuel commitments are disclosed within the Generation line below, since CENG is now fully consolidated by Generation. PECO and BGE have commitments to purchase natural gas related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of June 30, 2014, these net commitments were as follows:

			Expiration within
													2019
	Total		2014		2015		2016		2017		2018		and beyond

Generation	$	9,973	$	694	$	1,526	$	1,230	$	1,276	$	929	$	4,318
PECO		411		90		112		93		35		15		66
BGE		618		64		83		82		65		53		271

Other Purchase Obligations

The Registrants' other purchase obligations as of June 30, 2014, which primarily represent commitments for services, materials and information technology, are as follows:

			Expiration within
													2019
	Total		2014		2015		2016		2017		2018		and beyond

Exelon	$	568	$	140	$	171	$	65	$	55	$	37	$	100
Generation		474		110		155		52		47		31		79
ComEd^(a)		53		16		8		5		5		5		14
PECO^(a)		28		12		4		3		1		1		7
BGE^(a)		12		1		4		5		2		0		0

____________________

(a) Purchase obligations include commitments related to smart meter installation. See Note 5 – Regulatory Matters for additional information.

Construction Commitments

Generation has committed to the construction of the Antelope Valley solar PV facility in Los Angeles County, California. The first portion of the project began operations in December 2012, with six additional blocks coming online in 2013. As of June 30, 2014, the facility was fully operational. Generation has no further remaining construction commitments for the project.

On July 3, 2013, Generation executed a Turbine Supply Agreement to expand its Beebe wind project in Michigan. The estimated remaining commitment under the contract is $53 million and achievement of commercial operations is expected in the fourth quarter of 2014.

On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with 120 MW of new natural gas-fired generation to satisfy certain Exelon/Constellation merger commitments. The estimated remaining commitment under the contract is $84 million and achievement of commercial operation is expected in 2015. This project will satisfy a portion of Exelon's commitment to Maryland. See Note 4 – Mergers and Acquisitions of the Exelon 2013 Form 10-K for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Exelon/Constellation merger.

On December 27, 2013, Generation executed a Turbine Supply Agreement for construction of the 40 MW Fourmile Wind project in western Maryland. The estimated remaining commitment under the contract is $38 million and achievement of commercial operations is expected in the fourth quarter 2014. In the first quarter of 2014, Generation approved expansion of the Fourmile project to 40 MW. This project will satisfy a portion of Exelon's 125 MW Tier I land-based renewables commitment in Maryland. See Note 4 – Mergers and Acquisitions of the Exelon 2013 Form 10-K for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Exelon/Constellation merger.

Refer to Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for information on investment programs associated with regulatory mandates, such as ComEd's Infrastructure Investment Plan under EIMA, PECO's Smart Meter Procurement and Installation Plan and BGE's comprehensive smart grid initiative.

Constellation Merger Commitments

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 estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation's competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. Generation's total commitments under the lease agreement are $0 related to 2014 and 2015, and $9 million, $12 million, $12 million, and $270 million related to 2016, 2017, 2018, and 2019 and thereafter.

The direct investment commitment also includes $600 million to $650 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 over a period of 10 years. The MDPSC Order contemplates 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, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. If in the future Exelon determines that it is probable that it will make subsidy, compliance or liquidated damages payments related to the new generation development commitments, Exelon will record a liability at that time. As of June 30, 2014, it is reasonably possible that Exelon will be required to make subsidy or liquidated damages payments of approximately $40 million rather than build one of the generation projects contemplated by the commitments, given that the generation build is dependent upon the passage of legislation and other conditions that Exelon does not control.

Contingencies

Commercial Commitments

The Registrants' commercial commitments as of June 30, 2014, representing commitments potentially triggered by future events were as follows:

		Exelon			Generation			ComEd			PECO			BGE

Letters of credit (non-debt) ^(a)	$	1,514		$	1,470		$	19		$	22		$	1
Guarantees		4,706	^(b)		1,346	^(c)		206	^(d)		181	^(e)		259	^(f)
Nuclear insurance premiums ^(g)		3,559			3,559			0			0			0
Underwriters discount ^(h)		60			0			0			0			0
Total commercial commitments	$	9,839		$	6,375		$	225		$	203		$	260

(a) Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

(b) Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.6 billion at June 30, 2014, which represents the total amount Exelon could be required to fund based on June 30, 2014 market prices.

(c) Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.3 billion at June 30, 2014, which represents the total amount Generation could be required to fund based on June 30, 2014 market prices.

(d) Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.

(e) Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

(f) Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

(g) Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation's nuclear insurance premiums.

(h) Represents the underwriters discount for Exelon's forward equity transaction. See Note 16 – Common Stock of the Combined Notes to Consolidated Financial Statements for further details of the equity securities offering.

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, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of June 30, 2014, the current liability limit per incident was $13.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of June 30, 2014, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in an additional $13.2 billion 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. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon's maximum liability per incident is approximately $2.7 billion, including CENG's related liability.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.6 billion limit for a single incident.

Generation is also 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. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation is $3.6 billion, including CENG's obligation, which is included above in the Commercial Commitments table. See the Nuclear Insurance section within Note 22 – Commitments and Contingencies of the Exelon 2013 Form 10-K for additional details on Generation's nuclear insurance premiums.

As part of the execution of 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 6 – Investment in CENG for additional information on Generation's operations relating to CENG.

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 pays the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. This fee may be adjusted prospectively in order 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 will be delayed significantly. 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 January 3, 2014, the DOE filed a petition for rehearing which was denied by the D.C. Circuit Court on March 18, 2014. Also, on January 3, 2014, the DOE submitted a proposal to Congress to reduce the current SNF disposal fee to zero. On May 9, 2014, the DOE notified Generation that the SNF disposal fee will remain in effect through May 15, 2014, after which time the fee will be set to zero. For the six months ended June 30, 2014, and for the year ended December 31, 2013, Generation incurred expense of $49 million and $136 million, respectively, in SNF disposal fees, recorded in Purchased power and fuel expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income, including Exelon's share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG).

Indemnifications Related to Sale of Sithe (Exelon and Generation)

On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation's sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group's 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy, Inc. (Dynegy).

The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2013. The guarantee expired January 31, 2014. Generation was not required to make payments under the guarantee, and, therefore, has no further obligation related to this guarantee as of June 30, 2014.

Environmental Issues

General. The Registrants' operations have in the past, and may in the future, require substantial expenditures in order 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.

ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, ComEd, PECO or BGE is one of several PRPs that may be responsible for ultimate remediation of each location.

ComEd has identified 42 sites, 16 of which have been approved for cleanup by the Illinois EPA or the U.S. EPA and 26 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 2017.
PECO has identified 26 sites, 16 of which have been approved for cleanup by the PA DEP and 10 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 2020.
BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor's acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. One gas purification site is in the initial stages of investigation at the direction of the MDE.

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. BGE is authorized to and is currently recovering environmental costs for the remediation of former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. ComEd, PECO and BGE have recorded regulatory assets for the recovery of these costs. See Note 5 - Regulatory Matters for additional information regarding the associated regulatory assets.

As of June 30, 2014 and December 31, 2013, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:

June 30, 2014	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	323	$	258
Generation		56		0
ComEd		222		217
PECO		44		41
BGE		1		0
December 31, 2013	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	338	$	273
Generation		56		0
ComEd		234		229
PECO		47		44
BGE		1		0

The Registrants cannot reasonably estimate whether they will incur other 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.

Water Quality

Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation's and CENG's power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, those facilities are Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna.

On May, 19 2014, the U.S. EPA released the final Section 316(b) rule. The rule has not been published in the Federal Register, and will become effective 60 days after publication. The rule requires that a series of studies and analyses be performed to determine the best technology available, followed by an implementation period. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

The rule does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment. The rule provides the state permitting director with significant discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also provides a number of flexible compliance options to reduce impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or other technology at the intake. A number of concerns raised by the electric generation industry about the proposed rule were resolved favorably in the final rule.

New York Facilities. In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved. Each of CENG's New York facilities has filed for its SPDES permit renewal in 2014 and the renewal applications are currently pending with the NYDEC.

Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG, in July 2004 that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem's cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon's and Generation's share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment. However, it is unknown at this time whether implementation of the final EPA rule will result in a requirement to install closed cycle cooling at Salem.

Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its and CENG's generating facilities and its future results of operations, cash flows and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility's economic viability would be called into question. However, the likely impact of the rule has been significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors.

Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. As of June 30, 2014, and December 31, 2013, Generation's remaining groundwater contamination reserve was $15 million and $14 million respectively. In addition, a private party asserted claims relating to groundwater contamination. In February 2014, Generation settled these private party claims for an amount that was not material to the financial condition of Generation.

Air Quality

Cross State Air Pollution Rule (CSAPR). On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court's July 11, 2008 opinion. On July 7, 2011, the U.S. EPA published the final rule, known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states.

Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court's consideration of the matter on the merits. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA has exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. The Court's order was appealed to the U.S. Supreme Court, and on April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit Court decision and upheld CSAPR, and remanded the case to the D.C. Circuit Court to resolve the remaining implementation issues. On June 26, 2014, the U.S. EPA filed a motion with the D.C. Circuit Court seeking to have the stay of the CSAPR lifted, and proposed a three-year tolling of the effective dates under the rule so that the first phase of emission budgets would be implemented on January 1, 2015. The U.S. EPA believes that this would allow sufficient time to complete the remaining aspects of the rulemaking before the implementation of the more stringent second phase of emission budgets that, under the tolling proposal, would begin on January 1, 2017.

The CSAPR restricts entirely the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use. As of June 30, 2014, Generation had $64 million of emission allowances carried at the lower of weighted average cost or market.

EPA Mercury and Air Toxics Standards (MATS). The MATS rule became final on April 16, 2012. The MATS rule reduces emissions of toxic air pollutants, and finalized the new source performance standards for fossil fuel-fired electric utility steam generating units (EGUs). The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will require oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. On April 15, 2014, the D.C Circuit Court issued an opinion upholding MATS in its entirety. On July 14, 2014, three petitions for certiorari were filed with the U.S. Supreme Court seeking review of the D.C. Circuit Court decision upholding MATS.

Exelon, along with the other co-owners of Conemaugh Generating Station have improved the existing scrubbers and installed Selective Catalytic Reduction (SCR) controls to meet the requirements of MATS.

In addition, as of June 30, 2014, Exelon had a $353 million net investment in coal-fired plants in Georgia subject to long-term leases extending through 2028-2032. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, after the impairments recorded in the second quarter of 2013 and 2014, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material. See Note 7 – Impairment of Long-Lived Assets for additional information.

National Ambient Air Quality Standards (NAAQS). The U.S. EPA previously announced that it would complete a review of all NAAQS by 2014. Oral argument in the litigation (State of Miss. v. EPA) of the final 2008 ozone standard occurred in the D.C. Circuit Court in November 2012 and a final Court decision was issued on July 23, 2013 with the 2008 primary ozone standard upheld, but the secondary standard remanded to EPA for reconsideration. Concurrent with litigation of the 2008 ozone standard, the U.S. EPA continues its regular, periodic review of the ozone NAAQS and is expected to propose revisions in the fall of 2014, with preliminary indications that the U.S. EPA will likely propose a tightened standard. It is unclear at this point in time whether the U.S. EPA will be able to respond to the Court remand of the secondary 2008 ozone standard on a timeframe that would be any quicker than that of the U.S. EPA's current, periodic review schedule. In December 2012, the U.S. EPA issued its final revisions to the Agency's particulate matter (PM) NAAQS. In its final rule, the U.S. EPA lowered the annual PM2.5 standard, but declined to issue a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its final rule that by 2020 it expects most areas of the country will be in attainment of the new PM2.5 NAAQS based on currently expected regulations, such as the MATS regulation. It is unclear if the vacatur of the CSAPR, one of the regulations that the U.S. EPA is relying on to assist with future PM reduction, would alter the U.S. EPA's view since either CAIR or a finalized CSAPR regulation would be in effect leading up to 2020. In March 2013, a number of industry coalitions filed a joint lawsuit challenging the new PM2.5 standard. Also during early 2013, the D.C. Circuit remanded several rules for implementation of earlier PM2.5 NAAQS to the U.S. EPA for revision of certain aspects of the rules, with a requirement that the U.S. EPA re-promulgate regulations in conformance with the correct subparts of the Clean Air Act.

In addition to these NAAQS, the U.S. EPA also finalized nonattainment designations for certain areas in the United States for the 2010 one-hour SO2 standard on August 5, 2013, and indicated that additional nonattainment areas will be designated in a future rulemaking. U.S. EPA will require states to submit state implementation plans (SIPs) for nonattainment areas by April 2015. With regard to Texas and Maryland, no nonattainment areas were identified in EPA's final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. The U.S. EPA will follow the approach outlined in a February 2013 U.S. EPA strategy document that establishes a process and timeline for the Agency to address additional designations in states' counties under a future rulemaking. Nonattainment county compliance with the one-hour SO2 standard is required by October 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states' SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard.

Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale. In connection with Exelon's 2001 corporate restructuring, Generation assumed ComEd's rights and obligations with respect to its former generation business, including its rights and obligations under the sale agreement with Midwest Generation and EME.

Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement.

On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code.

In 2012, the Bankruptcy Court approved the rejection of an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations thereunder. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been accrued at December 31, 2012.

On January 17, 2014, Midwest Generation filed a plan supplement to its bankruptcy filing that included a list of contracts to be rejected upon the effective date of the reorganization plan. This list included the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement.

On March 11, 2014, the Bankruptcy Court for the Northern District of Illinois entered its Order Confirming Debtors' Joint Chapter 11 Plan of Reorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME's portfolio of generation, including Midwest Generation and the Joint Chapter 11 Plan of Reorganization (Plan) became effective. As part of the Plan, the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement were rejected. Creditors were provided 30 days from the Effective Date to file rejection damages claims associated with contracts rejected under the Plan.

During the second quarter of 2013, Exelon filed proofs of claim for approximately $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation for the coal rail car lease, ComEd utility payments and certain legal costs. Further, Exelon filed an environmental claim with an unspecified amount that listed the indemnifications that were in place pre-Petition Date and other factors associated with the remediation and a claim under the asbestos cost-sharing agreement with an unspecified amount. As of June 30, 2014, Exelon has not recorded a receivable for the filed proofs of claim because recovery of any amount cannot be assured at this point in the bankruptcy. Exelon will not record claim recoveries unless and until they are realized.

Certain environmental laws and regulations subject current and prior owners of properties or generators of hazardous substances at such properties to liability for remediation costs of environmental contamination. As a prior owner of the generating stations, ComEd (and Generation, through its agreement in Exelon's 2001 corporate restructuring to assume ComEd's rights and obligations associated with its former generation business) could face liability (along with any other potentially responsible parties) for environmental conditions at the stations requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors. ComEd and Generation have reviewed available public information as to potential environmental exposures regarding the Midwest Generation station sites. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q that (i) it has accrued a probable amount of approximately $9 million for estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation of contaminated property at two Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ or remediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Crawford, Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted. For these reasons, ComEd and Generation are unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations and as a result no liability has been recorded as of June 30, 2014. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows.

Generation increased its reserve for asbestos-related bodily injury claims at December 31, 2013 by $25 million, as a result of Midwest Generation listing such agreement in the January 2014 plan supplement as an agreement to be rejected in connection with the Plan. As discussed above, the rejection became effective as part of the Plan. Subsequently, Generation increased its reserve by $15 million pursuant to the second quarter 2014 actuarial study of such claims, of which an estimated $6 million pertains to Midwest Generation's share. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q that it had $53 million recorded related to asbestos bodily injury claims under the contractual indemnity with ComEd. Exelon and Generation may be entitled to damages associated with the rejection of the agreement. These amounts are considered to be contingent gains and would not be recognized until realized.

Solid and Hazardous Waste

Cotter Corporation. The U.S. 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. On February 18, 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 U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the anticipated landfill cover remediation for the site is approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the U.S. 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 final supplemental feasibility study to the U.S. EPA for review. In June 2012, the U.S. EPA requested that the PRPs perform additional analysis and groundwater sampling as part of the supplemental feasibility study, and subsequently requested additional analysis sampling and modeling that will be conducted throughout 2014 and into 2015. In light of these additional requests, it is unknown when the U.S EPA will propose a remedy for public comment, but will likely be sometime in 2015 at the earliest. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote.

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 the Formerly Utilized Sites Remedial Action Program. 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. The DOJ and the PRPs agreed to toll the statute of limitations until August 2014 so that settlement discussions could proceed. Based on Generation's preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the Exelon defendants) and Cotter. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the Exelon defendants' negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits which were subsequently granted. Since May 30, 2012, several related lawsuits have been filed in the same court on behalf of various plaintiffs against Cotter and other defendants, but not Exelon. The allegations in these related lawsuits mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed all state common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under the Price-Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price-Anderson Act. Cotter moved to dismiss the amended complaints and has motions currently pending before the court. At this stage of the litigation, Exelon, Generation, and ComEd cannot estimate a range of loss, if any.

On April 11, 2014, a class action complaint was filed in the U.S. District Court for the Eastern District of Missouri against Cotter and six additional defendants. The complaint alleges that individuals living in the North St. Louis area within a three-mile radius of the West Lake Landfill suffered damage to property or loss of use of property due to the defendants' negligent handling of radioactive materials. Plaintiffs have asserted claims for monetary damages under the Price-Anderson Act. At this stage of the litigation, Exelon and Generation cannot estimate a range of loss, if any.

68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRP's submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated range of costs noted above. Based on Generation's preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site.

Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be approximately $6 million, which has been fully reserved as of June 30, 2014.

Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP's signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP's to conduct a Remedial Investigation and Feasibility Study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE's reasonably possible loss, if any, cannot be determined.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the Federal, regional and state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA's position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations (the Tailoring Rule) relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012 the U.S. EPA declined to lower GHG permit thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in a per curium decision, dismissed industry and state petitions challenging the U.S. EPA's “Tailpipe Rule” for cars and light duty trucks, the endangerment finding for GHG's from stationary sources, and the Tailoring Rule. On October 15, 2013, the U.S. Supreme Court granted industry petitions to review one aspect of the PSD permitting regulations. Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case by case basis. Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants.

On June 25, 2013, President Obama announced “The President's Climate Action Plan,” a summary of executive branch actions intended to: reduce carbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement of the Administration's plan, the President also issued a Memorandum for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions under Section 111 of the Clean Air Act.

The first rulemaking, under Section 111(b) of the Clean Air Act, focuses on establishing carbon regulations for new fossil-fuel power plants. This rulemaking was proposed on September 20, 2013 and is to be finalized “in a timely fashion.” In the proposed rule, U.S. EPA sets separate standards for fossil-fuel fired utility boilers and natural gas fired stationary combustion turbines.

The second rulemaking, under Section 111(d) of the Clean Air Act, focuses on modified, reconstructed and existing fossil power plants. The proposed rule was published in the Federal Register on June 18, 2014 and is open for public comment until October 16, 2014. The Climate Action Plan calls for the rule to be finalized no later than June 1, 2015, and requires that states submit to U.S. EPA their implementation plans no later than June 30, 2016. The proposed rule establishes emission reduction targets for each state and provides flexibility for each state to determine how to achieve its required reductions, including heat rate improvements at coal-fired power plants, fuel switching from coal to gas, renewable generation and new nuclear facilities, demand side energy efficiency, and the use of market-based instruments.

To the extent that the final Section 111(d) rule results in emission reductions from fossil fuel fired plants, and thereby imposes some form of direct or indirect price of carbon in competitive electricity markets, Exelon's overall low carbon generation portfolio results could benefit.

Litigation and Regulatory Matters

Except to the extent noted below, the circumstances set forth in Note 22 of the Exelon 2013 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

Asbestos Personal Injury Claims (Exelon, Generation, PECO and BGE)

Exelon and Generation. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.

At June 30, 2014 and December 31, 2013, Generation had reserved approximately $104 million and $90 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2014, approximately $21 million of this amount related to 247 open claims presented to Generation, while the remaining $83 million of the reserve 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 an adjustment to the reserve is necessary. During the second quarter of 2014, Generation increased its reserve by approximately $15 million, primarily due to increased actual and projected number and severity of claims.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee's disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee's last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court's ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee's last employment-based exposure to asbestos. Currently, Exelon, Generation and PECO are unable to predict whether and to what extent they may experience additional claims in the future as a result of this ruling; as such no increase to the asbestos-related bodily injury liability has been recorded as of June 30, 2014. Increased claims activity resulting from this ruling could have a material adverse effect on Exelon's, Generation's and PECO's future results of operations and cash flows.

BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of "premises liability," alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.

Approximately 486 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation's financial results.

Discovery begins in these cases after they are placed on the trial docket. At present, only two of the pending cases are set for trial. Given the limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:

the identity of the facilities at which the plaintiffs allegedly worked as contractors;
the names of the plaintiffs' employers;
the dates on which and the places where the exposure allegedly occurred; and
the facts and circumstances relating to the alleged exposure.

Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.

Continuous Power Interruption (ComEd)

Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd's case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law.

On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd's service territory, as well as for five other storm systems that affected ComEd's customers during June and July 2011 (Summer 2011 Storm Docket). In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket).

On June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. The ICC held that for the July 11, 2011 storm, 34,559 interruptions were preventable and therefore no waiver should apply. As required by the ICC's Order, ComEd notified relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. In addition, the ICC found that ComEd did not systematically fail in its duty to provide adequate, reliable and safe service. As a result, the ICC rejected the Illinois Attorney General's request for the ICC to open an investigation into ComEd's infrastructure and storm hardening investments.

Following the ICC's June 26, 2013 denial of ComEd's request for rehearing, on June 27, 2013 ComEd filed an appeal of both the summer and winter storm dockets with the Illinois Appellate Court regarding the ICC's interpretation of Section 16-125 of the Illinois Public Utilities Act. On July 31, 2014, the Illinois Appellate Court reaffirmed the ICC's decision in the appeal of the Summer 2011 Storm Docket and dismissed the appeal of the February 2011 Blizzard Docket. The Illinois Appellate Court's opinion has no accounting impact as ComEd previously established a liability in connection with the June 5, 2013 ICC ruling discussed below.

As a result of the ICC's June 5, 2013 ruling, ComEd established a liability, which was not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC's June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd's ultimate liability will be based on actual claims eligible for reimbursement as well as the outcome of the appeal. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd's results of operations or cash flows.

ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd's results of operations and cash flows.

Telephone Consumer Protection Act Lawsuit (ComEd)

On November 19, 2013, a class action complaint was filed in the Northern District of Illinois on behalf of a single individual and a presumptive class that would include all customers that ComEd enrolled in its Outage Alert text message program. The complaint alleges that ComEd violated the Telephone Consumer Protection Act (“TCPA”) by sending approximately 1.2 million text messages to customers without first obtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys' fees, and an order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $ 500 to $ 1,500 per text. On February 21, 2014, ComEd filed a motion to dismiss this class action complaint and intends to contest the allegations of this suit. On June 4, 2014, ComEd's motion to dismiss was denied. As of June 30, 2014, ComEd has a reserve, which is not material, representing its best estimate of probable loss associated with this class action complaint. As ComEd is unable to predict the ultimate outcome of this proceeding, actual damages may differ from the estimated amount recorded, which may be material to ComEd's results of operations, cash flows, and financial position.

Baltimore City Franchise Taxes (BGE)

The City of Baltimore claims that BGE has maintained electric facilities in the City's public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City's claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE's results of operations and cash flows.

General (Exelon, Generation, ComEd, PECO and BGE)

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)

See Note 11 - Income Taxes for information regarding the Registrants' income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Supplemental Financial Information Tables [Line Items]

Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)

19. Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants' Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2014 and 2013:

Three Months Ended June 30, 2014			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	68	$	68	$	0	$	0	$	0
		Non-regulatory agreement units		38		38		0		0		0
	Net unrealized gains on decommissioning trust funds
		Regulatory agreement units		172		172		0		0		0
		Non-regulatory agreement units		128		128		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		10		10		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		(204)		(204)		0		0		0
Total decommissioning-related activities				212		212		0		0		0
Investment income (expense)				7		7		0		(1)		2	^(c)
Long-term lease income				10		0		0		0		0
Interest income (expense) related to uncertain income tax positions				(2)		3		0		0		0
AFUDC - Equity				5		0		0		1		3
Other				11		6		5		1		0

Other, net			$	243	$	228	$	5	$	1	$	5


Six Months Ended June 30, 2014			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	111	$	111	$	0	$	0	$	0
		Non-regulatory agreement units		63		63		0		0		0
	Net unrealized gains on decommissioning trust funds
		Regulatory agreement units		234		234		0		0		0
		Non-regulatory agreement units		141		141		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		20		20		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		(299)		(299)		0		0		0
Total decommissioning-related activities				270		270		0		0		0
Investment income (expense)				8		8		0		(1)		4	^(c)
Long-term lease income				17		0		0		0		0
Interest income related to uncertain income tax positions				7		17		0		0		0
AFUDC - Equity				11		0		3		3		6
Other				35		23		7		1		(1)

Other, net			$	348	$	318	$	10	$	3	$	9

Three Months Ended June 30, 2013			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	47	$	47	$	0	$	0	$	0
		Non-regulatory agreement units		16		16		0		0		0
	Net unrealized losses on decommissioning trust funds
		Regulatory agreement units		(102)		(102)		0		0		0
		Non-regulatory agreement units		(40)		(40)		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		2		2		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		40		40		0		0		0
Total decommissioning-related activities				(37)		(37)		0		0		0
Investment income (expense)				2		0		0		(1)		2	^(c)
Long-term lease income				5		0		0		0		0
Interest expense related to uncertain income tax positions				(1)		(2)		0		0		0
AFUDC - Equity				5		0		3		1		2
Other				9		6		3		0		0

Other, net			$	(17)	$	(33)	$	6	$	0	$	4

Six Months Ended June 30, 2013			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	84	$	84	$	0	$	0	$	0
		Non-regulatory agreement units		30		30		0		0		0
	Net unrealized gains on decommissioning trust funds
		Regulatory agreement units		92		92		0		0		0
		Non-regulatory agreement units		24		24		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		3		3		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		(148)		(148)		0		0		0
Total decommissioning-related activities				85		85		0		0		0
Investment income (expense)				5		(1)		0		(1)		5	^(c)
Long-term lease income				13		0		0		0		0
Interest income related to uncertain income tax positions				24		3		0		0		0
AFUDC - Equity				12		0		6		2		4
Other				16		8		5		2		0

Other, net			$	155	$	95	$	11	$	3	$	9

__________

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

(b) Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants' Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013:


Six Months Ended June 30, 2014	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,015	$	444	$	290	$	112	$	142
Regulatory assets		117		0		57		5		55
Amortization of intangible assets, net		22		22		0		0		0
Amortization of energy contract assets and liabilities ^(a)		113		118		0		0		0
Nuclear fuel ^(b)		499		499		0		0		0
ARO accretion ^(c)		159		159		0		0		0

Total depreciation, amortization, accretion and depletion	$	1,925	$	1,242	$	347	$	117	$	197

Six Months Ended June 30, 2013	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	942	$	402	$	275	$	109	$	128
Regulatory assets		112		0		62		4		47
Amortization of intangible assets, net		22		22		0		0		0
Amortization of energy contract assets and liabilities ^(a)		306		344		0		0		0
Nuclear fuel ^(b)		454		454		0		0		0
ARO accretion ^(c)		136		136		0		0		0

Total depreciation, amortization, accretion and depletion	$	1,972	$	1,358	$	337	$	113	$	175

__________

Six Months Ended June 30, 2014		Exelon		Generation		ComEd		PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs		$	315	$	139	$	96	$	21		$	33
Loss from equity method investments			20		20		0		0			0
Provision for uncollectible accounts			59		8		(8)		28			30
Stock-based compensation costs			68		0		0		0			0
Other decommissioning-related activity ^(a)			(85)		(85)		0		0			0
Energy-related options ^(b)			63		63		0		0			0
Amortization of regulatory asset related to debt costs			5		0		4		1			0
Amortization of rate stabilization deferral			33		0		0		0			33
Amortization of debt fair value adjustment			(26)		(12)		0		0			0
Discrete impacts of EIMA ^(c)			9		0		9		0			0
Amortization of debt costs			19		6		(3)		1			1
Increase in inventory reserve			3		3		1		0			0
Impairment of investments in direct financing leases ^(e)			24		0		0		0			0
Impairment charges ^(f)			86		86		0		0			0
Other			(26)		(19)		0		(1)			(8)

Total other non-cash operating activities		$	567	$	209	$	99	$	50		$	89

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		$	60	$	0	$	61	$	(6)		$	8
Other regulatory assets and liabilities			(25)		0		(30)		(13)			(49)
Other current assets			(157)		13		(5)		(89)	^(h)		51
Other noncurrent assets and liabilities			(158)		(69)		22		(6)			(2)

Total changes in other assets and liabilities		$	(280)	$	(56)	$	48	$	(114)		$	8

Non-cash investing and financing activities:
Fair value of net assets recorded upon CENG
consolidation ^(j)		$	3,400	$	3,400	$	0	$	0		$	0
Issuance of equity units ^(k)			131		0		0		0			0
Uranium procurement ^(l)			38		38		0		0			0
Indemnification of like-kind exchange position ^(m)			0		0		2		0			0

	Total non-cash investing and financing activities:	$	3,569	$	3,438	$	2	$	0		$	0

Six Months Ended June 30, 2013	Exelon		Generation		ComEd			PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	409	$	173	$	154		$	21		$	27
Loss in equity method investments		30		30		0			0			0
Provision for uncollectible accounts		55		10		4			27			14
Stock-based compensation costs		70		0		0			0			0
Other decommissioning-related activity ^(a)		(62)		(62)		0			0			0
Energy-related options ^(b)		65		65		0			0			0
Amortization of regulatory asset related to debt costs		6		0		5			1			0
Amortization of rate stabilization deferral		29		0		0			0			29
Amortization of debt fair value adjustment		(22)		(22)		0			0			0
Discrete impacts from EIMA ^(c)		(126)		0		(126)			0			0
Amortization of debt costs		8		5		2			1			0
Merger integration costs ^(d)		(6)		0		0			0			(6)
Impairment of investments in direct financing leases^(e)		14		0		0			0			0
Increase in inventory reserve		13		13		0			0			0
Impairment charges ^(g)		110		110		0			0			0
Other		(17)		(7)		0			0			(3)

Total other non-cash operating activities	$	576	$	315	$	39		$	50		$	61

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(24)	$	0	$	(61)		$	19		$	18
Other regulatory assets and liabilities		3		0		(28)			(5)			(82)
Other current assets		(123)		(134)		2			(62)	^(h)		99
Other noncurrent assets and liabilities		277		(34)		304	⁽ⁱ⁾		(1)			28

Total changes in other assets and liabilities	$	133	$	(168)	$	217		$	(49)		$	63

Non-cash investing and financing activities:
Consolidated VIE dividend to non-controlling interest	$	63		63		0			0			0
Indemnification of like-kind exchange position ^(l)		0		0		174			0			0

Total non-cash investing and financing activities	$	63	$	63	$	174		$	0		$	0

DOE Smart Grid Investment Grant (Exelon, BGE and PECO). For the six months ended June 30, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $3 million related to PECO's DOE SGIG programs. For the six months ended June 30, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $41 million, $12 million and $29 million, respectively, and reimbursements of $50 million, $16 million and $34 million, respectively, related to PECO's and BGE's DOE SGIG programs. See Note 5 - Regulatory Matters for additional information regarding the DOE SGIG.

_________

(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 of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(c) 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 tariff. See Note 5 – Regulatory Matters for more information.

(d) Relates to integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 5 – Regulatory Matters for more information.

(e) Relates to an other than temporary decline in the estimated residual value of Exelon's direct financing leases. See Note 7 – Impairment of Long-Lived Assets for more information.

(f) Relates to the impairment of long-lived assets at Generation. See Note 7 – Impairment of Long-Lived Assets for additional information.

(g) Relates to the cancellation of uprate projects at Generation. See Note 7 – Impairment of Long-Lived Assets for additional information.

(h) Relates primarily to prepaid utility taxes.

(i) Relates primarily to interest payable related to like-kind exchange tax position. See Note 11 – Income Taxes for discussion of the like-kind exchange tax position.

(j) See Note 6 – Investment in Constellation Energy Nuclear Group, LLC for additional information.

(k) Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 16 – Common Stock for additional information.

(l) Relates to the nuclear fuel procurement contract for the purchase of a fixed quantity of uranium, which was delivered to Generation on June 30, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.

(m) See Note 11 – Income Taxes for discussion of the like-kind exchange tax position.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of June 30, 2014 and December 31, 2013.

June 30, 2014	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	14,369	^(a)	$	7,397	^(a)	$	3,325	$	2,969	$	2,781
Accounts receivable:
Allowance for uncollectible accounts		293			56			71		124		42

December 31, 2013	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	13,713	^(b)	$	7,034	^(b)	$	3,184	$	2,935	$	2,702
Accounts receivable:
Allowance for uncollectible accounts		272			57			62		107		46

___________

(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,411 million.

(b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.

PECO Installment Plan Receivables (Exelon and PECO)

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $21 million as of June 30, 2014 and $19 million as of December 31, 2013. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 – Significant Accounting Policies of the Exelon 2013 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at June 30, 2014 of $20 million consists of $1 million, $4 million and $15 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2013 of $18 million consists of $1 million, $4 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of June 30, 2014 and December 31, 2013 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 – Significant Accounting Policies of the Exelon 2013 Form 10-K.

Segment Information (Exelon, Generation, ComEd, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Segment Information [Line Items]

Segment Information (Exelon, Generation, ComEd, PECO and BGE)

20. Segment Information (Exelon, Generation, ComEd, PECO and BGE)

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 nine reportable segments, ComEd, PECO, BGE and Generation's six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other regions not considered individually significant referred to collectively as “Other Regions”; including the South, West and Canada. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon's CODM evaluates the performance of and allocates resources to ComEd, PECO and BGE based on net income and return on equity.

The CODMs for ComEd, PECO, and BGE evaluate performance and allocate resources for their respective companies based on net income and return on equity for ComEd, PECO, and BGE each as single integrated businesses.

The foundation of Generation's six reportable segments is based on the geographic location of its assets, and is largely representative of the footprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation's six reportable segments are as follows:

Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina.
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO's Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
Other Regions not considered individually significant:
South represents operations in the FRCC, MISO's Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation's South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.
Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO.

The CODMs for Exelon and Generation evaluate the performance of Generation's power marketing activities and allocate resources based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel expense 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 sales to its affiliates, ComEd, PECO and BGE. 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 own generation and fuel costs associated with tolling agreements. Generation's other business activities, including retail and wholesale gas, upstream natural gas, proprietary trading, energy efficiency and demand response, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, and investments in energy-related proprietary technology are not allocated to regions. Further, Generation's other miscellaneous revenues, unrealized mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value as a result of the merger with Constellation and the consolidation of CENG are also not allocated to a region.

An analysis and reconciliation of the Registrants' reportable segment information to the respective information in the consolidated financial statements for the three months ended June 30, 2014 and 2013 is as follows:

Three Months Ended June 30, 2014 and 2013

__________

(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended June 30, 2014 include revenue from sales to PECO of $49 million and sales to BGE of $87 million in the Mid-Atlantic region, and sales to ComEd of $65 million in the Midwest region. For the three months ended June 30, 2013 intersegment revenues for Generation include revenue from sales to PECO of $97 million and sales to BGE of $99 million in the Mid-Atlantic region, sales to ComEd of $121 million in the Midwest region, and $10 million related to the unrealized mark-to-market gains related to the ComEd swap, which eliminate upon consolidation.

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

(c) For the three months ended June 30, 2014 and 2013, utility taxes of $21 million and $18 million, respectively, are included in revenues and expenses for Generation. For the three months ended June 30, 2014 and 2013, utility taxes of $56 million and $56 million, respectively, are included in revenues and expenses for ComEd. For the three months ended June 30, 2014 and 2013, utility taxes of $30 million and $31 million, respectively, are included in revenues and expenses for PECO. For the three months ended June 30, 2014 and 2013, utility taxes of $19 million and $19 million, respectively, are included in revenues and expenses for BGE.

(d) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation's sale of certain products and services by and between Exelon's segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Generation total revenues (three months ended):
	2014						2013
	Revenues from external customers ^(a)		Intersegment revenues		Total Revenues		Revenues from external customers ^(a)		Intersegment revenues		Total Revenues
Mid-Atlantic	$	1,272	$	5	$	1,277	$	1,220	$	9	$	1,229
Midwest		981		0		981		1,076		(5)		1,071
New England		211		1		212		209		(20)		189
New York		194		0		194		175		(1)		174
ERCOT		198		(1)		197		319		(4)		315
Other Regions ^(b)		314		(6)		308		246		(6)		240
Total Revenues for Reportable Segments		3,170		(1)		3,169		3,245		(27)		3,218
Other ^(c)		619		1		620		825		27		852
Total Generation Consolidated Operating Revenues	$	3,789	$	0	$	3,789	$	4,070	$	-	$	4,070

(a) Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

(b) Other regions include the South, West and Canada, which are not considered individually significant.

(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $88 million and $234 million, for the three months ended June 30, 2014 and 2013, respectively, and elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense (three months ended):
	2014						2013
	RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	906	$	14	$	920	$	770	$	(2)	$	768
Midwest		604		1		605		687		(3)		684
New England		88		(24)		64		85		(35)		50
New York		142		6		148		0		14		14
ERCOT		117		(58)		59		143		(31)		112
Other Regions ^(b)		157		(82)		75		111		(52)		59
Total Revenues net of purchased power and fuel expense for Reportable Segments		2,014		(143)		1,871		1,796		(109)		1,687
Other ^(c)		(60)		143		83		328		109		437
Total Generation Revenues net of purchased power and fuel expense	$	1,954	$	0	$	1,954	$	2,124	$	-	$	2,124

(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b) Other regions include the South, West and Canada, which are not considered individually significant.

(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $50 million and $167 million for the three months ended June 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.

Six Months Ended June 30, 2014 and 2013

												Intersegment Eliminations
		Generation ^(a)(b)		ComEd		PECO		BGE		Other ^(c)		Intersegment Eliminations			Exelon
Total revenues ^(d):
	2014	$	8,179	$	2,262	$	1,649	$	1,707	$	619	$	(1,155)	$	13,261
	2013		7,603		2,239		1,567		1,533		615		(1,334)		12,223
Intersegment revenues ^(e):
	2014	$	517	$	1	$	1	$	18	$	618	$	(1,155)	$	0
	2013		710		1		0		8		615		(1,334)		0
Net income (loss):
	2014	$	188	$	209	$	173	$	106	$	(25)	$	0	$	651
	2013		310		14		200		106		(132)		0		498

__________

(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the six months ended June 30, 2014 include revenue from sales to PECO of $ 137 million and sales to BGE of $ 207 million in the Mid-Atlantic region, and sales to ComEd of $ 173 million in the Midwest region. For the six months ended June 30, 2013 intersegment revenues for Generation include revenue from sales to PECO of $238 million in the Mid-Atlantic region and sales to BGE of $212 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.

(b) Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through June 30, 2014.

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

(d) For the six months ended June 30, 2014 and 2013, utility taxes of $45 million and $39 million, respectively, are included in revenues and expenses for Generation. For the six months ended June 30, 2014 and 2013, utility taxes of $119 million and $117 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2014 and 2013, utility taxes of $65 million and $64 million, respectively, are included in revenues and expenses for PECO. For the six months ended June 30, 2014 and 2013, utility taxes of $43 million and $41 million, respectively, are included in revenues and expenses for BGE.

(e) Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generation's sale of certain products and services by and between Exelon's segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Generation total revenues (six months ended):
	2014						2013
	Revenues from external customers ^(a)		Intersegment revenues		Total Revenues		Revenues from external customers ^(a)		Intersegment revenues		Total Revenues
Mid-Atlantic ^(b)	$	2,713	$	(18)	$	2,695	$	2,551	$	1	$	2,552
Midwest		2,239		12		2,251		2,257		2		2,259
New England		756		5		761		600		(8)		592
New York ^(b)		384		(3)		381		350		(7)		343
ERCOT		441		(1)		440		612		(4)		608
Other Regions ^(c)		648		1		649		429		36		465
Total Revenues for Reportable Segments		7,181		(4)		7,177		6,799		20		6,819
Other ^(d)		998		4		1,002		804		(20)		784
Total Generation Consolidated Operating Revenues	$	8,179	$	0	$	8,179	$	7,603	$	0	$	7,603

(a) Includes all wholesale and retail electric sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b) Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through June 30, 2014.

(d) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $180 million and $478 million, for the six months ended June 30, 2014 and 2013, respectively, and elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense (six months ended):
	2014						2013
	RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF
Mid-Atlantic ^(b)	$	1,690	$	(75)	$	1,615	$	1,622	$	(10)	$	1,612
Midwest		1,134		27		1,161		1,397		4		1,401
New England		242		(42)		200		103		(23)		80
New York ^(b)		113		14		127		(16)		8		(8)
ERCOT		272		(130)		142		255		(42)		213
Other Regions ^(c)		307		(127)		180		122		(17)		105
Total Revenues net of purchased power and fuel expense for Reportable Segments		3,758		(333)		3,425		3,483		(80)		3,403
Other ^(d)		(770)		333		(437)		6		80		86
Total Generation Revenues net of purchased power and fuel expense	$	2,988	$	0	$	2,988	$	3,489	$	0	$	3,489

(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b) Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through June 30, 2014.

(d) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $92 million and $341 million, for the six months ended June 30, 2014 and 2013, respectively.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Subsequent Events Disclosure [Line Items]

Subsequent Events (Exelon, PECO and BGE)

6 Months Ended

Jun. 30, 2014

Subsequent Events TextBlock (Exelon, PECO and BGE)

21. Subsequent Events (Exelon, Generation and PECO)

Summer storms during July 2014 interrupted electric service delivery in PECO's service territory. Restoration efforts included significant costs associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies. PECO estimates that restoration efforts will result in $10 million to $20 million of incremental operating and maintenance expense and $10 million to $20 million of incremental capital expenditures for the third quarter of 2014.

On July 29, 2014, Generation entered into a Stock Purchase Agreement (the Purchase Agreement) with Integrys Energy Group, Inc. (Integrys). Pursuant to the Purchase Agreement, Integrys agreed to sell its competitive retail electric and natural gas businesses through a sale of all of the stock of its wholly-owned subsidiary, Integrys Energy Services, Inc. (IES), to Generation for an all cash purchase price of $60 million plus adjusted net working capital at the time of the closing. IES's adjusted net working capital balance was approximately $183 million as of May 31, 2014. Pursuant to the Purchase Agreement, Generation has agreed to use its commercially reasonable efforts to replace the guarantees and other credit support currently being provided by Integrys for IES in support of the ongoing competitive retail businesses and to reimburse Integrys for any payments arising pursuant to such arrangements continuing for any post-closing period. The generation and solar asset businesses of IES are excluded from the transaction.

The transaction is expected to close in the fourth quarter of 2014 or the first quarter of 2015. The closing of the transaction is subject to certain conditions, included, among others, approval by the FERC and expiration or termination of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. Either party may terminate the Purchase Agreement if the transaction has not been consummated by the 6 month anniversary of the date of the Purchase Agreement, subject to an extension of up to 180 days, if necessary, to obtain regulatory approval. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.

Fair Value of Financial Assets and Liabilities (Policies)	6 Months Ended
	Jun. 30, 2014
Fair Value Of Financial Liabilities Recorded At The Carrying Amount [Abstract]
Cash Equivalents Valuation Techniques Used to Determine Fair Value	Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE). The Registrants' cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Nuclear Decommissioning Trust Fund Investments Valuation Techniques Used to Determine Fair Value	Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). The trust fund investments have been established to satisfy Generation's and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds. Generation's and CENG's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies 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 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 are based on quoted prices in active markets and are categorized in Level 1. 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. 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 are determined using a third party valuation that contains significant unobservable inputs and are categorized in Level 3. Equity, balanced and fixed income commingled funds and fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon, Generation and CENG invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. Comingled and mutual funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities. See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments. Middle market lending are investments in loans or managed funds which invest in 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 middle market lending 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. Investments in middle market lending typically cannot be redeemed until maturity of the term loan. As of June 30, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $430 million. These commitments will be funded by Generation's existing nuclear decommissioning trust funds.
Rabbi Trust Investments Valuation Techniques Used to Determine Fair Value	Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE). 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 investments in the Rabbi trusts are included in investments in the Registrants' Consolidated Balance Sheets and consist primarily of mutual funds. These 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. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices.
Mark-to-Market Valuation Techniques Used to Determine Fair Value	Mark-to-Market Derivatives (Exelon, Generation, and ComEd). 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 predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3. Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 9 — Derivative Financial Instruments for further discussion on mark-to-market derivatives. Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon's RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon's business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. 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.
Deferred Compensation Obligations Valuation Techniques Used to Determine Fair Value	Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). 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 notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

Variable Interest Entities (Tables)

6 Months Ended

Jun. 30, 2014

Variable Interest Entity [Line Items]

Schedule of Variable Interest Entities [Table Text Block]

		June 30, 2014						December 31, 2013
		Exelon (a) (b)		Generation (b)		BGE		Exelon (a)		Generation		BGE
Current assets		$	991	$	956	$	28	$	484	$	446	$	28
Noncurrent assets			7,426		7,407		3		1,905		1,884		3
	Total assets	$	8,417	$	8,363	$	31	$	2,389	$	2,330	$	31

Current liabilities		$	815	$	732	$	76	$	566	$	481	$	74
Noncurrent liabilities			2,911		2,738		158		774		562		195
	Total liabilities	$	3,726	$	3,470	$	234	$	1,340	$	1,043	$	269

		June 30, 2014						December 31, 2013
		Exelon		Generation		BGE		Exelon		Generation		BGE
Cash and cash equivalents		$	126	$	126	$	-	$	62	$	62	$	-
Restricted cash			75		47		28		80		52		28
Accounts receivable, net
	Customer		296		296		-		260		260		-
	Other		133		133		-		-		-		-
Inventory
	Fossil fuel		103		103		-		2		2		-
	Materials and supplies		165		165		-		-		-		-
Other current assets			61		54		-		53		42		-
	Total current assets		959		924		28		457		418		28

Property, plant and equipment, net			4,603		4,603		-		1,171		1,171		-
Nuclear decommissioning trust funds			2,030		2,030		-		-		-		-
Goodwill			48		48		-		-		-		-
Other noncurrent assets			125		106		3		127		106		3
	Total noncurrent assets		6,806		6,787		3		1,298		1,277		3
	Total assets	$	7,765	$	7,711	$	31	$	1,755	$	1,695	$	31

Short-term borrowings		$	40	$	40	$	-	$	-	$	-	$	-
Long-term debt due within one year			84		5		72		85		5		70
Accounts payable			243		243		-		170		170		-
Accrued expenses			89		86		4		26		22		4
Mark-to-market derivative liabilities			24		24		-		29		29		-
Unamortized energy contracts			12		12		-		5		5		-
Other current liabilities			165		165		-		5		5		-
	Total current liabilities		657		575		76		320		236		74

Long-term debt			258		84		158		298		86		195
Asset retirement obligations			1,731		1,731		-		-		-		-
Pension obligation^(a)			133		133		-		-		-		-
Non-pension postretirement benefit			136		136		-		-		-		-
Unamortized energy contracts			18		18		-		12		12		-
Other noncurrent liabilities			178		178		-		28		28		-
	Noncurrent liabilities		2,454		2,280		158		338		126		195
	Total liabilities	$	3,111	$	2,855	$	234	$	658	$	362	$	269

Schedule Of Unconsolidated Variable Interest Entities [Text Block]


		Commercial		Equity
		Agreement		Investment
June 30, 2014		VIEs		VIEs		Total
Total assets ^(a)		$	119	$	325	$	444
Total liabilities^(a)			2		120		122
Exelon's ownership interest in VIE^(a)			0		63		63
Other ownership interests in VIE^(a)			117		142		259
Registrants' maximum exposure to loss:
	Carrying amount of equity method investments		0		73		73
	Contract intangible asset		9		0		9
	Debt and payment guarantees		0		3		3
	Net assets pledged for Zion Station decommissioning ^(b)		45		0		45


		Commercial		Equity
		Agreement		Investment
December 31, 2013		VIEs		VIEs		Total
Total assets ^(a)		$	128	$	332	$	460
Total liabilities^(a)			17		123		140
Exelon's ownership interest in VIE^(a)			0		86		86
Other ownership interests in VIE^(a)			111		123		234
Registrants' maximum exposure to loss:
	Carrying amount of equity method investments		7		67		74
	Contract intangible asset		9		0		9
	Debt and payment guarantees		0		5		5
	Net assets pledged for Zion Station decommissioning^(b)		44		0		44

These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon's or Generation's Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
These items represent amounts on Exelon's and Generation's Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $402 million and $458 million as of June 30, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $357 million and $414 million as of June 30, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

Schedule of Restructuring and Related Costs [Text Block]

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

+ References + Details

Merger and Acquisitions (Tables)

6 Months Ended

Jun. 30, 2014

Business Acquisition [Line Items]

Three Months Ended June 30, 2014
Severance Benefits		Exelon		Generation
Severance charges (a)	$	1	$	1
Total severance benefits	$	1	$	1

Six Months Ended June 30, 2014
Severance Benefits		Exelon		Generation
Severance charges (a)	$	2	$	2
Total severance benefits	$	2	$	2

Schedule Of Severance Costs [TableTextBlock]

			Exelon		Generation		ComEd		PECO		BGE

Three Months Ending
	June 30, 2014	$	4	$	2	$	0	$	0	$	0
	June 30, 2013	$	1	$	1	$	0	$	0	$	0

Six Months Ending
	June 30, 2014	$	6	$	4	$	0	$	0	$	0
	June 30, 2013	$	2	$	1	$	1	$	0	$	0

Regulatory Matters (Tables)

6 Months Ended

Jun. 30, 2014

Regulatory Matters [Line Items]

Regulatory assets and liabilities

June 30, 2014		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent
Pension and other postretirement
	benefits	$	208	$	2,510	$	0	$	0	$	0	$	0	$	0		$	0
Deferred income taxes			13		1,495		1		68		0		1,358		12			69
AMI programs			7		222		7		56		0		72		0			94
Under-recovered distribution service
	costs		219		220		219		220		0		0		0			0
Debt costs			10		51		8		49		2		2		1			8
Fair value of BGE long-term debt ^(a)			7		198		0		0		0		0		0			0
Fair value of BGE supply contract^(b)			6		0		0		0		0		0		0			0
Severance			4		11		0		0		0		0		4			11
Asset retirement obligations			1		110		1		73		0		26		0			11
MGP remediation costs			40		196		33		165		6		30		1			1
RTO start-up costs			1		0		1		0		0		0		0			0
Under-recovered uncollectible
	accounts		0		70		0		70		0		0		0			0
Renewable energy			13		121		13		121		0		0		0			0
Energy and transmission programs			17		4		12		0		0		0		5	^(f)		4
Deferred storm costs			3		1		0		0		0		0		3			1
Electric generation-related
	regulatory asset		13		24		0		0		0		0		13			24
Rate stabilization deferral			73		119		0		0		0		0		73			119
Energy efficiency and demand
	response programs		63		148		0		0		0		0		63			148
Merger integration costs			2		7		0		0		0		0		2			7
Conservation voltage reduction			0		1		0		0		0		0		0			1
Other			32		37		9		28		21		7		1			1

Total regulatory assets		$	732	$	5,545	$	304	$	850	$	29	$	1,495	$	178		$	499

June 30, 2014		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Other postretirement benefits		$	53	$	111	$	0	$	0	$	0		$	0	$	0		$	0
Nuclear decommissioning			0		2,917		0		2,427		0			490		0			0
Removal costs			107		1,449		83		1,248		0			0		24			201
Energy efficiency and demand
	response programs		14		2		14		0		0			2		0			0
DLC Program Costs			1		9		0		0		1			9		0			0
Energy efficiency Phase 2			0		32		0		0		0			32		0			0
Electric distribution tax repairs			20		104		0		0		20			104		0			0
Gas distribution tax repairs			8		34		0		0		8			34		0			0
Energy and transmission programs			89		11		19		11		52	^(c)		0		18	^(f)		0
Over-recovered gas and electric
	universal service fund costs		5		0		0		0		5			0		0			0
Revenue subject to refund ^(d)			47		0		47		0		0			0		0			0
Over-recovered gas and electric
	revenue decoupling^(e)		21		0		0		0		0			0		21			0
Other			3		1		1		0		2			0		0			1

Total regulatory liabilities		$	368	$	4,670	$	164	$	3,686	$	88		$	671	$	63		$	202

December 31, 2013		Exelon				ComEd				PECO				BGE

Regulatory assets		Current		Noncurrent		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent
Pension and other postretirement
	benefits	$	221	$	2,794	$	0	$	0	$	0	$	0	$	0		$	0
Deferred income taxes			10		1,459		2		65		0		1,317		8			77
AMI programs			5		159		5		35		0		58		0			66
AMI meter events			0		5		0		0		0		5		0			0
Under-recovered distribution service
	costs		178		285		178		285		0		0		0			0
Debt costs			12		56		9		53		3		3		1			8
Fair value of BGE long-term debt^(a)			0		219		0		0		0		0		0			0
Fair value of BGE supply contract ^(b)			12		0		0		0		0		0		0			0
Severance			16		12		12		0		0		0		4			12
Asset retirement obligations			1		102		1		67		0		25		0			10
MGP remediation costs			40		212		33		178		6		33		1			1
RTO start-up costs			2		0		2		0		0		0		0			0
Under-recovered uncollectible
	accounts		0		48		0		48		0		0		0			0
Renewable energy			17		176		17		176		0		0		0			0
Energy and transmission programs			53		0		52		0		0		0		1	(f)		0
Deferred storm costs			3		3		0		0		0		0		3			3
Electric generation-related
	regulatory asset		13		30		0		0		0		0		13			30
Rate stabilization deferral			71		154		0		0		0		0		71			154
Energy efficiency and demand
	response programs		73		148		0		0		0		0		73			148
Merger integration costs			2		9		0		0		0		0		2			9
Other			31		39		18		26		8		7		4			6

Total regulatory assets		$	760	$	5,910	$	329	$	933	$	17	$	1,448	$	181		$	524

December 31, 2013		Exelon				ComEd				PECO					BGE

Regulatory liabilities		Current		Noncurrent		Current		Noncurrent		Current			Noncurrent		Current			Noncurrent
Other postretirement benefits		$	2	$	43	$	0	$	0	$	0		$	0	$	0		$	0
Nuclear decommissioning			0		2,740		0		2,293		0			447		0			0
Removal costs			99		1,423		78		1,219		0			0		21			204
Energy efficiency and demand
	response programs		53		0		45		0		8			0		0			0
DLC Program Costs			1		10		0		0		1			10		0			0
Energy efficiency phase II			0		21		0		0		0			21		0			0
Electric distribution tax repairs			20		114		0		0		20			114		0			0
Gas distribution tax repairs			8		37		0		0		8			37
Energy and transmission programs			78		0		9		0		58	^(c)		0		11	^(f)		0
Over-recovered gas and electric
	universal service fund costs		8		0		0		0		8			0		0			0
Revenue subject to refund ^(d)			38		0		38		0		0			0		0			0
Over-recovered electric and gas
	revenue decoupling^(e)		16		0		0		0		0			0		16			0
Other			4		0		0		0		3			0		0			0

Total regulatory liabilities		$	327	$	4,388	$	170	$	3,512	$	106		$	629	$	48		$	204

Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt. See Note 10 – Debt and Credit Agreements for additional information.
Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE's supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.
Includes $26 million related to the DSP program, $19 million related to the over-recovered natural gas costs under the PGC and $7 million related to over-recovered electric transmission costs as of June 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.
Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC's order in the 2007 Rate Case. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for further information.
Represents the electric and gas distribution costs recoverable from customers under BGE's decoupling mechanism. As of June 30, 2014, BGE had a regulatory liability of $3 million related to over-recovered electric revenue decoupling and $18 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling.
Relates to $1 million of under-recovered electric supply costs, $4 million associated with the transmission formula rate and $18 million of over-recovered natural gas supply costs as of June 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs, $0 million associated with the transmission formula rate and $11 million of over-recovered natural gas supply costs.

As of June 30, 2014	Exelon		ComEd		PECO		BGE
Purchased receivables^(a)	$	270	$	116	$	75	$	79
Allowance for uncollectible accounts ^(b)		(32)		(17)		(8)		(7)
Purchased receivables, net	$	238	$	99	$	67	$	72

As of December 31, 2013	Exelon		ComEd		PECO		BGE
Purchased receivables^(a)	$	263	$	105	$	72	$	86
Allowance for uncollectible accounts ^(b)		(30)		(16)		(7)		(7)
Purchased receivables, net	$	233	$	89	$	65	$	79

__________

Investment in Constellation Energy Nuclear Group, LLC (Tables)

6 Months Ended

Jun. 30, 2014

Schedule of Equity Method Investments [Line Items]

Schedule of total equity in earnings of investment in CENG

	Three Months			Three Months
	Ended March 31,			Ended March 31,
	2014		2013
Equity investment income	$	(2)	$	15
Amortization of basis difference in CENG		(17)		(27)
Total equity in earnings - CENG	$	(19)	$	(12)

Schedule of Equity Method Investments [Line Items]

Schedule of total equity in earnings of investment in CENG

	Three Months			Three Months
	Ended March 31,			Ended March 31,
	2014		2013
Equity investment income	$	(2)	$	15
Amortization of basis difference in CENG		(17)		(27)
Total equity in earnings - CENG	$	(19)	$	(12)

Impairment of Long-Lived assets (Tables)

6 Months Ended

Jun. 30, 2014

Impaired Long-Lived Assets Held and Used [Line Items]

Schedule of Capital Leased Assets [Table Text Block]

	June 30, 2014		December 31, 2013
Estimated residual value of leased assets	$	685	$	1,465
Less: unearned income		332		767
Net investment in long-term leases	$	353	$	698

Fair Value of Financial Assets and Liabilities (Tables)

6 Months Ended

Jun. 30, 2014

Fair value of financial liabilities recorded at the carrying amount

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	624	$	3	$	621	$	0	$	624
Long-term debt (including amounts due within one year)		20,180		1,150		19,373		1,135		21,658
Long-term debt to financing trusts		648		0		0		668		668
SNF obligation		1,021		0		814		0		814

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	344	$	3	$	341	$	0	$	344
Long-term debt (including amounts due within one year)		19,132		0		18,672		1,079		19,751
Long-term debt to financing trusts		648		0		0		631		631
SNF obligation		1,021		0		790		0		790

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

As of June 30, 2014	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	1,034	$	0	$	0	$	1,034
Nuclear decommissioning trust fund investments
Cash equivalents		151		66		0		217
Equity
Individually held		2,572		0		0		2,572
Exchange traded funds		164		0		0		164
Commingled funds		0		2,529		0		2,529
Equity funds subtotal		2,736		2,529		0		5,265
Balanced funds - commingled funds		0		273		0		273
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		990		0		0		990
Debt securities issued by states of the United States
and political subdivisions of the states		0		416		0		416
Debt securities issued by foreign governments		0		114		0		114
Corporate debt securities		0		2,059		181		2,240
Federal agency mortgage-backed securities		0		84		0		84
Commercial mortgage-backed securities (non-agency)		0		43		0		43
Residential mortgage-backed securities (non-agency)		0		3		0		3
Mutual funds		0		18		0		18
Commingled funds		0		325		0		325
Fixed income subtotal		990		3,062		181		4,233
Middle market lending		0		0		376		376
Private Equity		0		0		35		35
Other debt obligations		0		24		0		24
Nuclear decommissioning trust fund investments subtotal^(b)		3,877		5,954		592		10,423

Pledged assets for Zion Station decommissioning
Cash equivalents		0		45		0		45
Equity
Individually held		4		2		0		6
Equity funds subtotal		4		2		0		6
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		12		3		0		15
Debt securities issued by states of the United States
and political subdivisions of the states		0		19		0		19
Corporate debt securities		0		172		0		172
Commingled funds		0		5		0		5
Fixed income subtotal		12		199		0		211
Middle market lending		0		0		133		133
Pledged assets for Zion Station decommissioning subtotal^(c)		16		246		133		395

Rabbi trust investments^(e)
Cash equivalents		2		0		0		2
Mutual funds^(d)		43		0		0		43
Rabbi trust investments subtotal		45		0		0		45

Commodity derivative assets
Economic hedges		434		2,969		1,413		4,816
Proprietary trading		178		712		184		1,074
Effect of netting and allocation of collateral^(f)		(569)		(3,119)		(1,127)		(4,815)
Commodity derivative assets subtotal		43		562		470		1,075

Interest rate and foreign currency derivative assets		24		40		0		64
Effect of netting and allocation of collateral		(21)		(7)		0		(28)
Interest rate and foreign currency derivative assets subtotal		3		33		0		36

Other investments		13		0		10		23

Total assets		5,031		6,795		1,205		13,031

Liabilities
Commodity derivative liabilities
Economic hedges		(434)		(2,803)		(1,465)		(4,702)
Proprietary trading		(182)		(707)		(176)		(1,065)
Effect of netting and allocation of collateral^(f)		618		3,408		1,279		5,305
Commodity derivative liabilities subtotal		2		(102)		(362)		(462)

Interest rate and foreign currency derivative liabilities		(24)		(34)		0		(58)
Effect of netting and allocation of collateral		24		6		0		30
Interest rate and foreign currency derivative liabilities subtotal		0		(28)		0		(28)

Deferred compensation obligation		0		(104)		0		(104)

Total liabilities		2		(234)		(362)		(594)

Total net assets	$	5,033	$	6,561	$	843	$	12,437

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents^(a)	$	1,230	$	0	$	0	$	1,230
Nuclear decommissioning trust fund investments
Cash equivalents		459		0		0		459
Equity
Individually held		1,776		0		0		1,776
Exchange traded funds		115		0		0		115
Commingled funds		0		2,271		0		2,271
Equity funds subtotal		1,891		2,271		0		4,162
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		882		0		0		882
Debt securities issued by states of the United States
and political subdivisions of the states		0		294		0		294
Debt securities issued by foreign governments		0		87		0		87
Corporate debt securities		0		1,753		31		1,784
Federal agency mortgage-backed securities		0		10		0		10
Commercial mortgage-backed securities (non-agency)		0		40		0		40
Residential mortgage-backed securities (non-agency)		0		7		0		7
Mutual funds		0		18		0		18
Fixed income subtotal		882		2,209		31		3,122
Middle market lending		0		0		314		314
Private Equity		0		0		5		5
Other debt obligations		0		14		0		14
Nuclear decommissioning trust fund investments subtotal^(b)		3,232		4,494		350		8,076

Pledged assets for Zion decommissioning
Cash equivalents		0		26		0		26
Equity
Individually held		16		0		0		16
Equity funds subtotal		16		0		0		16
Fixed income
Debt securities issued by the U.S. Treasury and other
U.S. government corporations and agencies		45		4		0		49
Debt securities issued by states of the United States
and political subdivisions of the states		0		20		0		20
Corporate debt securities		0		227		0		227
Fixed income subtotal		45		251		0		296
Middle market lending		0		0		112		112
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal^(c)		61		278		112		451

Rabbi trust investments^(e)
Cash equivalents		2		0		0		2
Mutual funds^(d)		54		0		0		54
Rabbi trust investments subtotal		56		0		0		56

Commodity derivative assets
Economic hedges		493		2,582		885		3,960
Proprietary trading		324		1,315		122		1,761
Effect of netting and allocation of collateral^(f)		(863)		(3,131)		(430)		(4,424)
Commodity derivative assets subtotal		(46)		766		577		1,297

Interest rate and foreign currency derivative assets		30		39		0		69
Effect of netting and allocation of collateral		(30)		(2)		0		(32)
Interest rate and foreign currency derivative assets subtotal		0		37		0		37

Other Investments		0		0		15		15
Total assets		4,533		5,575		1,054		11,162

Liabilities
Commodity derivative liabilities
Economic hedges		(540)		(1,890)		(590)		(3,020)
Proprietary trading		(328)		(1,256)		(119)		(1,703)
Effect of netting and allocation of collateral^(f)		869		3,007		404		4,280
Commodity derivative liabilities subtotal		1		(139)		(305)		(443)

Interest rate and foreign currency derivative liabilities		(31)		(17)		0		(48)
Effect of netting and allocation of collateral		31		1		0		32
Interest rate and foreign currency derivative liabilities subtotal		0		(16)		0		(16)

Deferred compensation obligation		0		(114)		0		(114)

Total liabilities		1		(269)		(305)		(573)

Total net assets	$	4,534	$	5,306	$	749	$	10,589

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(e) Excludes $34 million and $32 million of the cash surrender value of life insurance investments at June 30, 2014 and December 31, 2013, respectively.

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

Three Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2014		$	486	$	137	$	119		$	10	$	752
Total realized / unrealized gains (losses)
	Included in net income		2		0		(48)	^(a)		0		(46)
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		8		0		34			0		42
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral			0		0		34			0		34
Purchases, sales, issuances and settlements
	Purchases		109		13		5			0		127
	Sales		(1)		(21)		(4)			0		(26)
	Settlements		(12)		0		0			0		(12)
Transfers into Level 3			0		0		(4)			0		(4)
Transfers out of Level 3			0		0		(28)			0		(28)

Balance as of June 30, 2014		$	592	$	133	$	108		$	10	$	843
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2014	$	2	$	0	$	19		$	0	$	21

Six Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2013		$	350	$	112	$	272		$	15	$	749
Total realized / unrealized gains (losses)
	Included in net income		3		0		(360)	^(a)		0		(357)
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		11		0		59			0		70
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral			0		0		178			0		178
Purchases, sales, issuances and settlements
	Purchases		249		42		15			2		308
	Sales		(2)		(25)		(6)			0		(33)
	Settlements		(19)		0		0			0		(19)
Transfers into Level 3			0		0		(30)			0		(30)
Transfers out of Level 3			0		0		(20)			(7)		(27)

Balance as of June 30, 2014		$	592	$	133	$	108		$	10	$	843
The amount of total losses included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended June 30, 2014	$	2	$	0	$	(427)		$	0	$	(425)

Three Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2013		$	210	$	104	$	260		$	9	$	583
Total realized / unrealized gains (losses)
	Included in net income		1		0		158	^(a)		0		159
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		8		0		(10)	^(b)		0		(2)
	Included in payable for Zion Station
	decommissioning		0		1		0			0		1
Change in collateral			0		0		10			0		10
Purchases, sales, issuances and settlements
	Purchases		35		11		13			2		61
	Sales		(11)		(5)		(4)			0		(20)
	Settlements		(3)		0		0			0		(3)
Transfers into Level 3			0		0		3			0		3
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	431		$	11	$	793
The amount of total losses included in income
	attributed to the change in unrealized losses related to assets and liabilities held for the three months ended June 30, 2013	$	1	$	0	$	187		$	0	$	188

Six Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2012		$	183	$	89	$	367		$	17	$	656
Total realized / unrealized gains (losses)
	Included in net income		2		0		31	^(a)		0		33
	Included in other comprehensive income		0		0		0			0		0
	Included in regulatory assets		9		0		(18)	^(b)		0		(9)
	Included in payable for Zion Station
	decommissioning		0		1		0			0		1
Change in collateral			0		0		43			0		43
Purchases, sales, issuances and settlements
	Purchases		67		33		8	^(c)		2		110
	Sales		(13)		(12)		(8)			(8)		(41)
	Settlements		(8)		0		0			0		(8)
Transfers into Level 3			0		0		7			0		7
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	431		$	11	$	793
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2013	$	1	$	0	$	108		$	0	$	109

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


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

Total gains (losses) included in income for the three months ended
	June 30, 2014	$	(62)	$	14	$	2
Total gains (losses) included in income for the six months ended
	June 30, 2014	$	(330)	$	(30)	$	3
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended June 30, 2014	$	(10)	$	29	$	2
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the six months ended June 30, 2014	$	(435)	$	8	$	2

		Operating Revenue		Purchased Power and Fuel		Other, net^(a)
Total gains included in income for the three months
	ended June 30, 2013	$	137	$	21	$	1
Total gains (losses) included in income for the six months ended
	June 30, 2013	$	(22)	$	53	$	2
Change in the unrealized gains relating to assets and
	liabilities held for the three months ended June 30, 2013	$	156	$	31	$	1
Change in the unrealized gains relating to assets and
	liabilities held for the six months ended June 30, 2013	$	39	$	69	$	1

(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

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

Type of trade	Fair Value at June 30, 2014 (c)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) (a)	$	82	Discounted Cash Flow	Forward power price	$	16		-	$	170	(d)
			Discounted Cash Flow	Forward gas price	$	2.19		-	$	19.84	(d)
			Option Model	Volatility percentage		8	%	-		260	%

Mark-to-market derivatives – Proprietary trading (Generation) (a)	$	8	Discounted Cash Flow	Forward power price	$	13		-	$	168	(d)
			Option Model	Volatility percentage		8	%	-		260	%

Mark-to-market derivatives (ComEd)	$	(134)	Discounted Cash Flow	Forward heat rate (b)		8	x	-		9	x
				Marketability reserve		3.5	%	-		8	%
				Renewable factor		86	%	-		123	%

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
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 fair values do not include cash collateral held on level three positions of $152 million as of June 30, 2014.

The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas economic hedges would be approximately $106 and $10.29, respectively, and would be approximately $93 for power proprietary trading.

Type of trade	Fair Value at December 31, 2013^(c)		Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives – Economic Hedges (Generation) ^(a)	$	488	Discounted Cash Flow	Forward power price	$	8		-	$	176	^(d)
			Discounted Cash Flow	Forward gas price	$	2.98		-	$	16.63	^(d)
			Option Model	Volatility percentage		15	%	-		142	%

Mark-to-market derivatives – Proprietary trading (Generation)^(a)	$	3	Discounted Cash Flow	Forward power price	$	10		-	$	176	^(d)
			Option Model	Volatility percentage		14	%	-		19	%

Mark-to-market derivatives (ComEd)	$	(193)	Discounted Cash Flow	Forward heat rate ^(b)		8	x	-		9	x
				Marketability reserve		3.5	%	-		8	%
				Renewable factor		84	%	-		128	%

The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
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 fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013
The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively.

Fair value of financial liabilities recorded at the carrying amount

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	53	$	0	$	53	$	0	$	53
Long-term debt (including amounts due within one year)		7,507		0		6,881		1,135		8,016
SNF obligation		1,021		0		814		0		814

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	22	$	0	$	22	$	0	$	22
Long-term debt (including amounts due within one year)		7,729		0		6,586		1,062		7,648
SNF obligation		1,021		0		790		0		790

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

As of June 30, 2014	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	65	$	0	$	0	$	65
Nuclear decommissioning trust fund investments
Cash equivalents		151		66		0		217
Equity
Individually held		2,572		0		0		2,572
Exchange traded funds		164		0		0		164
Commingled funds		0		2,529		0		2,529
Equity funds subtotal		2,736		2,529		0		5,265
Balanced funds - commingled funds		0		273		0		273
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		990		0		0		990
Debt securities issued by states of the United States and
political subdivisions of the states		0		416		0		416
Debt securities issued by foreign governments		0		114		0		114
Corporate debt securities		0		2,059		181		2,240
Federal agency mortgage-backed securities		0		84		0		84
Commercial mortgage-backed securities (non-agency)		0		43		0		43
Residential mortgage-backed securities (non-agency)		0		3		0		3
Mutual funds		0		18		0		18
Commingled funds		0		325		0		325
Fixed income subtotal		990		3,062		181		4,233
Middle market lending		0		0		376		376
Private Equity		0		0		35		35
Other debt obligations		0		24		0		24
Nuclear decommissioning trust fund investments subtotal^(b)		3,877		5,954		592		10,423

Pledged assets for Zion Station decommissioning
Cash equivalents		0		45		0		45
Equity
Individually held		4		2		0		6
Equity funds subtotal		4		2		0		6
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		12		3		0		15
Debt securities issued by states of the United States and
political subdivisions of the states		0		19		0		19
Corporate debt securities		0		172		0		172
Commingled funds		0		5		0		5
Fixed income subtotal		12		199		0		211
Middle market lending		0		0		133		133
Pledged assets for Zion Station decommissioning subtotal^(c)		16		246		133		395

Rabbi trust investments^(d)
Cash equivalents		1		0		0		1
Mutual funds		14		0		0		14
Rabbi trust investments subtotal		15		0		0		15

Commodity derivative assets
Economic hedges		434		2,969		1,413		4,816
Proprietary trading		178		712		184		1,074
Effect of netting and allocation of collateral^(e)		(569)		(3,119)		(1,127)		(4,815)
Commodity derivative assets subtotal		43		562		470		1,075

Interest rate and foreign currency derivative assets		24		22		0		46
Effect of netting and allocation of collateral		(21)		(7)		0		(28)
Interest rate and foreign currency derivative assets subtotal		3		15		0		18

Other investments		13		0		10		23

Total assets		4,032		6,777		1,205		12,014

Liabilities
Commodity derivative liabilities
Economic hedges		(434)		(2,803)		(1,331)		(4,568)
Proprietary trading		(182)		(707)		(176)		(1,065)
Effect of netting and allocation of collateral^(e)		618		3,408		1,279		5,305
Commodity derivative liabilities subtotal		2		(102)		(228)		(328)

Interest rate and foreign currency derivative liabilities		(24)		(28)		0		(52)
Effect of netting and allocation of collateral		24		6		0		30
Interest rate and foreign currency derivative liabilities subtotal		0		(22)		0		(22)

Deferred compensation obligation		0		(29)		0		(29)

Total liabilities		2		(153)		(228)		(379)

Total net assets	$	4,034	$	6,624	$	977	$	11,635

As of December 31, 2013	Level 1		Level 2		Level 3			Total
Assets
Cash equivalents^(a)	$	1,006	$	0	$	0	$	1,006
Nuclear decommissioning trust fund investments
Cash equivalents		459		0		0		459
Equity
Individually held		1,776		0		0		1,776
Exchange traded funds		115		0		0		115
Commingled funds		0		2,271		0		2,271
Equity funds subtotal		1,891		2,271		0		4,162
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		882		0		0		882
Debt securities issued by states of the United States and
political subdivisions of the states		0		294		0		294
Debt securities issued by foreign governments		0		87		0		87
Corporate debt securities		0		1,753		31		1,784
Federal agency mortgage-backed securities		0		10		0		10
Commercial mortgage-backed securities (non-agency)		0		40		0		40
Residential mortgage-backed securities (non-agency)		0		7		0		7
Mutual funds		0		18		0		18
Fixed income subtotal		882		2,209		31		3,122
Middle market lending		0		0		314		314
Private Equity		0		0		5		5
Other debt obligations		0		14		0		14
Nuclear decommissioning trust fund investments subtotal^(b)		3,232		4,494		350		8,076

Pledged assets for Zion Station decommissioning
Cash equivalents		0		26		0		26
Equity
Individually held		16		0		0		16
Equity funds subtotal		16		0		0		16
Fixed income
Debt securities issued by the U.S. Treasury and other U.S.
government corporations and agencies		45		4		0		49
Debt securities issued by states of the United States and
political subdivisions of the states		0		20		0		20
Corporate debt securities		0		227		0		227
Fixed income subtotal		45		251		0		296
Middle market lending		0		0		112		112
Other debt obligations		0		1		0		1
Pledged assets for Zion Station decommissioning subtotal^(c)		61		278		112		451

Rabbi trust investments^(d)
Mutual funds		13		0		0		13
Rabbi trust investments subtotal		13		0		0		13

Commodity derivative assets
Economic hedges		493		2,582		885		3,960
Proprietary trading		324		1,315		122		1,761
Effect of netting and allocation of collateral^(e)		(863)		(3,131)		(430)		(4,424)
Commodity and foreign currency assets subtotal		(46)		766		577		1,297

Interest rate and foreign currency derivative assets		30		32		0		62
Effect of netting and allocation of collateral		(30)		(2)		0		(32)
Interest rate and foreign currency derivative assets subtotal		0		30		0		30

Other investments		0		0		15		15

Total assets		4,266		5,568		1,054		10,888

Liabilities
Commodity derivative liabilities
Economic hedges		(540)		(1,890)		(397)		(2,827)
Proprietary trading		(328)		(1,256)		(119)		(1,703)
Effect of netting and allocation of collateral^(e)		869		3,007		404		4,280
Commodity derivative liabilities subtotal		1		(139)		(112)		(250)

Interest rate derivative liabilities		(31)		(13)		0		(44)
Effect of netting and allocation of collateral		31		1		0		32
Interest rate and foreign currency derivative liabilities		0		(12)		0		(12)

Deferred compensation obligation		0		(29)		0		(29)

Total liabilities		1		(180)		(112)		(291)

Total net assets	$	4,267	$	5,388	$	942	$	10,597

(a) Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

(d) Excludes $10 million of the cash surrender value of life insurance investments at both June 30, 2014 and December 31, 2013.

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

Three Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2014		$	486	$	137	$	287		$	10	$	920
Total realized / unrealized gains (losses)
	Included in net income		2		0		(48)	^(a)		0		(46)
	Included in noncurrent payables to affiliates		8		0		0			0		8
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral			0		0		34			0		34
Purchases, sales, issuances and settlements
	Purchases		109		13		5			0		127
	Sales		(1)		(21)		(4)			0		(26)
	Settlements		(12)		0		0			0		(12)
Transfers into Level 3			0		0		(4)			0		(4)
Transfers out of Level 3			0		0		(28)			0		(28)

Balance as of June 30, 2014		$	592	$	133	$	242		$	10	$	977
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the three months ended June 30, 2014	$	2	$	0	$	19		$	0	$	21

Six Months Ended June 30, 2014		Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning	Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2013		$	350	$	112	$	465		$	15	$	942
Total realized / unrealized gains (losses)
	Included in net income		3		0		(360)	^(a)		0		(357)
	Included in noncurrent payables to affiliates		11		0		0			0		11
	Included in payable for Zion Station decommissioning		0		4		0			0		4
Change in collateral					0		178			0		178
Purchases, sales, issuances and settlements
	Purchases		249		42		15			2		308
	Sales		(2)		(25)		(6)			0		(33)
	Settlements		(19)		0		0			0		(19)
Transfers into Level 3			0		0		(30)			0		(30)
Transfers out of Level 3			0		0		(20)			(7)		(27)

Balance as of June 30, 2014		$	592	$	133	$	242		$	10	$	977
The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2014	$	2	$	0	$	(427)		$	0	$	(425)

Three Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of March 31, 2013		$	210	$	104	$	420		$	9	$	743
Total realized / unrealized gains (losses)
	Included in net income		1		0		168	^(a)(b)		0		169
	Included in other comprehensive income		0		0		(95)	^(b)		0		(95)
	Included in noncurrent payables to affiliates		8		0		0			0		8
	Included in payable for Zion Station decommissioning		0		1		0			0		1
Changes in collateral			0		0		10			0		10
Purchases, sales, issuances and settlements
	Purchases		35		11		13			2		61
	Sales		(11)		(5)		(4)			0		(20)
	Settlements		(3)		0		0			0		(3)
Transfers into Level 3			0		0		3			0		3
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	516		$	11	$	878

The amount of total losses included in income
	attributed to the change in unrealized losses related to assets and liabilities held for the three months ended June 30, 2013	$	1	$	0	$	183		$	0	$	184

Six Months Ended June 30, 2013		Nuclear Decommissioning Trust Fund Investments		Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives			Other Investments		Total
Balance as of December 31, 2012		$	183	$	89	$	660		$	17	$	949
Total realized / unrealized gains (losses)
	Included in net income		2		0		24	^(a)(b)		0		26
	Included in other comprehensive income		0		0		(219)	^(b)		0		(219)
	Included in noncurrent payables to affiliates		9		0		0					9
	Included in payable for Zion Station decommissioning		0		1		0			0		1
Changes in collateral			0		0		43			0		43
Purchases, sales, issuances and settlements												0
	Purchases		67		33		8	^(c)		2		110
	Sales		(13)		(12)		(8)			(8)		(41)
	Settlements		(8)		0		0			0		(8)
Transfers into Level 3			0		0		7			0		7
Transfers out of Level 3			0		0		1			0		1

Balance as of June 30, 2013		$	240	$	111	$	516		$	11	$	878

The amount of total gains included in income
	attributed to the change in unrealized gains related to assets and liabilities held for the six months ended June 30, 2013	$	1	$	0	$	97		$	0	$	98

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

(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

		Operating Revenue		Purchased Power and Fuel		Other, net (a)
Total gains (losses) included in net income for the three months		$	(62)	$	14	$	2
	ended June 30, 2014
Total losses included in net income for the six months
	ended June 30, 2014	$	(330)	$	(30)	$	3
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the three months ended June 30, 2014	$	(10)	$	29	$	2
Change in the unrealized gains (losses) relating to assets and liabilities
	held for the six months ended June 30, 2014	$	(435)	$	8	$	2

		Operating Revenue		Purchased Power and Fuel		Other, net (a)
Total gains included in net income for the three months		$	148	$	20	$	1
	ended June 30, 2013
Total gains (losses) included in net income for the six months		$	(28)	$	52	$	2
	ended June 30, 2013
Change in the unrealized gains relating to assets and		$	153	$	30	$	1
	liabilities held for the three months ended June 30, 2013
Change in the unrealized gains relating to assets and		$	29	$	68	$	1
	liabilities held for the nine months ended June 30, 2013

(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

Fair value of financial liabilities recorded at the carrying amount

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	498	$	0	$	498	$	0	$	498
Long-term debt (including amounts due within one year)		5,708		0		6,452		0		6,452
Long-term debt to financing trust		206		0		0		211		211

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	184	$	0	$	184	$	0	$	184
Long-term debt (including amounts due within one year)		5,675		0		6,238		17		6,255
Long-term debt to financing trust		206		0		0		202		202

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

As of June 30, 2014		Level 1		Level 2		Level 3		Total
Assets
Rabbi trust investments
Mutual funds		$	1	$	0	$	0	$	1
	Rabbi trust investments subtotal		1		0		0		1

Total assets		$	1	$	0	$	0	$	1

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities^(a)			0		0		(134)		(134)

Total liabilities			0		(8)		(134)		(142)

Total net assets (liabilities)		$	1	$	(8)	$	(134)	$	(141)

As of December 31, 2013		Level 1		Level 2		Level 3		Total
Assets
Rabbi trust investments
Mutual funds		$	5	$	0	$	0	$	5
	Rabbi trust investments subtotal		5		0		0		5

Total assets			5		0		0		5

Liabilities
Deferred compensation obligation			0		(8)		0		(8)
Mark-to-market derivative liabilities^(a)			0		0		(193)		(193)

Total liabilities			0		(8)		(193)		(201)

Total net assets (liabilities)		$	5	$	(8)	$	(193)	$	(196)

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

Three Months Ended June 30, 2014	Mark-to-Market Derivatives
Balance as of March 31, 2014	$	(168)
Total realized / unrealized gains included in regulatory assets^(a)		34
Balance as of June 30, 2014	$	(134)

Six Months Ended June 30, 2014	Mark-to-Market Derivatives
Balance as of December 31, 2013	$	(193)
Total realized / unrealized gains included in regulatory assets^(b)		59
Balance as of June 30, 2014	$	(134)

Includes $34 million decreases in the fair value partially offset by immaterial realized losses due to settlements recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2014.
Includes $64 million of decreases in the fair value partially offset by realized gains due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2014.

Three Months Ended June 30, 2013	Mark-to-Market Derivatives
Balance as of March 31, 2013	$	(160)
Total realized / unrealized gains included in regulatory assets^(a)(b)		75
Balance as of June 30, 2013	$	(85)

Six Months Ended June 30, 2013	Mark-to-Market Derivatives
Balance as of December 31, 2012	$	(293)
Total realized / unrealized gains included in regulatory assets^(a)(b)		208
Balance as of June 30, 2013	$	(85)

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

Includes $3 million of increases in fair value and $11 million of decreases in fair value and realized gains due to settlements of $82 million and $215 million of associated with ComEd's financial swap contract with Generation for the three and six months ended June 30, 2013, respectively. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements.
Includes $9 million and $20 million of increases in the fair value and realized losses due to settlements of $1 million and $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and six months ended June 30, 2013, respectively.

Fair value of financial liabilities recorded at the carrying amount

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)	$	2,197	$	0	$	2,436	$	0	$	2,436
Long-term debt to financing trusts		184		0		0		198		198

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)	$	2,197	$	0	$	2,358	$	0	$	2,358
Long-term debt to financing trusts		184		0		0		180		180

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

As of June 30, 2014	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	50	$	0	$	0	$	50
Rabbi trust investments^(a)
Mutual funds		9		0		0		9
Rabbi trust investments subtotal		9		0		0		9

Total assets		59		0		0		59

Liabilities
Deferred compensation obligation		0		(15)		0		(15)

Total liabilities		0		(15)		0		(15)

Total net assets (liabilities)	$	59	$	(15)	$	0	$	44

As of December 31, 2013	Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	175	$	0	$	0	$	175
Rabbi trust investments^(a)
Mutual funds		9		0		0		9
Rabbi trust investments subtotal		9		0		0		9

Total assets		184		0		0		184

Liabilities
Deferred compensation obligation		0		(17)		0		(17)

Total liabilities		0		(17)		0		(17)

Total net assets (liabilities)	$	184	$	(17)	$	0	$	167

(a) Excludes $14 million of the cash surrender value of life insurance investments at both June 30, 2014 and December 31, 2013.

Fair value of financial liabilities recorded at the carrying amount

	June 30, 2014
	Carrying		Fair Value
	Amount		Level 1			Level 2	Level 3		Total
Short-term liabilities	$	73	$	3	$	70	$	0	$	73
Long-term debt (including amounts due within one year)		1,976		0		2,206		0		2,206
Long-term debt to financing trusts		258		0		0		259		259

	December 31, 2013
	Carrying		Fair Value
	Amount		Level 1			Level 2	Level 3		Total
Short-term liabilities	$	138	$	3	$	135	$	0	$	138
Long-term debt (including amounts due within one year)		2,011		0		2,148		0		2,148
Long-term debt to financing trusts		258		0		0		249		249

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

As of June 30, 2014		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents		$	53	$	0	$	0	$	53
Rabbi trust investments
	Mutual funds		5		0		0		5
Rabbi trust investments subtotal			5		0		0		5

Total assets			58		0		0		58

Liabilities
Deferred compensation obligation			0		(5)		0		(5)

Total liabilities			0		(5)		0		(5)

Total net assets (liabilities)		$	58	$	(5)	$	0	$	53

As of December 31, 2013		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents		$	31	$	0	$	0	$	31
Rabbi trust investments
	Mutual funds		6		0		0		6
Rabbi trust investments subtotal			6		0		0		6

Total assets			37		0		0		37

Liabilities
Deferred compensation obligation			0		(6)		0		(6)

Total liabilities			0		(6)		0		(6)

Total net assets (liabilities)		$	37	$	(6)	$	0	$	31

Derivative Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2014

Derivative Financial Instruments [Line Items]

Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense

__________

For the three and six months ended June 30, 2014, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing. For the three and six months ended June 30, 2013, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing.

Summary of the derivative fair value

		Generation										Other		Exelon
	Description	Derivatives Designated as Hedging Instruments		Economic Hedges		Proprietary Trading^(a)		Collateral and Netting^(b)		Subtotal		Derivatives Designated as Hedging Instruments		Total

Mark-to-market derivative assets
	(current assets)	$	0	$	2	$	14	$	(18)	$	(2)	$	0	$	(2)
Mark-to-market derivative assets
	(noncurrent assets)		16		2		12		(10)		20		18		38
Total mark-to-market derivative
	assets	$	16	$	4	$	26	$	(28)	$	18	$	18	$	36

Mark-to-market derivative liabilities
	(current liabilities)	$	(1)	$	(4)	$	(15)	$	19	$	(1)	$	0	$	(1)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(19)		(2)		(11)		11		(21)		(6)		(27)
Total mark-to-market derivative
	liabilities	$	(20)	$	(6)	$	(26)	$	30	$	(22)	$	(6)	$	(28)
Total mark-to-market derivative
	net assets (liabilities)	$	(4)	$	(2)	$	0	$	2	$	(4)	$	12	$	8

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
Represents the netting of fair value balances with the same counterparty and any associated cash collateral.

		Generation										Other		Exelon
	Description	Derivatives Designated as Hedging Instruments		Economic Hedges		Proprietary Trading^(a)		Collateral and Netting^(b)		Subtotal		Derivatives Designated as Hedging Instruments		Total

Mark-to-market derivative assets
	(current assets)	$	0	$	3	$	15	$	(19)	$	(1)	$	0	$	(1)
Mark-to-market derivative assets
	(noncurrent assets)		26		3		15		(13)		31		7		38
Total mark-to-market derivative
	assets	$	26	$	6	$	30	$	(32)	$	30	$	7	$	37

Mark-to-market derivative liabilities
	(current liabilities)	$	(1)	$	(1)	$	(18)	$	19	$	(1)	$	0	$	(1)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(10)		(1)		(13)		13		(11)		(4)		(15)
Total mark-to-market derivative
	liabilities	$	(11)	$	(2)	$	(31)	$	32	$	(12)	$	(4)	$	(16)
Total mark-to-market derivative
	net assets (liabilities)	$	15	$	4	$	(1)	$	0	$	18	$	3	$	21

Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
Represents the netting of fair value balances with the same counterparty and any associated cash collateral.

		Three Months Ended June 30,
	Income Statement	2014		2013		2014		2013
	Location	Gain (Loss) on Swaps				Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(3)	$	(5)	$	2	$	2
Exelon	Interest expense		3		(6)		(3)		3

		Six Months Ended June 30,
	Income Statement	2014		2013		2014		2013
	Location	Gain (Loss) on Swaps				Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(8)	$	(9)	$	1	$	1
Exelon	Interest expense		5		(12)		(7)		4

		Generation								ComEd		Exelon
		Economic		Proprietary		Collateral and				Economic		Total
Derivatives		Hedges		Trading		Netting^(a)		Subtotal^(b)		Hedges^(c)		Derivatives

Mark-to-market derivative assets
	(current assets)	$	3,422	$	925	$	(3,716)	$	631	$	0	$	631
Mark-to-market derivative assets
	(noncurrent assets)		1,394		149		(1,099)		444		0		444
Total mark-to-market derivative
	assets	$	4,816	$	1,074	$	(4,815)	$	1,075	$	0	$	1,075

Mark-to-market derivative liabilities
	(current liabilities)	$	(3,354)	$	(900)	$	4,040	$	(214)	$	(13)	$	(227)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(1,214)		(165)		1,265		(114)		(121)		(235)
Total mark-to-market derivative
	liabilities	$	(4,568)	$	(1,065)	$	5,305	$	(328)	$	(134)	$	(462)
Total mark-to-market derivative
	net assets (liabilities)	$	248	$	9	$	490	$	747	$	(134)	$	613

__________

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

		Generation								ComEd		Exelon
		Economic		Proprietary		Collateral and				Economic		Total
Description		Hedges		Trading		Netting^(a)		Subtotal^(b)		Hedges^(c)		Derivatives

Mark-to-market derivative assets
	(current assets)	$	2,616	$	1,476	$	(3,364)	$	728	$	0	$	728
Mark-to-market derivative assets
	(noncurrent assets)		1,344		285		(1,060)		569		0		569
Total mark-to-market derivative
	assets	$	3,960	$	1,761	$	(4,424)	$	1,297	$	0	$	1,297

Mark-to-market derivative liabilities
	(current liabilities)	$	(2,023)	$	(1,410)	$	3,292	$	(141)	$	(17)	$	(158)
Mark-to-market derivative liabilities
	(noncurrent liabilities)		(804)		(293)		988		(109)		(176)		(285)
Total mark-to-market derivative
	liabilities	$	(2,827)	$	(1,703)	$	4,280	$	(250)	$	(193)	$	(443)
Total mark-to-market derivative
	net assets (liabilities)	$	1,133	$	58	$	(144)	$	1,047	$	(193)	$	854

__________

(a) Exelon and Generation net all available amounts allowed under the derivative accounting 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. These are not reflected in the table above.

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

Other Derivatives - Gain (loss) and reclassification

Prior to the merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation.

Change in fair value and reclassification of derivative contracts

		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Three Months Ended June 30, 2014		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	(124)	$	111	$	0	$	(13)	$	0	$	0	$	(13)
Reclassification to realized at settlement
	of commodity positions		45		(42)		0		3		0		0		3
Net commodity mark-to-market gains (losses)		$	(79)	$	69	$	0	$	(10)	$	0	$	0	$	(10)

Change in fair value of treasury positions		$	(3)	$	0	$	(1)	$	(4)	$	0	$	0	$	(4)
Reclassification to realized at settlement
	of treasury positions		(1)		0		0		(1)		0		0		(1)
Net treasury mark-to-market gains (losses)		$	(4)	$	0	$	(1)	$	(5)	$	0	$	0	$	(5)

	Net mark-to-market gains (losses)	$	(83)	$	69	$	(1)	$	(15)	$	0	$	0	$	(15)

		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Six Months Ended June 30, 2014		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	(975)	$	282	$	0	$	(693)	$	0	$	0	$	(693)
Reclassification to realized at settlement
	of commodity positions		137		(183)		0		(46)		0		0		(46)
Net commodity mark-to-market gains (losses)		$	(838)	$	99	$	0	$	(739)	$	0	$	0	$	(739)

Change in fair value of treasury positions		$	(4)	$	0	$	(1)	$	(5)	$	0	$	0	$	(5)
Reclassification to realized at settlement
	of treasury positions		(1)		0		0		(1)		0		0		(1)
Net treasury mark-to-market gains (losses)		$	(5)	$	0	$	(1)	$	(6)	$	0	$	0	$	(6)

	Net mark-to-market gains (losses)	$	(843)	$	99	$	(1)	$	(745)	$	0	$	0	$	(745)

		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Three Months Ended June 30, 2013		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	460	$	(77)	$	0	$	383	$	(13)	$	0	$	370
Reclassification to realized at settlement
	of commodity positions		44		1		0		45		3		0		48
Net commodity mark-to-market gains (losses)		$	504	$	(76)	$	0	$	428	$	(10)	$	0	$	418

Change in fair value of treasury positions		$	0	$	0	$	(2)	$	(2)	$	0	$	0	$	(2)
Reclassification to realized at settlement
	of treasury positions		0		0		0		0		0		0		0
Net treasury mark-to-market gains (losses)		$	0	$	0	$	(2)	$	(2)	$	0	$	0	$	(2)

	Net mark-to-market gains (losses)	$	504	$	(76)	$	(2)	$	426	$	(10)	$	0	$	416


		Generation								Intercompany Eliminations		HoldCo		Exelon
				Purchased
		Operating		Power		Interest				Operating		Interest
Six Months Ended June 30, 2013		Revenues		and Fuel		Expense		Total		Revenues^(a)		Expense		Total
Change in fair value of commodity positions		$	(26)	$	69	$		$	43	$	(6)	$	0	$	37
Reclassification to realized at settlement
	of commodity positions		(56)		38				(18)		13		0		(5)
Net commodity mark-to-market gains (losses)		$	(82)	$	107	$	0	$	25	$	7	$	0	$	32

Change in fair value of treasury positions		$	0	$	0	$	(3)	$	(3)	$	0	$	0	$	(3)
Reclassification to realized at settlement
	of treasury positions		0		0		0		0		0		0		0
Net treasury mark-to-market gains (losses)		$	0	$	0	$	(3)	$	(3)	$	0	$	0	$	(3)

	Net mark-to-market gains (losses)	$	(82)	$	107	$	(3)	$	22	$	7	$	0	$	29

			Three Months Ended				Six Months Ended
		Location on Income	June 30,				June 30,
		Statement	2014		2013		2014		2013
Change in fair value of commodity positions		Operating Revenues	$	1	$	5	$	0	$	1
Reclassification to realized at settlement
	of commodity positions	Operating Revenues		(8)		(1)		(7)		5
Net commodity mark-to-market gains (losses)		Operating Revenues	$	(7)	$	4	$	(7)	$	6

Change in fair value of treasury positions		Operating Revenues	$	0	$	0	$	(1)	$	0
Reclassification to realized at settlement
	of treasury positions	Operating Revenues		1		(1)		1		(1)
Net treasury mark-to-market gains (losses)		Operating Revenues	$	1	$	(1)	$	0	$	(1)

Net mark-to-market gains (losses)		Operating Revenues	$	(6)	$	3	$	(7)	$	5

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

	Total						Number of		Net Exposure of
	Exposure						Counterparties		Counterparties
	Before Credit		Credit		Net		Greater than 10%		Greater than 10%
Rating as of June 30, 2014	Collateral		Collateral^(a)		Exposure		of Net Exposure		of Net Exposure
Investment grade	$	1,095	$	103	$	992		1	$	417
Non-investment grade		12		9		3		0		0
No external ratings
Internally rated - investment grade		286		2		284		1		189
Internally rated - non-investment
grade		21		4		17		0		0
Total	$	1,414	$	118	$	1,296		2	$	606

Net Credit Exposure by Type of Counterparty	As of June 30, 2014
Financial institutions		$	185
Investor-owned utilities, marketers, power producers			360
Energy cooperatives and municipalities			729
Other			22
Total		$	1,296

Credit-Risk Related Contingent Feature		June 30, 2014		December 31, 2013
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(1,102)	$	(1,056)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)		825		846
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(277)	$	(210)

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.
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.
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.

Debt and Credit Agreements Year-End (Tables)

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Debt Instrument [Line Items]

Schedule Of Short Term Debt [Text Block]

Type of Credit Facility		Amount (a)		Expiration Dates	Capacity Type
Exelon Corporate		(In billions)
	Syndicated Revolver^(b)	$	0.5	May 2019	Letters of credit and cash
Generation
	Syndicated Revolver		5.1	May 2019	Letters of credit and cash
	Syndicated Revolver		0.2	August 2018	Letters of credit and cash
	Bilateral		0.3	December 2015 and March 2016	Letters of credit and cash
	Bilateral		0.1	January 2015	Letters of credit
	Bilateral		0.1	October 2014	Letters of credit and cash
ComEd
	Syndicated Revolver		1.0	March 2019	Letters of credit and cash
PECO
	Syndicated Revolver^(b)		0.6	May 2019	Letters of credit and cash
BGE
	Syndicated Revolver^(b)		0.6	May 2019	Letters of credit and cash
	Total	$	8.5

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd's, PECO's and BGE's service territories. These facilities expire on October 18, 2014 and are solely utilized to issue letters of credit. As of June 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $20 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $7.2 billion to support the PHI transaction discussed below.
Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.

Schedule Of Short Term Debt [Text Block]

Debt Instrument [Line Items]

184

Schedule Of Short Term Debt [Text Block]

Debt Instrument [Line Items]

135

Debt and Credit Agreements Quarter-End (Tables)

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Commercial paper and credit facility borrowings outstanding

Type of Credit Facility		Amount (a)		Expiration Dates	Capacity Type
Exelon Corporate		(In billions)
	Syndicated Revolver^(b)	$	0.5	May 2019	Letters of credit and cash
Generation
	Syndicated Revolver		5.1	May 2019	Letters of credit and cash
	Syndicated Revolver		0.2	August 2018	Letters of credit and cash
	Bilateral		0.3	December 2015 and March 2016	Letters of credit and cash
	Bilateral		0.1	January 2015	Letters of credit
	Bilateral		0.1	October 2014	Letters of credit and cash
ComEd
	Syndicated Revolver		1.0	March 2019	Letters of credit and cash
PECO
	Syndicated Revolver^(b)		0.6	May 2019	Letters of credit and cash
BGE
	Syndicated Revolver^(b)		0.6	May 2019	Letters of credit and cash
	Total	$	8.5

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd's, PECO's and BGE's service territories. These facilities expire on October 18, 2014 and are solely utilized to issue letters of credit. As of June 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $20 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $7.2 billion to support the PHI transaction discussed below.
Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.

Issuance of Long-Term Debt

Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon	Junior Subordinated Notes	2.500	%	June 1, 2024	$	1,150	Used to finance a portion of the acquisition of PHI and for general corporate purposes
Generation	Nuclear Fuel Purchase Contract	3.350	%	June 30, 2018	$	38	Used for procurement of uranium
Generation	ExGen Renewables I Project Financing^(a)	LIBOR + 4.250%		February 6, 2021	$	300	Used for general corporate purposes
ComEd	Mortgage Bonds Series 115	2.150	%	January 15, 2019	$	300	Used to refinance existing mortgage bonds
ComEd	Mortgage Bonds Series 116	4.700	%	January 15, 2044	$	350	Used to refinance existing mortgage bonds

Company	Type	Interest Rate		Maturity		Amount	Use of Proceeds
Generation	Upstream Gas Lending Agreement	2.210	%	July 22, 2016	$	3	Used to fund Upstream gas activities
Generation	DOE Project Financing	2.535 - 2.922	%	January 5, 2037	$	197	Funding for Antelope Valley Solar Development
Generation	Energy Efficiency Project Financing	4.400	%	August 31, 2014	$	9	Funding to install energy conservation measures in Beckley, West Virginia
BGE	Senior Notes	3.350	%	July 1, 2023	$	300	Used to partially refinance Notes due July 1, 2013 and for general corporate purposes

Retirement of Long-Term Debt

Company	Type	Interest Rate		Maturity	Amount
Generation	2003 Senior Notes	5.35	%	January 15, 2014		$	500
Generation	Pollution Control Loan	4.10	%	July 1, 2014		$	20
Generation	Continental Wind Project Financing	6.00	%	February 28, 2033		$	11
Generation	Kennett Square Capital Lease	7.83	%	September 20, 2020		$	2
Generation	ExGen Renewables I	3mL + 4.25	%	February 6, 2021		$	3
Generation	AVSR	2.33% - 3.55%		January 5, 2037		$	1
Generation	Clean Horizons Solar	2.56	%	September 7, 2030		$	1
Generation	Sacramento Solar	2.56	%	December 31, 2030		$	1
ComEd	Mortgage Bonds Series 110	1.63	%	January 15, 2014		$	600
ComEd	Pollution Control Series 1994C	5.85	%	January 15, 2014		$	17
BGE	Rate Stabilization Bonds	5.72	%	April 1, 2017		$	35

Company		Type	Interest Rate		Maturity	Amount
Generation		Kennett Square Capital Lease	7.830	%	September 20, 2020		$	1
Generation		Solar Revolver	1.950	%	July 7, 2014		$	6
Generation		Clean Horizons Solar	2.563	%	September 7, 2030		$	1
Generation	^(a)	Series A Junior Subordinated Debentures	8.625	%	June 15, 2063		$	450
ComEd		First Mortgage Bonds Series 92	7.625	%	April 15, 2013		$	125
BGE		Rate Stabilization Bonds	5.720	%	April 1, 2017		$	33

Commercial paper and credit facility borrowings outstanding

184

Commercial paper and credit facility borrowings outstanding

135

Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2014

Asset Retirement Obligations Tables [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

(b) Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

Asset Retirement Obligations Tables [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

Schedule Of Nuclear Decommissioning [Line Items]

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

Nuclear Decommissioning (Tables)

6 Months Ended

Jun. 30, 2014

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

(b) Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

Schedule Of Nuclear Decommissioning [Line Items]

Nuclear decommissioning asset retirement obligation rollforward

Nuclear decommissioning ARO at December 31, 2013 ^(a)	$	4,855
Consolidation of CENG ^(b)		1,701
Accretion expense		154
Costs incurred to decommission retired plants		(3)
Nuclear decommissioning ARO at June 30, 2014 ^(a)	$	6,707

Unrealized Gains (Losses) on nuclear decommissioning trust funds

		Exelon and Generation
			Three Months Ended				Six Months Ended
			June 30,				June 30,
			2014		2013		2014		2013
Net unrealized gains (losses) on decommissioning trust funds —
	Regulatory Agreement Units ^(a)	$	172	$	(102)	$	234	$	92
Net unrealized gains (losses) on decommissioning trust funds —
	Non-Regulatory Agreement Units ^(b)(c)		128		(40)		141		24

Schedule of Defined Benefit Plans Disclosures [Text Block]

	Exelon and Generation
	June 30,		December 31,
	2014		2013
Carrying value of Zion Station pledged assets	$	402	$	458

Payable to Zion Solutions ^(a)		357		414

Current portion of payable to Zion Solutions ^(b)		93		109

Withdrawals by Zion Solutions to pay decommissioning costs ^(c)		575		498

Excludes a liability recorded within Exelon's and Generation's Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets.
Cumulative withdrawals since September 1, 2010.

Retirement Benefits (Tables)

6 Months Ended

Jun. 30, 2014

Retirement Benefits [Line Items]

		Pension Benefits				Other Postretirement Benefits
		Three Months Ended				Three Months Ended
		June 30,				June 30,
		2014(a)		2013		2014(a)		2013
Service cost		$	69	$	79	$	29	$	40
Interest cost			184		163		45		49
Expected return on assets			(242)		(254)		(38)		(33)
Amortization of:
	Prior service cost (benefit)		4		4		(30)		(6)
	Actuarial loss		104		141		12		21

Net periodic benefit cost		$	119	$	133	$	18	$	71

		Pension Benefits				Other Postretirement Benefits
		Six Months Ended				Six Months Ended
		June 30,				June 30,
		2014(a)		2013		2014(a)		2013
Service cost		$	138	$	159	$	61	$	81
Interest cost			367		326		101		97
Expected return on assets			(483)		(508)		(76)		(66)
Amortization of:
	Prior service cost (benefit)		7		7		(34)		(10)
	Actuarial loss		209		281		20		42

Net periodic benefit cost		$	238	$	265	$	72	$	144

Schedule Of Pension And Other Postretirement Benefit Costs [Text Block]

	Pension Benefits		Other Postretirement Benefits
Service cost	$	5	$	1
Interest cost		6		2
Expected return on assets		(9)		0

Net periodic benefit cost	$	2	$	3

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Pension and Other Postretirement Benefit Costs	2014		2013		2014		2013
Generation(a)	$	63	$	87	$	139	$	173
ComEd		40		77		96		154
PECO		9		10		21		21
BGE		17		14		33		27
BSC(b)		13		16		26		34

These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.

Schedule Of Defined Contributions [Text Block]

	Three Months Ended				Six Months Ended
	June 30,				June 30,
Savings Plan Matching Contributions	2014		2013		2014		2013
Exelon(a)	$	19	$	21	$	48	$	43
Generation(a)		10		10		24		21
ComEd		5		5		12		10
PECO		2		2		4		4
BGE		1		2		4		4
BSC(b)		1		2		4		4

Includes $1 million of matching contributions to CENG's 401(k) defined contribution savings plan for the period April 1, 2014 to June 30, 2014.
These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Serverance And Plant Retirements (Tables)

6 Months Ended

Jun. 30, 2014

Corporate Restructuring And Plant Retirements Tables [Abstract]

Total severance benefits costs, recorded as operating and maintenance expense

Three Months Ended June 30, 2014
Severance Benefits		Exelon		Generation
Severance charges (a)	$	1	$	1
Total severance benefits	$	1	$	1

Six Months Ended June 30, 2014
Severance Benefits		Exelon		Generation
Severance charges (a)	$	2	$	2
Total severance benefits	$	2	$	2

Activity of severance obligations for the corporate restructuring (excluding obligations recorded in equity)


Six Months Ended June 30, 2014
Severance Liability		Exelon		Generation
Balance at December 31, 2013	$	2	$	2
Integration of CENG^(a)		19		19
Severance charges		2		2
Payments		(3)		(3)
Balance at June 30, 2014	$	20	$	20

Six Months Ended June 30, 2014
Severance Liability		Exelon		Generation		ComEd		PECO		BGE
Balance at December 31, 2013	$	53	$	10	$	0	$	0	$	6
Payments		(20)		(2)		0		0		(3)
Balance at June 30, 2014	$	33	$	8	$	0	$	0	$	3

Schedule Of Severance Costs [TableTextBlock]

			Exelon		Generation		ComEd		PECO		BGE

Three Months Ending
	June 30, 2014	$	4	$	2	$	0	$	0	$	0
	June 30, 2013	$	1	$	1	$	0	$	0	$	0

Six Months Ending
	June 30, 2014	$	6	$	4	$	0	$	0	$	0
	June 30, 2013	$	2	$	1	$	1	$	0	$	0

Stock-Based Compensation Plans (Tables)

6 Months Ended

Jun. 30, 2014

Stock-Based Compensation Plans [Line Items]

Stock Based Compensation Components [Text Block]

		Three Months Ended				Six Months Ended
		June 30,				June 30,

Components of Stock-Based Compensation Expense		2014		2013		2014		2013

Performance share awards		$	12	$	5	$	41	$	32
Stock options			1		2		3		13
Restricted stock units			13		12		49		41
Other stock-based awards			1		1		4		3

Total stock-based compensation expense included in
	operating and maintenance expense		27		20		97		89

Income tax benefit			(10)		(8)		(37)		(34)

Total after-tax stock-based compensation expense		$	17	$	12	$	60	$	55

Stock Based Compensation Expense Subsidiaries [Text Block]

	Three Months Ended				Six Months Ended
	June 30,				June 30,

Subsidiaries	2014		2013		2014		2013

Generation	$	10	$	9	$	38	$	33
ComEd		3		2		7		9
PECO		1		1		4		4
BGE (a)		1		1		5		4
BSC (b)		12		7		43		39

Total (c)	$	27	$	20	$	97	$	89

(b) These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.

Changes in Accumulated Other Comprehensive Income (Tables)

6 Months Ended

Jun. 30, 2014

Accumulated Other Comprehensive Income Loss [Line Items]

Schedule Of Accumulated Other Comprehensive Income Loss Table [Text Block]

For The Six Months Ended June 30, 2014			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 Equity Investments		Total
Exelon^(a)
	Beginning balance	$	120	$	2	$	(2,260)	$	(10)	$	108	$	(2,040)
	OCI before reclassifications		(11)		1		246		(1)		11		246
	Amounts reclassified from AOCI^(b)		(62)		0		66		0		(116)		(112)
	Net current-period OCI		(73)		1		312		(1)		(105)		134
	Ending balance	$	47	$	3	$	(1,948)	$	(11)	$	3	$	(1,906)

Generation^(a)
	Beginning balance	$	114	$	2	$	0	$	(10)	$	108	$	214
	OCI before reclassifications		(8)		(1)		0		(1)		11		1
	Amounts reclassified from AOCI^(b)		(62)		0		0		0		(116)		(178)
	Net current-period OCI		(70)		(1)		0		(1)		(105)		(177)
	Ending balance	$	44	$	1	$	0	$	(11)	$	3	$	37

ComEd ^(a)

PECO ^(a)
	Beginning balance	$	0	$	1	$	0	$	0	$	0	$	1
	OCI before reclassifications		0		0		0		0		0		0
	Net current-period OCI		0		0		0		0		0		0
	Ending balance	$	0	$	1	$	0	$	0	$	0	$	1

BGE^(a)

(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

(b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.

Schedule Of Other Comprehensive Income Loss Tax Table [TextBlock]

		Three Months Ended				Six Months Ended
		June 30,				June 30,
		2014		2013		2014		2013
Exelon
Pension and non-pension postretirement benefit plans:
	Prior service benefit reclassified to periodic benefit cost	$	5	$	0	$	5	$	1
	Actuarial loss reclassified to periodic cost		(23)		(32)		(46)		(66)
	Pension and non-pension post retirement benefit plans valuation adjustment		(166)		(1)		(159)		(50)
Change in unrealized loss on cash flow hedges			28		45		48		77
Change in unrealized income on equity investments			77		(5)		70		(23)
Deferred compensation unit valuation adjustment			0		(6)		0		(6)
Total		$	(79)	$	1	$	(82)	$	(67)

Generation
	Change in unrealized loss on cash flow hedges	$	25	$	89	$	44	$	175
	Change in unrealized income on equity investments		77		(5)		70		(23)
	Change in marketable securities		0		0		(2)		0
Total		$	102	$	84	$	112	$	152

Earnings Per Share and Equity (Tables)

6 Months Ended

Jun. 30, 2014

Earnings Per Share and Equity Tables [Abstract]

Reconciliation of basic and diluted earnings per share

			Three Months Ended June 30,				Six Months Ended June 30,
			2014		2013		2014		2013

Net income attributable to common shareholders		$	522	$	490	$	612	$	486

Average common shares outstanding — basic			860		856		860		856
Potentially dilutive effect of stock options, performance share awards,
	restricted stock, and Exelon's equity forward sales agreement		4		4		3		3

Average common shares outstanding — diluted			864		860		863		859

Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2014

Commitments And Contingencies Tables Disclosure [Line Items]

Energy Commitments [Text Block]

	Net Capacity			REC			Transmission Rights
	Purchases^(a)			Purchases^(b)			Purchases^(c)			Total

2014		$	208		$	43		$	13		$	264
2015			353			163			13			529
2016			269			122			2			393
2017			208			59			2			269
2018			98			13			2			113
Thereafter			388			4			32			424

Total		$	1,524		$	404		$	64		$	1,992

(b) The table excludes renewable energy purchases that are contingent in nature.

(c) Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

Utility Energy Purchase Commitments [Text Block]

			Expiration within
													2019
	Total		2014		2015		2016		2017		2018		and beyond

ComEd
Electric supply procurement^(a)	$	740	$	217	$	232	$	151	$	140	$	0	$	0
Renewable energy and RECs^(b)		1,548		32		73		76		77		78		1,212
PECO
Electric supply procurement^(c)		550		381		169		0		0		0		0
AECs ^(d)		13		1		2		2		2		2		4
BGE
Electric supply procurement ^(e)		1,320		448		632		240		0		0		0
Curtailment services^(f)		136		21		40		34		29		12		0

(d) PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 5 - Regulatory Matters for additional information.

(f) BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - Regulatory Matters for additional information.

Fuel Purchase Commitments [Text Block]

			Expiration within
													2019
	Total		2014		2015		2016		2017		2018		and beyond

Generation	$	9,973	$	694	$	1,526	$	1,230	$	1,276	$	929	$	4,318
PECO		411		90		112		93		35		15		66
BGE		618		64		83		82		65		53		271

Commercial Commitments [Text Block]

		Exelon			Generation			ComEd			PECO			BGE

Letters of credit (non-debt) ^(a)	$	1,514		$	1,470		$	19		$	22		$	1
Guarantees		4,706	^(b)		1,346	^(c)		206	^(d)		181	^(e)		259	^(f)
Nuclear insurance premiums ^(g)		3,559			3,559			0			0			0
Underwriters discount ^(h)		60			0			0			0			0
Total commercial commitments	$	9,839		$	6,375		$	225		$	203		$	260

(a) Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

(d) Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.

(e) Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

(f) Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

Accrued environmental liabilities [Text Block]

June 30, 2014	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	323	$	258
Generation		56		0
ComEd		222		217
PECO		44		41
BGE		1		0
December 31, 2013	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation
Exelon	$	338	$	273
Generation		56		0
ComEd		234		229
PECO		47		44
BGE		1		0

Other Purchase Obligation [Table Text Block]

			Expiration within
													2019
	Total		2014		2015		2016		2017		2018		and beyond

Exelon	$	568	$	140	$	171	$	65	$	55	$	37	$	100
Generation		474		110		155		52		47		31		79
ComEd^(a)		53		16		8		5		5		5		14
PECO^(a)		28		12		4		3		1		1		7
BGE^(a)		12		1		4		5		2		0		0

(a) Purchase obligations include commitments related to smart meter installation. See Note 5 – Regulatory Matters for additional information.

Supplemental Financial Information (Tables)

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Supplemental Financial Information Tables [Line Items]

Components of non-operating income and expenses

Three Months Ended June 30, 2014			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	68	$	68	$	0	$	0	$	0
		Non-regulatory agreement units		38		38		0		0		0
	Net unrealized gains on decommissioning trust funds
		Regulatory agreement units		172		172		0		0		0
		Non-regulatory agreement units		128		128		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		10		10		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		(204)		(204)		0		0		0
Total decommissioning-related activities				212		212		0		0		0
Investment income (expense)				7		7		0		(1)		2	^(c)
Long-term lease income				10		0		0		0		0
Interest income (expense) related to uncertain income tax positions				(2)		3		0		0		0
AFUDC - Equity				5		0		0		1		3
Other				11		6		5		1		0

Other, net			$	243	$	228	$	5	$	1	$	5


Six Months Ended June 30, 2014			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	111	$	111	$	0	$	0	$	0
		Non-regulatory agreement units		63		63		0		0		0
	Net unrealized gains on decommissioning trust funds
		Regulatory agreement units		234		234		0		0		0
		Non-regulatory agreement units		141		141		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		20		20		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		(299)		(299)		0		0		0
Total decommissioning-related activities				270		270		0		0		0
Investment income (expense)				8		8		0		(1)		4	^(c)
Long-term lease income				17		0		0		0		0
Interest income related to uncertain income tax positions				7		17		0		0		0
AFUDC - Equity				11		0		3		3		6
Other				35		23		7		1		(1)

Other, net			$	348	$	318	$	10	$	3	$	9

Three Months Ended June 30, 2013			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	47	$	47	$	0	$	0	$	0
		Non-regulatory agreement units		16		16		0		0		0
	Net unrealized losses on decommissioning trust funds
		Regulatory agreement units		(102)		(102)		0		0		0
		Non-regulatory agreement units		(40)		(40)		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		2		2		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		40		40		0		0		0
Total decommissioning-related activities				(37)		(37)		0		0		0
Investment income (expense)				2		0		0		(1)		2	^(c)
Long-term lease income				5		0		0		0		0
Interest expense related to uncertain income tax positions				(1)		(2)		0		0		0
AFUDC - Equity				5		0		3		1		2
Other				9		6		3		0		0

Other, net			$	(17)	$	(33)	$	6	$	0	$	4

Six Months Ended June 30, 2013			Exelon		Generation		ComEd		PECO		BGE
Other, Net
Decommissioning-related activities:
	Net realized income on decommissioning trust funds ^(a)
		Regulatory agreement units	$	84	$	84	$	0	$	0	$	0
		Non-regulatory agreement units		30		30		0		0		0
	Net unrealized gains on decommissioning trust funds
		Regulatory agreement units		92		92		0		0		0
		Non-regulatory agreement units		24		24		0		0		0
	Net unrealized gains on pledged assets
		Zion Station decommissioning		3		3		0		0		0
	Regulatory offset to decommissioning trust fund-related
		activities ^(b)		(148)		(148)		0		0		0
Total decommissioning-related activities				85		85		0		0		0
Investment income (expense)				5		(1)		0		(1)		5	^(c)
Long-term lease income				13		0		0		0		0
Interest income related to uncertain income tax positions				24		3		0		0		0
AFUDC - Equity				12		0		6		2		4
Other				16		8		5		2		0

Other, net			$	155	$	95	$	11	$	3	$	9

__________

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

(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral.

__________

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

(c) Relates to the cash return on BGE's rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral.

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


Six Months Ended June 30, 2014	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,015	$	444	$	290	$	112	$	142
Regulatory assets		117		0		57		5		55
Amortization of intangible assets, net		22		22		0		0		0
Amortization of energy contract assets and liabilities ^(a)		113		118		0		0		0
Nuclear fuel ^(b)		499		499		0		0		0
ARO accretion ^(c)		159		159		0		0		0

Total depreciation, amortization, accretion and depletion	$	1,925	$	1,242	$	347	$	117	$	197

Six Months Ended June 30, 2013	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	942	$	402	$	275	$	109	$	128
Regulatory assets		112		0		62		4		47
Amortization of intangible assets, net		22		22		0		0		0
Amortization of energy contract assets and liabilities ^(a)		306		344		0		0		0
Nuclear fuel ^(b)		454		454		0		0		0
ARO accretion ^(c)		136		136		0		0		0

Total depreciation, amortization, accretion and depletion	$	1,972	$	1,358	$	337	$	113	$	175

__________

Cash Flow Supplemental Disclosures

Six Months Ended June 30, 2014		Exelon		Generation		ComEd		PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs		$	315	$	139	$	96	$	21		$	33
Loss from equity method investments			20		20		0		0			0
Provision for uncollectible accounts			59		8		(8)		28			30
Stock-based compensation costs			68		0		0		0			0
Other decommissioning-related activity ^(a)			(85)		(85)		0		0			0
Energy-related options ^(b)			63		63		0		0			0
Amortization of regulatory asset related to debt costs			5		0		4		1			0
Amortization of rate stabilization deferral			33		0		0		0			33
Amortization of debt fair value adjustment			(26)		(12)		0		0			0
Discrete impacts of EIMA ^(c)			9		0		9		0			0
Amortization of debt costs			19		6		(3)		1			1
Increase in inventory reserve			3		3		1		0			0
Impairment of investments in direct financing leases ^(e)			24		0		0		0			0
Impairment charges ^(f)			86		86		0		0			0
Other			(26)		(19)		0		(1)			(8)

Total other non-cash operating activities		$	567	$	209	$	99	$	50		$	89

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs		$	60	$	0	$	61	$	(6)		$	8
Other regulatory assets and liabilities			(25)		0		(30)		(13)			(49)
Other current assets			(157)		13		(5)		(89)	^(h)		51
Other noncurrent assets and liabilities			(158)		(69)		22		(6)			(2)

Total changes in other assets and liabilities		$	(280)	$	(56)	$	48	$	(114)		$	8

Non-cash investing and financing activities:
Fair value of net assets recorded upon CENG
consolidation ^(j)		$	3,400	$	3,400	$	0	$	0		$	0
Issuance of equity units ^(k)			131		0		0		0			0
Uranium procurement ^(l)			38		38		0		0			0
Indemnification of like-kind exchange position ^(m)			0		0		2		0			0

	Total non-cash investing and financing activities:	$	3,569	$	3,438	$	2	$	0		$	0

Six Months Ended June 30, 2013	Exelon		Generation		ComEd			PECO			BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	409	$	173	$	154		$	21		$	27
Loss in equity method investments		30		30		0			0			0
Provision for uncollectible accounts		55		10		4			27			14
Stock-based compensation costs		70		0		0			0			0
Other decommissioning-related activity ^(a)		(62)		(62)		0			0			0
Energy-related options ^(b)		65		65		0			0			0
Amortization of regulatory asset related to debt costs		6		0		5			1			0
Amortization of rate stabilization deferral		29		0		0			0			29
Amortization of debt fair value adjustment		(22)		(22)		0			0			0
Discrete impacts from EIMA ^(c)		(126)		0		(126)			0			0
Amortization of debt costs		8		5		2			1			0
Merger integration costs ^(d)		(6)		0		0			0			(6)
Impairment of investments in direct financing leases^(e)		14		0		0			0			0
Increase in inventory reserve		13		13		0			0			0
Impairment charges ^(g)		110		110		0			0			0
Other		(17)		(7)		0			0			(3)

Total other non-cash operating activities	$	576	$	315	$	39		$	50		$	61

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(24)	$	0	$	(61)		$	19		$	18
Other regulatory assets and liabilities		3		0		(28)			(5)			(82)
Other current assets		(123)		(134)		2			(62)	^(h)		99
Other noncurrent assets and liabilities		277		(34)		304	⁽ⁱ⁾		(1)			28

Total changes in other assets and liabilities	$	133	$	(168)	$	217		$	(49)		$	63

Non-cash investing and financing activities:
Consolidated VIE dividend to non-controlling interest	$	63		63		0			0			0
Indemnification of like-kind exchange position ^(l)		0		0		174			0			0

Total non-cash investing and financing activities	$	63	$	63	$	174		$	0		$	0

_________

(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

(d) Relates to integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 5 – Regulatory Matters for more information.

(e) Relates to an other than temporary decline in the estimated residual value of Exelon's direct financing leases. See Note 7 – Impairment of Long-Lived Assets for more information.

(f) Relates to the impairment of long-lived assets at Generation. See Note 7 – Impairment of Long-Lived Assets for additional information.

(g) Relates to the cancellation of uprate projects at Generation. See Note 7 – Impairment of Long-Lived Assets for additional information.

(h) Relates primarily to prepaid utility taxes.

(i) Relates primarily to interest payable related to like-kind exchange tax position. See Note 11 – Income Taxes for discussion of the like-kind exchange tax position.

(j) See Note 6 – Investment in Constellation Energy Nuclear Group, LLC for additional information.

(k) Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 16 – Common Stock for additional information.

(m) See Note 11 – Income Taxes for discussion of the like-kind exchange tax position.

Supplemental Balance Sheet Disclosures

June 30, 2014	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	14,369	^(a)	$	7,397	^(a)	$	3,325	$	2,969	$	2,781
Accounts receivable:
Allowance for uncollectible accounts		293			56			71		124		42

December 31, 2013	Exelon			Generation			ComEd		PECO		BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	13,713	^(b)	$	7,034	^(b)	$	3,184	$	2,935	$	2,702
Accounts receivable:
Allowance for uncollectible accounts		272			57			62		107		46

___________

(a) Includes accumulated amortization of nuclear fuel in the reactor core of $2,411 million.

(b) Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.

Accumulated Other Comprehensive Income Net Of Taxes

For The Six Months Ended June 30, 2014			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 Equity Investments		Total
Exelon^(a)
	Beginning balance	$	120	$	2	$	(2,260)	$	(10)	$	108	$	(2,040)
	OCI before reclassifications		(11)		1		246		(1)		11		246
	Amounts reclassified from AOCI^(b)		(62)		0		66		0		(116)		(112)
	Net current-period OCI		(73)		1		312		(1)		(105)		134
	Ending balance	$	47	$	3	$	(1,948)	$	(11)	$	3	$	(1,906)

Generation^(a)
	Beginning balance	$	114	$	2	$	0	$	(10)	$	108	$	214
	OCI before reclassifications		(8)		(1)		0		(1)		11		1
	Amounts reclassified from AOCI^(b)		(62)		0		0		0		(116)		(178)
	Net current-period OCI		(70)		(1)		0		(1)		(105)		(177)
	Ending balance	$	44	$	1	$	0	$	(11)	$	3	$	37

ComEd ^(a)

PECO ^(a)
	Beginning balance	$	0	$	1	$	0	$	0	$	0	$	1
	OCI before reclassifications		0		0		0		0		0		0
	Net current-period OCI		0		0		0		0		0		0
	Ending balance	$	0	$	1	$	0	$	0	$	0	$	1

BGE^(a)

(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

(b) See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.

Segment Information (Tables)

6 Months Ended

Jun. 30, 2014

Analysis and reconciliation of reportable segment information

Three Months Ended June 30, 2014 and 2013

__________

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

Six Months Ended June 30, 2014 and 2013

												Intersegment Eliminations
		Generation ^(a)(b)		ComEd		PECO		BGE		Other ^(c)		Intersegment Eliminations			Exelon
Total revenues ^(d):
	2014	$	8,179	$	2,262	$	1,649	$	1,707	$	619	$	(1,155)	$	13,261
	2013		7,603		2,239		1,567		1,533		615		(1,334)		12,223
Intersegment revenues ^(e):
	2014	$	517	$	1	$	1	$	18	$	618	$	(1,155)	$	0
	2013		710		1		0		8		615		(1,334)		0
Net income (loss):
	2014	$	188	$	209	$	173	$	106	$	(25)	$	0	$	651
	2013		310		14		200		106		(132)		0		498

__________

(a) Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the six months ended June 30, 2014 include revenue from sales to PECO of $ 137 million and sales to BGE of $ 207 million in the Mid-Atlantic region, and sales to ComEd of $ 173 million in the Midwest region. For the six months ended June 30, 2013 intersegment revenues for Generation include revenue from sales to PECO of $238 million in the Mid-Atlantic region and sales to BGE of $212 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.

(b) Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through June 30, 2014.

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

Analysis and reconciliation of reportable segment revenues net of purchased power and fuel expense for Generation

Three Months Ended June 30, 2014 and 2013

Generation total revenues net of purchased power and fuel expense (three months ended):
	2014						2013
	RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF
Mid-Atlantic	$	906	$	14	$	920	$	770	$	(2)	$	768
Midwest		604		1		605		687		(3)		684
New England		88		(24)		64		85		(35)		50
New York		142		6		148		0		14		14
ERCOT		117		(58)		59		143		(31)		112
Other Regions ^(b)		157		(82)		75		111		(52)		59
Total Revenues net of purchased power and fuel expense for Reportable Segments		2,014		(143)		1,871		1,796		(109)		1,687
Other ^(c)		(60)		143		83		328		109		437
Total Generation Revenues net of purchased power and fuel expense	$	1,954	$	0	$	1,954	$	2,124	$	-	$	2,124

(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b) Other regions include the South, West and Canada, which are not considered individually significant.

(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $50 million and $167 million for the three months ended June 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.

Six Months Ended June 30, 2014 and 2013

Generation total revenues net of purchased power and fuel expense (six months ended):
	2014						2013
	RNF from external customers ^(a)		Intersegment RNF		Total RNF		RNF from external customers ^(a)		Intersegment RNF		Total RNF
Mid-Atlantic ^(b)	$	1,690	$	(75)	$	1,615	$	1,622	$	(10)	$	1,612
Midwest		1,134		27		1,161		1,397		4		1,401
New England		242		(42)		200		103		(23)		80
New York ^(b)		113		14		127		(16)		8		(8)
ERCOT		272		(130)		142		255		(42)		213
Other Regions ^(c)		307		(127)		180		122		(17)		105
Total Revenues net of purchased power and fuel expense for Reportable Segments		3,758		(333)		3,425		3,483		(80)		3,403
Other ^(d)		(770)		333		(437)		6		80		86
Total Generation Revenues net of purchased power and fuel expense	$	2,988	$	0	$	2,988	$	3,489	$	0	$	3,489

(a) Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b) Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through June 30, 2014.

(d) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $92 million and $341 million, for the six months ended June 30, 2014 and 2013, respectively.

Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2014

Schedule Of Income Loss From Equity Method Investments [Text Block]

	Three Months			Three Months
	Ended March 31,			Ended March 31,
	2014		2013
Equity investment income	$	(2)	$	15
Amortization of basis difference in CENG		(17)		(27)
Total equity in earnings - CENG	$	(19)	$	(12)

Schedule Of Income Loss From Equity Method Investments [Text Block]

	Three Months			Three Months
	Ended March 31,			Ended March 31,
	2014		2013
Equity investment income	$	(2)	$	15
Amortization of basis difference in CENG		(17)		(27)
Total equity in earnings - CENG	$	(19)	$	(12)

Significant Accounting Policies (Details) - USD ($)	3 Months Ended			6 Months Ended
Significant Accounting Policies (Details) - USD ($)	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	May 15, 2014	Dec. 31, 2013
Capitalized Interest And AFUDC [Line Items]
Total interest incurred					$ 8,000,000
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Operating and maintenance	$ 2,166,000,000	$ 1,000,000	$ 1,892,000,000	$ 4,024,000,000	3,656,000,000
Interest Expense	228,000,000		246,000,000	445,000,000	863,000,000
Consolidation Percentages Detail Tagging [Abstract]
Equity Method Investment Ownership Percentage						67.00%
Third Party interest in ComEd	1,183,000,000			1,183,000,000			$ 15,000,000
Exelon Generation Co L L C [Member]
Capitalized Interest And AFUDC [Line Items]
Total interest incurred					8,000,000
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Operating and maintenance	1,255,000,000		1,041,000,000	2,194,000,000	2,007,000,000
Interest Expense	$ 74,000,000		77,000,000	$ 147,000,000	142,000,000
Consolidation Percentages Detail Tagging [Abstract]
Equity Method Investment Ownership Percentage	50.01%			50.01%
Third Party interest in ComEd	$ 1,185,000,000			$ 1,185,000,000			$ 17,000,000
Nuclear Fuel [Abstract]
Cost of spent nuclear fuel disposal per kWh of net nuclear generation	0.001			0.001
Commonwealth Edison Co [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Electrical transmission and distribution revenue	1,128,000,000		1,080,000,000	2,261,000,000	2,238,000,000
Operating and maintenance	316,000,000		319,000,000	603,000,000	611,000,000
Interest Expense	76,000,000		72,000,000	153,000,000	422,000,000
PECO Energy Co [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Operating and maintenance	160,000,000		155,000,000	416,000,000	319,000,000
Interest Expense	25,000,000		25,000,000	50,000,000	51,000,000
Baltimore Gas and Electric Company [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Operating and maintenance	163,000,000		139,000,000	326,000,000	266,000,000
Interest Expense	$ 23,000,000		$ 28,000,000	$ 47,000,000	$ 58,000,000

Basis of Presentation (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended
Basis of Presentation (Details) - USD ($) $ in Millions	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization	$ 590		$ 533	$ 1,154	$ 1,076
Operating and maintenance	2,166	$ 1	1,892	4,024	3,656
Capital expenditures				2,501	2,518
Income Tax Expense (Benefit)	277		239	224	294
Interest Expense	228		246	445	863
Total interest expense to affiliates, net	10		6	$ 20	13
Equity Method Investment Summarized Financial Information[Abstract]
Related Party Purchase Of Nuclear Output By Third Party Percentage				49.99%
Scenario Adjustment [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Purchased power and fuel from affiliate				$ 605
Exelon Generation Co L L C [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization	254		210	466	424
Operating and maintenance	1,255		1,041	2,194	2,007
Capital expenditures				1,103	1,277
Income Tax Expense (Benefit)	199		149	(1)	148
Interest Expense	74		77	147	142
Purchased power and fuel from affiliate	69		290	417	611
Total interest expense to affiliates, net	(12)		(16)	$ (25)	(34)
Equity Method Investment Summarized Financial Information[Abstract]
Related Party Purchase Of Nuclear Output By Third Party Percentage				49.99%
Exelon Generation Co L L C [Member] \| Scenario Adjustment [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Purchased power and fuel from affiliate				$ 611
Total interest expense to affiliates, net				34
Commonwealth Edison Co [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization	174		170	347	337
Operating and maintenance	316		319	603	611
Capital expenditures				747	711
Income Tax Expense (Benefit)	72		66	137	8
Interest Expense	76		72	153	422
Total interest expense to affiliates, net	4		4	7	7
PECO Energy Co [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization	59		56	117	113
Operating and maintenance	160		155	416	319
Capital expenditures				308	254
Income Tax Expense (Benefit)	23		32	57	87
Interest Expense	25		25	50	51
Total interest expense to affiliates, net	3		3	6	6
Baltimore Gas and Electric Company [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization	89		82	197	175
Operating and maintenance	163		139	326	266
Capital expenditures				313	264
Income Tax Expense (Benefit)	14		16	72	70
Interest Expense	23		28	47	58
Purchased power and fuel from affiliate	85		99	205	212
Total interest expense to affiliates, net	$ (4)		$ (4)	(8)	$ (8)
Baltimore Gas and Electric Company [Member] \| Scenario Adjustment [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Total interest expense to affiliates, net				$ 8

Variable Interest Entities (Details)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

USD ($)

VIE

Jun. 30, 2014

USD ($)

VIE

Jun. 30, 2013

USD ($)

Jun. 30, 2014

USD ($)

VIE

Jun. 30, 2013

USD ($)

Dec. 31, 2013

USD ($)

VIE

Dec. 31, 2012

USD ($)

Consolidated Variable Interest Entities Disclosure [Abstract]

Parental guarantee provided

$ 991

$ 484

Non Current Assets

7,426

1,905

Total Assets

8,417

2,389

Current Liabilities

815

566

Non Current Liabilites

2,911

774

Total Liabilities

3,726

1,340

Deferred tax assets

$ 0

$ 75

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Number of Variable Interest Entities not consolidated by equity holders | VIE

Number Of Variable Interest Entities Consolidated | VIE

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

$ 444

$ 460

Other ownership interests

^[1]

122

140

Our ownership interest

^[1]

^[1]

259

234

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract]

Gross pledged assets

486

614

Pledged assets liabilities offset

443

414

2,973

2,981

1,362

991

1,362

991

1,609

$ 1,486

1,005

1,175

409

276

1,041

829

775

666

9,823

10,137

51,747

47,330

10,437

8,071

2,674

2,625

1,092

964

22,086

22,457

83,656

79,924

Long-term Debt and Capital Lease Obligations, Current

621

341

2,047

1,509

2,633

2,484

Energy Marketing Contract Liabilities, Current

228

159

239

261

994

858

8,567

7,728

18,133

17,623

Defined Benefit Pension Plan, Liabilities, Noncurrent

7,054

5,194

1,804

1,876

260

266

2,133

2,540

32,079

30,985

59,427

56,984

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

1,382

1,633

1,419

2,190

Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

119

128

Other ownership interests

^[1]

^[1]

117

111

Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[1]

325

332

Other ownership interests

^[1]

120

123

Our ownership interest

^[1]

^[1]

142

123

Investments [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Investments [Member] | Maximum [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Investments [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Investments [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Contract Intangible Asset [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Contract Intangible Asset [Member] | Maximum [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Contract Intangible Asset [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Payment Guarantee [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Payment Guarantee [Member] | Maximum [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Payment Guarantee [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Net assets pledged for Zion Station decommissioning

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

^[2]

1,298

Net assets pledged for Zion Station decommissioning | Maximum [Member]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

Net assets pledged for Zion Station decommissioning | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

^[2]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information [Abstract]

VariableInterestEntityPrimaryBeneficiaryAggregatedDisclosureMember

^[2]

296

260

126

133

103

165

959

457

4,603

1,171

2,030

125

127

6,806

7,765

1,755

Long-term Debt and Capital Lease Obligations, Current

243

170

165

657

320

258

298

Defined Benefit Pension Plan, Liabilities, Noncurrent

1,731

133

178

2,454

338

3,111

658

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

136

Consolidated Variable Interest Entities Disclosure [Abstract]

Variable Interest Entity Nonconsolidated Carrying Amount Assets Liabilities And Other Information Footnotes [Abstract]

956

446

Non Current Assets

7,407

1,884

Total Assets

8,363

2,330

Current Liabilities

732

481

Non Current Liabilites

2,738

562

Total Liabilities

3,470

1,043

Deferred tax assets

Gross pledged assets

402

458

Pledged assets liabilities offset

385

414

1,733

1,689

305

222

305

222

1,258

671

441

353

328

164

872

671

524

505

5,727

6,439

23,743

20,111

10,437

8,071

687

645

14,952

14,682

44,422

41,232

Long-term Debt and Capital Lease Obligations, Current

561

1,508

1,322

Energy Marketing Contract Liabilities, Current

215

142

233

249

473

389

4,215

3,867

5,944

5,645

Defined Benefit Pension Plan, Liabilities, Noncurrent

6,907

5,047

125

260

266

260

266

761

811

19,665

17,455

30,772

28,490

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

819

976

941

850

Exelon Generation Co L L C [Member] | CENGMember [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Parental guarantee provided

Severance Costs

RestructuringAndRelatedCostExpectedCostRemaining

Other long term liabilities

113

Exelon Generation Co L L C [Member] | VariableInterestEntityPrimaryBeneficiaryAggregatedDisclosureMember

296

260

126

133

103

165

924

418

4,603

1,171

2,030

106

6,787

1,277

7,711

1,695

Long-term Debt and Capital Lease Obligations, Current

243

170

Energy Marketing Contract Liabilities, Current

165

575

236

Defined Benefit Pension Plan, Liabilities, Noncurrent

1,731

133

178

2,280

126

2,855

362

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

136

516

451

144

428

584

1,434

1,540

15,121

14,666

2,625

275

291

7,989

7,912

24,544

24,118

Long-term Debt and Capital Lease Obligations, Current

498

184

260

617

505

449

2,080

2,048

5,448

5,058

100

841

994

9,112

9,278

16,846

16,590

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

274

307

284

381

304

360

217

362

107

803

906

6,545

6,384

2,413

2,327

Long-term Debt and Capital Lease Obligations, Current

9,761

9,617

250

298

285

922

891

1,947

3,630

3,530

6,683

6,552

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

167

106

292

286

Consolidated Variable Interest Entities Disclosure [Abstract]

Non Current Liabilites

158

195

Total Liabilities

234

269

419

480

457

$ 89

102

114

916

1,011

6,030

5,864

931

986

7,877

7,861

Long-term Debt and Capital Lease Obligations, Current

135

205

270

747

827

1,904

1,941

2,313

2,280

5,222

5,306

Other Postretirement Defined Benefit Plan, Liabilities, Noncurrent

111

215

217

Baltimore Gas and Electric Company [Member] | RSB Bond Co LLC [Member]

Consolidated Variable Interest Entities Disclosure [Abstract]

Non Current Assets

Remittance of payments received from customers for rate stabilization to BondCo.

$ 17

$ 39

Baltimore Gas and Electric Company [Member] | VariableInterestEntityPrimaryBeneficiaryAggregatedDisclosureMember

Long-term Debt and Capital Lease Obligations, Current

158

195

158

195

234

269

$ 4

[1]

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

[2]

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $402 million and $458 million as of June 30, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $357 million and $414 million as of June 30, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

Regulatory Matters (Details)

1 Months Ended

6 Months Ended

12 Months Ended

Sep. 30, 2008

USD ($)

Jun. 30, 2014

USD ($)

SmartMeters

Jun. 30, 2013

USD ($)

Dec. 31, 2013

USD ($)

Dec. 31, 2012

Sep. 30, 2013

USD ($)

Jun. 01, 2013

Feb. 29, 2012

USD ($)

Dec. 31, 2010

USD ($)

^[1]

$ 270,000,000

$ 263,000,000

^[2]

(32,000,000)

(30,000,000)

Regulatory Assets And Liabilities Other Disclosures [Abstract]

238,000,000

233,000,000

33,000,000

$ 29,000,000

117,000,000

112,000,000

5,545,000,000

5,910,000,000

732,000,000

760,000,000

368,000,000

327,000,000

Nuclear Decommissioning [Member]

4,670,000,000

4,388,000,000

2,917,000,000

2,740,000,000

Removal Costs [Member]

107,000,000

99,000,000

Energy Efficiency Demand Response Programs [Member]

1,449,000,000

1,423,000,000

14,000,000

53,000,000

Electric Transmission And Distribution Tax Repairs [Member]

2,000,000

20,000,000

Over Recovered Energy And Transmission Costs [Member]

104,000,000

114,000,000

89,000,000

78,000,000

Over-Recovered Universal Service Fund Costs [Member]

11,000,000

5,000,000

8,000,000

Revenue subject to refund [Member]

Over Recovered Decoupling Revenue [Member]

^[3]

47,000,000

38,000,000

Gas Distribution Tax Repairs [Member]

^[4]

21,000,000

16,000,000

8,000,000

Regulatory Liabilities Other [Member]

34,000,000

37,000,000

3,000,000

4,000,000

Dlc Program Cost [Member]

1,000,000

1,000,000

Energy Efficiency Phase [Member]

9,000,000

10,000,000

Other Postretirement Benefits [Member]

32,000,000

21,000,000

53,000,000

2,000,000

111,000,000

43,000,000

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Minimum Purchase Obligation

License Renewals [Abstract]

25,000,000

Maximum Purchase Obligation

35,000,000

License Costs

36,000,000

Exelon Generation Co L L C [Member] | Regulatory Liabilities Other [Member]

^[1]

116,000,000

105,000,000

^[2]

(17,000,000)

(16,000,000)

Energy Infrastructure Modernization Act [Abstract]

99,000,000

89,000,000

Increased revenue requirement

269,000,000

Expected revenue adjustment for prior year

95,000,000

Expected revenue adjustment for current year

$ 174,000,000

Excess basis points over treasury after year one

5.80%

Distribution Rate Case [Abstract]

Requested increase in electric revenues

$ 396,000,000

Adjustment to Requested increase in electric revenues

343,000,000

Recovery request for Operating and Maintenance expenses of AMI Pilot Program

$ 40,000,000

Requested rate of return on common equity

11.50%

Rate of return on common equity electric distribution

0.103%

Increase in electric delivery service revenue resulting from rate case settlement or order.

$ 143,000,000

ComEd's proposed increase to net distribution revenue requirement related to uncollectable account expense

$ 22,000,000

Requested Rate Of Return Common Equity Electric Distribution

10.5

Appeal of 2007 Illinois Electric Distribution Rate Case [Abstract]

Increase in electric delivery service revenue requirement resulting from regulatory order in rate case

$ 274,000,000

Chicago areas smart meters installed | SmartMeters

350,000

Estimated Refund Obligation To Customers

$ 37,000,000

Chicago area smart meters, approved for installation | SmartMeters

350,000

Annual Transmission Formula Rate Update [Abstract]

Gross transmission revenue requirement

$ 524,000,000

488,000,000

Transmission revenue true up

11,000,000

25,000,000

Net transmission revenue requirement

535,000,000

$ 513,000,000

Advanced metering infrastructure pilot program [Abstract]

Collections Under Rider Amp

$ 24,000,000

RegulatoryLiabilityUnderRiderAmp

400,000

RefundAMP

$ 14,600,000

Weighted Average Debt And Equity Return Electric Distribution

0.0706%

0.0704%

Weighted Average Debt And Equity Return

8.62%

8.70%

Rate Of Return On Common Equity

11.50%

0.0925%

0.092%

Common Equity Component Cap

55.00%

Regulatory Assets And Liabilities Other Disclosures [Abstract]

$ 57,000,000

$ 62,000,000

850,000,000

$ 933,000,000

304,000,000

329,000,000

164,000,000

170,000,000

Commonwealth Edison Co [Member] | Nuclear Decommissioning [Member]

3,686,000,000

3,512,000,000

Commonwealth Edison Co [Member] | Removal Costs [Member]

2,427,000,000

2,293,000,000

83,000,000

78,000,000

Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]

1,248,000,000

1,219,000,000

14,000,000

45,000,000

Commonwealth Edison Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member]

19,000,000

9,000,000

Commonwealth Edison Co [Member] | Over-Recovered Universal Service Fund Costs [Member]

11,000,000

Commonwealth Edison Co [Member] | Revenue subject to refund [Member]

Commonwealth Edison Co [Member] | Other [Member]

^[3]

47,000,000

38,000,000

1,000,000

^[1]

75,000,000

72,000,000

^[2]

(8,000,000)

(7,000,000)

Smart Meter and Smart Grid Investments [Abstract]

$ 67,000,000

65,000,000

Estimated number of smart meters to be installed | SmartMeters

1,600,000

Expected number of smart meters to be deployed during the first phase of Smart Meter Installment Plan | SmartMeters

600,000

Revised spend on its Smart Meter Procurement and Installation Plan

$ 595,000,000

Spend on smart grid investments

120,000,000

Smart meter spend to date

480,000,000

Smart grid infrastructure spend to date

119,000,000

Total smart grid and smart meter investment grant amount

200,000,000

Smart meter investment grant awarded

140,000,000

Smart grid investment grant awarded

60,000,000

Reimbursements received from the DOE

198,000,000

Outstanding reimbursable DOE Smart Grid Investment Grant expenditures

2,000,000

Carrying value of originally installed Smart Meters, net of reimbursements from DOE

17,000,000

VendorRefund

12,000,000

Amount of reimbursements received from the DOE applied to the originally installed Smart Meters.

16,000,000

Current Year AMI Events Balance

5,000,000

Depreciation Related To Original Meters

2,000,000

DOE Cash Payable to Sub Receipients

4,000,000

Regulatory Assets And Liabilities Other Disclosures [Abstract]

Over under recovered electric supply costs

26,000,000

34,000,000

Over under recovered gas supply costs

19,000,000

16,000,000

5,000,000

4,000,000

1,495,000,000

1,448,000,000

29,000,000

17,000,000

88,000,000

106,000,000

Regulatory Liabilities Table Footnote Data [Abstract]

671,000,000

629,000,000

Electric Transmission Costs Under-Recovery

$ 7,000,000

8,000,000

PECO Energy Co [Member] | NewEnglandTransmissionOwners [Member]

Base Rate Of Return On Common Equity

11.14%

PECO Energy Co [Member] | Nuclear Decommissioning [Member]

PECO Energy Co [Member] | Removal Costs [Member]

$ 490,000,000

447,000,000

PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]

8,000,000

PECO Energy Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]

2,000,000

20,000,000

PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member]

104,000,000

114,000,000

52,000,000

^[5]

58,000,000

^[6]

PECO Energy Co [Member] | Over-Recovered Universal Service Fund Costs [Member]

5,000,000

8,000,000

PECO Energy Co [Member] | Gas Distribution Tax Repairs [Member]

8,000,000

PECO Energy Co [Member] | Regulatory Liabilities Other [Member]

34,000,000

37,000,000

PECO Energy Co [Member] | Dlc Program Cost [Member]

2,000,000

3,000,000

1,000,000

PECO Energy Co [Member] | Energy Efficiency Phase [Member]

9,000,000

10,000,000

PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]

$ 32,000,000

21,000,000

Illinois Settlement Agreement [Abstract]

Annual energy savings requirement

3.00%

Demand response peak demand reduction

4.50%

Energy Efficiency Program [Abstract]

Proposed funding of estimated costs associated with DLC demand program due to modification of incentive levels for other Phase II programs.

$ 10,000,000

^[1]

79,000,000

86,000,000

^[2]

(7,000,000)

Requested increase in electric revenues

72,000,000

$ 79,000,000

Distribution Rate Case [Abstract]

118,000,000

101,000,000

$ 83,000,000

Requested increase in gas revenues

$ 68,000,000

$ 30,000,000

$ 24,000,000

Rate of return on common equity electric distribution

10.65%

9.75%

Rate of return on common equity gas distribution

10.55%

9.60%

Increase in electric delivery service revenue resulting from rate case settlement or order.

$ 81,000,000

$ 34,000,000

Increase in gas delivery service revenue resulting from rate case settlement or order.

32,000,000

12,000,000

Regulatory Assets Transfer Changes

8,000,000

Severance Recovered Through Distribution Rates

20,000,000

Requested Rate Of Return Common Equity Electric Distribution

10.50

Requested Rate Of Return Common Equity Gas Distribution

10.35

Appeal of 2007 Illinois Electric Distribution Rate Case [Abstract]

Estimated Refund Obligation To Customers

13,000,000

Annual Transmission Formula Rate Update [Abstract]

Gross transmission revenue requirement

167,000,000

158,000,000

Transmission revenue true up

4,000,000

1,000,000

Net transmission revenue requirement

$ 171,000,000

$ 157,000,000

Smart Meter and Smart Grid Investments [Abstract]

Estimated number of smart meters to be installed | SmartMeters

2,000,000

Smart grid investment grant awarded

$ 200,000,000

Reimbursements received from the DOE

200,000,000

Outstanding reimbursable DOE Smart Grid Investment Grant expenditures

23,000,000

Total Projected smart meter smart grid spend

480,000,000

Upfront fee for opt-out of Smart Meter

RecurringFees

$ 11

New Electric Generation [Abstract]

Megawatt capacity of new generating plant | MW

700

Weighted Average Debt And Equity Return

8.53%

8.35%

Rate Of Return On Common Equity

10.80%

11.30%

Rate Of Return On Common Equity in FERC Complaint

8.70%

ReductionInRevenuefromProposedRate

$ 10,000,000

Regulatory Assets And Liabilities Other Disclosures [Abstract]

33,000,000

$ 29,000,000

Maryland Electric And Natural Gas Distribution Rate Cases [Abstract]

55,000,000

$ 47,000,000

Captial and OM estimates current year

14,800,000

Revenue Requirment

1,400,000

499,000,000

$ 524,000,000

178,000,000

181,000,000

63,000,000

48,000,000

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

$ 202,000,000

204,000,000

Rate Of Return On Common Equity in FERC Complaint

10.57%

Baltimore Gas and Electric Company [Member] | Nuclear Decommissioning [Member]

Baltimore Gas and Electric Company [Member] | Removal Costs [Member]

$ 24,000,000

21,000,000

Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]

201,000,000

204,000,000

Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution Tax Repairs [Member]

Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]

18,000,000

^[7]

11,000,000

Baltimore Gas and Electric Company [Member] | Over Recovered Gas Energy And Transmission Costs [Member]

Baltimore Gas and Electric Company [Member] | Over-Recovered Universal Service Fund Costs [Member]

18,000,000

Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Revenue [Member]

Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Electric Revenue [Member]

^[4]

21,000,000

16,000,000

Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Gas Revenue [Member]

3,000,000

Baltimore Gas and Electric Company [Member] | Regulatory Liabilities Other [Member]

18,000,000

$ 9,000,000

Baltimore Gas and Electric Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member]

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

1,000,000

Payments To Acquire Businesses Net Of Cash Acquired [Abstract]

$ 1,000,000

[1]	PECO's gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.
[2]	For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.
[3]	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC’s order in the 2007 Rate Case. See Note 3 – Regulatory Matters of the Exelon 2013 Form 10-K for further information.
[4]	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of June 30, 2014, BGE had a regulatory liability of $3 million related to over-recovered electric revenue decoupling and $18 million related to over-recovered natural gas revenue decoupling. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling
[5]	Includes $26 million related to the DSP program, $19 million related to the over-recovered natural gas costs under the PGC and $7 million related to over-recovered electric transmission costs as of June 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.
[6]	Includes $26 million related to the DSP program, $19 million related to the over-recovered natural gas costs under the PGC and $7 million related to over-recovered electric transmission costs as of June 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.
[7]	. Relates to $1 million of under-recovered electric supply costs, $4 million associated with the transmission formula rate and $18 million of over-recovered natural gas supply costs as of June 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs, $0 million associated with the transmission formula rate and $11 million of over-recovered natural gas supply costs.

Merger and Acquisitions (Details)
$ / shares in Units, shares in Millions, $ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

May 15, 2014

USD ($)

Jun. 30, 2014

USD ($)

$ / shares

Jun. 30, 2014

USD ($)

$ / shares

Sep. 30, 2013

USD ($)

Jun. 30, 2013

USD ($)

Jun. 30, 2014

USD ($)

$ / shares

Jun. 30, 2013

USD ($)

Jun. 11, 2014

USD ($)

$ / shares

Apr. 02, 2014

USD ($)

Jun. 30, 2012

USD ($)

Payments To Acquire Businesses Gross

$ 66

$ 3

BusinessAcquisitionPreexistingRelationshipGainLossRecognized

$ 125

125

Units of shares offered | shares

57.5

BridgeLoan

$ 4,200

4,200

$ 7,200

Equity Method Investment Ownership Percentage

67.00%

AfterTaxNetCashProceeds

$ 37

Business Acquisition, Impact Of Merger [Abstract]

131

6,024

$ 6,141

13,261

^[1]

12,223

^[1]

Business Acquisition, Regulatory Matters [Abstract]

557

497

498

Business Acquisition Potential Cash Payment

Business Acquisition, Costs Recognized Post Merger [Abstract]

Severance Charges

Payments

$ 3

Length of years for charitable contributions at $7 million per year

10 years

Business Acquisition Charitable Contributions Per Year

$ 7

Severance [Member]

Restructuring Reserve, Period Start

Restructuring Reserve, Period End

Pepco Holdings [Member]

Payments to Acquire Businesses and Interest in Affiliates [Abstract]

Business Acquisition Cost Of Acquired Entity Transaction Costs

Payments To Acquire Businesses Net Of Cash Acquired [Abstract]

Business Combination Proposed Customer Benefits Package

100

CashFundingFromNonCoreAssetSale

$ 1

GainOnSaleOfInvestmentsNet

332

EquityMethodInvestmentNetSalesProceeds

$ 613

Cash offered in exchange for each share of PHI common stock | $ / shares

$ 27.25

$ 35

PHI Preferred Securities Acquired

$ 90

OtherLongTermInvestmentsMaximum

$ 180

Pepco Holdings [Member] | Convertible

Payments To Acquire Businesses Net Of Cash Acquired [Abstract]

SubordinatedLongTermDebt

$ 1,200

Pepco Holdings [Member] | Minimum [Member]

Payments To Acquire Businesses Net Of Cash Acquired [Abstract]

BusinessExitCosts

259

Pepco Holdings [Member] | Maximum [Member]

Payments To Acquire Businesses Net Of Cash Acquired [Abstract]

BusinessExitCosts

293

Payments To Acquire Businesses Net Of Cash Acquired [Abstract]

Payments To Acquire Businesses Gross

$ (66)

Equity Method Investment Ownership Percentage

50.01%

Business Acquisition, Impact Of Merger [Abstract]

$ 1

3,789

4,070

8,179

7,603

372

328

188

310

Exelon Generation Co L L C [Member] | Severance [Member]

Severance Charges

Payments

Restructuring Reserve, Period Start

Restructuring Reserve, Period End

Exelon Generation Co L L C [Member] | Minimum [Member]

Business Acquisition, Regulatory Matters [Abstract]

Business Acquisition, Development Of New Generation Cost

600

$ 600

Business Acquisition, Expected New Generation Mwh | MW

285

Exelon Generation Co L L C [Member] | Maximum [Member]

Business Acquisition, Regulatory Matters [Abstract]

Business Acquisition, Development Of New Generation Cost

120

$ 650

650

$ 650

Business Acquisition, Expected New Generation Mwh | MW

300

Business Acquisition, Impact Of Merger [Abstract]

1,128

1,080

$ 2,262

2,239

111

209

Business Acquisition, Impact Of Merger [Abstract]

656

672

1,649

1,567

173

200

Business Acquisition, Impact Of Merger [Abstract]

653

1,707

1,533

Regulatory Assets Transfer Changes

$ 19

$ 25

106

$ 106

$ 8

Business Acquisition, Regulatory Matters [Abstract]

Business Acquisition, Direct Investment With State And Local Governments Due To Settlement

$ 1,000

Customer Relationships [Member] | Constellation Energy Group Acquisition [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life

12 years 4 months 26 days

Trade Names [Member] | Constellation Energy Group Acquisition [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life

10 years

Power Supply Contracts [Member] | Constellation Energy Group Acquisition [Member]

Acquired Finite-Lived Intangible Assets [Line Items]

Acquired Finite Lived Intangible Asset Weighted Average Useful Life

1 year 6 months 3 days

[1]

Investment in Constellation Energy Nuclear Group, LLC (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Apr. 02, 2014

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

May 15, 2014

Mar. 31, 2014

BusinessAcquisitionPreexistingRelationshipGainLossRecognized

$ 125

BusinessCombinationStepAcquisitionEquityInterestInAcquireeFairValue1

136

Accumulated Other Comprehensive Income (Loss), Net of Tax

$ (21)

(20)

$ (30)

^[1]

(1,906)

$ (2,040)

6,024

$ 6,141

6,141

13,261

^[2]

12,223

^[2]

$ 0

1,925

Impact Of Transactions Under Agreements [Abstract]

49.99%

Increase (Decrease) in earnings

Amortization of energy contract assets and liabilities

^[3]

$ 113

306

Maximum exposure related to guarantees

9,839

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Noncontrolling interest acquired

1,548

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

67.00%

Accumulated Other Comprehensive Income (Loss), Net of Tax

261

CENGMember [Member]

$ 1,500

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

499

2,958

Nuclear Fuel Inventory

482

Other Non Current Assets

Asset Retirement Obligation

5,904

Current liabilities

237

1,701

Unamortized energy contracts

171

Deferred credits and other liabilities and preferred securities

114

BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedLiabilities

2,504

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

3,400

CENG [Member] | Subsequent Event [Member] | FinancialGuaranteeMember

Impact Of Transactions Under Agreements [Abstract]

Due To Affiliate Current And Noncurrent

165

CENG [Member] | Subsequent Event [Member] | Payment Guarantee [Member]

Impact Of Transactions Under Agreements [Abstract]

Due To Affiliate Current And Noncurrent

245

Accumulated Other Comprehensive Income (Loss), Net of Tax

(1)

(21)

(20)

(30)

^[1]

214

3,789

4,070

8,179

7,603

$ 0

1,925

Impact Of Transactions Under Agreements [Abstract]

49.99%

Increase (Decrease) in earnings

201

352

$ 535

744

Amortization of energy contract assets and liabilities

^[3]

118

344

Special and Preferred Distributions by CENG

235

$ 474

Maximum exposure related to guarantees

$ 6,375

6,375

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

Noncontrolling interest acquired

$ 1,548

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

50.01%

Total equity investment earnings (losses) - CENG

$ 19

Basis difference in investment in CENG

204

$ 204

Exelon Generation Co L L C [Member] | CENGMember [Member]

261

(268)

Accumulated Other Comprehensive Income (Loss), Net of Tax

$ 139

$ 23

Impact Of Transactions Under Agreements [Abstract]

$ 1,900

Net Income

Business Combination, Integration Related Costs

Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Net Abstract

499

2,958

Nuclear Fuel Inventory

482

Other Non Current Assets

Asset Retirement Obligation

5,904

Current liabilities

237

1,701

Unamortized energy contracts

171

Pension obligation

$ 281

281

Deferred credits and other liabilities and preferred securities

114

BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedLiabilities

2,504

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

3,400

ReductionToNetIncomeAttributableToNonControllingInterest

Exelon Generation Co L L C [Member] | CENG [Member] | Subsequent Event [Member]

Impact Of Transactions Under Agreements [Abstract]

Loan Recievable from CENG

$ 400

Debt Instrument Interest Rate Stated Percentage

5.25%

Exelon Generation Co L L C [Member] | CENG [Member] | Subsequent Event [Member] | Payment Guarantee [Member]

Impact Of Transactions Under Agreements [Abstract]

Due To Affiliate Current And Noncurrent

$ 205

Exelon Generation Co L L C [Member] | First Distribution [Member] | CENG [Member]

Impact Of Transactions Under Agreements [Abstract]

Distribution From Affiliates

$ 115

Exelon Generation Co L L C [Member] | Second Distribution [Member] | CENG [Member]

Impact Of Transactions Under Agreements [Abstract]

Distribution From Affiliates

$ 13

Exelon Generation Co L L C [Member] | Minimum [Member]

Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent)

85.00%

Constellation Energy Group LLC [Member] | EDFI [Member] | Subsequent Event [Member]

Impact Of Transactions Under Agreements [Abstract]

Special and Preferred Distributions by CENG

400

Constellation Energy Group LLC [Member] | GenerationCoMember [Member] | Subsequent Event [Member]

Impact Of Transactions Under Agreements [Abstract]

Special and Preferred Distributions by CENG

$ 400

InterestRateOnDistribution

8.50%

Electricite De France LLC [Member] | CENG [Member] | Subsequent Event [Member] | FinancialGuaranteeMember

Impact Of Transactions Under Agreements [Abstract]

Maximum exposure related to guarantees

$ 145

[1]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[2]	For the six months ended June 30, 2014 and 2013, utility taxes of $45 million and $39 million, respectively, are included in revenues and expenses for Generation. For the six months ended June 30, 2014 and 2013, utility taxes of $119 million and $117 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2014 and 2013, utility taxes of $65 million and $64 million, respectively, are included in revenues and expenses for PECO. For the six months ended June 30, 2014 and 2013, utility taxes of $43 million and $41 million, respectively, are included in revenues and expenses for BGE.
[3]	Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income

Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2014	Mar. 31, 2014	Jun. 30, 2013	Mar. 31, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Sep. 30, 2000
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property	$ 685				$ 685		$ 1,465	$ 1,600
Less: unearned income	(332)				(332)		(767)
Net investment in long-term leases	353				353		$ 698
Carring Amount Of Long Lived Assets To Be Written Down	151				151
ImpairedAssetsFairValue	65				65
Other Cost and Expense, Operating	2,166	$ 1	$ 1,892		4,024	$ 3,656
CapitalLeasesNetInvestmentInDirectFinancingLeasesWriteoff	336				336
ProceedsFromLeaseTermination					335
Tangible Asset Impairment Charges					86
CapitalLeaseNetInvestmentInDirectFinancingLeasesPrepaymentsReceived	1,200				1,200
Utilities Operating Expense Maintenance And Operations [Abstract]
Utilities Operating Expense, Impairments			92	$ 21
Interest Costs Incurred [Abstract]
Interest Costs Incurred						8
Exelon Generation Co L L C [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Carring Amount Of Long Lived Assets To Be Written Down	151				151
ImpairedAssetsFairValue	65				65
Other Cost and Expense, Operating	1,255		1,041		2,194	2,007
Tangible Asset Impairment Charges					86
Utilities Operating Expense Maintenance And Operations [Abstract]
Utilities Operating Expense, Impairments			92	$ 21
Interest Costs Incurred [Abstract]
Interest Costs Incurred						8
Commonwealth Edison Co [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Other Cost and Expense, Operating	316		319		603	611
PECO Energy Co [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Other Cost and Expense, Operating	160		155		416	319
Baltimore Gas and Electric Company [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Other Cost and Expense, Operating	$ 163		$ 139		$ 326	$ 266

Goodwill (Details) $ in Millions	Jun. 30, 2014 USD ($)
Goodwill [Roll Forward]
Goodwill, beginning balance	$ 2,625
Goodwill, ending balance	2,674
Exelon Generation Co L L C [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	0
Goodwill, ending balance	49
Commonwealth Edison Co [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	2,625
Goodwill, ending balance	$ 2,625

Accounts Receivable (Details) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	$ 293	$ 272
Accounts Receivable Additional Disclosures [Abstract]
Gross Accounts Receivable Pledged as Collateral	0	0
Exelon Generation Co L L C [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	56	57
Commonwealth Edison Co [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	71	62
PECO Energy Co [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	124	107
Accounts Receivable Additional Disclosures [Abstract]
Gross Accounts Receivable Pledged as Collateral	0	0
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables	21	19
Installment plan receivables uncollectible accounts reserve	(20)	(18)
PECO Energy Co [Member] \| Medium Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(4)	(4)
PECO Energy Co [Member] \| High Risk [Member]
Financing Receivable Recorded Investment [Line Items]
Installment plan receivables uncollectible accounts reserve	(15)	(13)
Baltimore Gas and Electric Company [Member]
Accounts Notes And Loans Receivable Net Current [Abstract]
Allowance for uncollectible accounts	$ 42	$ 46

Property, Plant and Equipment (Details) - USD ($)
$ in Millions

6 Months Ended

Jun. 30, 2014

Dec. 31, 2013

$ (14,369)

^[1]

$ (13,713)

^[2]

Property Plant And Equipment Footnotes [Abstract]

51,747

47,330

Inventory write down related to plant retirements

2,411

2,371

Plant Retirement Cost [Abstract]

(7,397)

^[1]

(7,034)

^[2]

Property Plant And Equipment Footnotes [Abstract]

23,743

20,111

Inventory write down related to plant retirements

2,411

2,371

Plant Retirement Cost [Abstract]

(3,325)

(3,184)

Inventory write down related to plant retirements

15,121

14,666

Plant Retirement Cost [Abstract]

(2,969)

(2,935)

6,545

6,384

(2,781)

(2,702)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

$ 6,030

$ 5,864

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,411 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.

Fair Value of Financial Assets and Liabilities (Fair Value Measurements, Recurring and Nonrecurring) (Details) - USD ($)
$ in Millions

Jun. 30, 2014

Dec. 31, 2013

Jun. 30, 2013

$ 1,034

^[1]

$ 1,230

^[2]

(104)

(114)

13,031

11,162

(594)

(573)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

12,437

10,589

Mark-to-market derivative liabilities (current liabilities)

104

114

228

159

Mark-to-market derivative liabilities (noncurrent liabilities)

262

300

Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

217

459

2,572

1,776

164

115

2,529

2,271

5,265

273

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

990

882

Debt securities issued by states of the United States and political subdivisions of the states

416

294

114

2,240

1,784

Residential mortgage-backed securities (non-agency)

325

4,233

3,122

376

314

Nuclear decommissioning trust fund investments subtotal

^[3]

10,423

8,076

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

(5)

Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

172

227

211

296

133

112

Pledged assets for Zion Station decommissioning subtotal

^[4]

395

451

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from pledged assets

Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[5],[6]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(42)

(53)

Supplemental executive retirement plan fair value

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

Derivative Financial Instruments Liabilities [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair value of energy swap contract current liability

Fair value of energy swap contract noncurrent liability

121

176

Commodity Mark To Market Derivative Assets [Member]

4,816

3,960

Effect of netting and allocation of collateral received/(paid)

1,074

1,761

^[7]

(4,815)

(4,424)

Commodity Mark To Market Derivative Liabilities [Member]

1,075

1,297

(4,702)

(3,020)

Effect of netting and allocation of collateral received/(paid)

(1,065)

(1,703)

^[7]

5,305

4,280

Interest Rate Mark To Market Derivative Assets [Member]

(462)

(443)

Effect of netting and allocation of collateral received/(paid)

(28)

Interest Rate Mark To Market Derivative Liabilities [Member]

Effect of netting and allocation of collateral received/(paid)

(30)

(58)

Fair Value Inputs Level 1 [Member]

(28)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,034

^[1]

1,230

^[2]

Effect of netting and allocation of collateral received/(paid)

(31)

5,031

4,533

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

5,033

4,534

Collateral received from counterparties, net of collateral paid to counterparties

Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

151

459

2,572

1,776

164

115

2,736

1,891

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

990

882

Debt securities issued by states of the United States and political subdivisions of the states

Residential mortgage-backed securities (non-agency)

990

882

Nuclear decommissioning trust fund investments subtotal

^[3]

3,877

3,232

Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

Pledged assets for Zion Station decommissioning subtotal

^[4]

Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[5],[6]

Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]

434

493

Effect of netting and allocation of collateral received/(paid)

178

324

^[7]

(569)

(863)

Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

(46)

(434)

(540)

Effect of netting and allocation of collateral received/(paid)

(182)

(328)

^[7]

618

869

Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member]

Effect of netting and allocation of collateral received/(paid)

(21)

(30)

Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Effect of netting and allocation of collateral received/(paid)

(24)

Fair Value Inputs Level 2 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[1]

^[2]

(104)

(114)

6,795

5,575

(234)

(269)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

6,561

5,306

Collateral received from counterparties, net of collateral paid to counterparties

104

114

289

(124)

Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

2,529

2,271

2,529

2,271

273

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

416

294

114

2,059

1,753

Residential mortgage-backed securities (non-agency)

325

3,062

2,209

Nuclear decommissioning trust fund investments subtotal

^[3]

5,954

4,494

Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

172

227

199

251

Pledged assets for Zion Station decommissioning subtotal

^[4]

246

278

Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[5],[6]

Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Assets [Member]

Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]

2,969

2,582

Effect of netting and allocation of collateral received/(paid)

712

1,315

^[7]

(3,119)

(3,131)

Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

562

766

(2,803)

(1,890)

Effect of netting and allocation of collateral received/(paid)

(707)

(1,256)

^[7]

3,408

3,007

Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]

(102)

(139)

Effect of netting and allocation of collateral received/(paid)

(7)

Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Effect of netting and allocation of collateral received/(paid)

(6)

(1)

(34)

Fair Value Inputs Level 3 [Member]

(28)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[1]

^[2]

1,205

1,054

(362)

(305)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

843

749

Collateral received from counterparties, net of collateral paid to counterparties

152

(26)

Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

181

Residential mortgage-backed securities (non-agency)

181

376

314

Nuclear decommissioning trust fund investments subtotal

^[3]

592

350

Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

Pledged assets for Zion Station decommissioning subtotal

133

112

^[4]

133

112

Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[5],[6]

Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]

1,413

885

Effect of netting and allocation of collateral received/(paid)

184

122

^[7]

(1,127)

(430)

Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

470

577

(1,465)

(590)

Effect of netting and allocation of collateral received/(paid)

(176)

(119)

^[7]

1,279

404

Fair Value Inputs Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member]

(362)

(305)

Fair Value Inputs Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,006

^[1]

(29)

12,014

10,888

(379)

(291)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

11,635

10,597

Mark-to-market derivative liabilities (current liabilities)

215

142

Mark-to-market derivative liabilities (noncurrent liabilities)

135

120

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

217

459

2,572

1,776

164

115

2,529

2,271

5,265

4,162

273

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

990

882

Debt securities issued by states of the United States and political subdivisions of the states

416

294

114

2,240

1,784

Residential mortgage-backed securities (non-agency)

325

4,233

3,122

376

314

Nuclear decommissioning trust fund investments subtotal

^[8]

10,423

8,076

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

(5)

Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

172

227

211

296

133

112

Pledged assets for Zion Station decommissioning subtotal

^[9]

395

451

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Net assets (liabilities) excluded from nuclear decommissioning trust fund investments

Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[10]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

Exelon Generation Co L L C [Member] | Derivative Financial Instruments Assets [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair value swap contract noncurrent asset

Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Assets [Member]

4,816

3,960

Effect of netting and allocation of collateral received/(paid)

1,074

1,761

^[11]

(4,815)

(4,424)

Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member]

1,075

1,297

(4,568)

(2,827)

Effect of netting and allocation of collateral received/(paid)

(1,065)

(1,703)

^[11]

5,305

4,280

Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Assets [Member]

(328)

(250)

Effect of netting and allocation of collateral received/(paid)

Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Effect of netting and allocation of collateral received/(paid)

(30)

(32)

(52)

(44)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member]

(22)

(12)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

1,006

^[1]

4,032

4,266

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

4,034

4,267

Collateral received from counterparties, net of collateral paid to counterparties

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

151

459

2,572

1,776

164

115

2,736

$ 1,891

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

990

882

Debt securities issued by states of the United States and political subdivisions of the states

990

882

Nuclear decommissioning trust fund investments subtotal

^[8]

3,877

3,232

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Pledged assets for Zion Station decommissioning subtotal

^[9]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[10]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]

434

493

Effect of netting and allocation of collateral received/(paid)

178

324

^[11]

(569)

(863)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

(46)

(434)

(540)

Effect of netting and allocation of collateral received/(paid)

(182)

(328)

^[11]

618

869

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member]

Effect of netting and allocation of collateral received/(paid)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Effect of netting and allocation of collateral received/(paid)

(24)

(31)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member]

(24)

(31)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[1]

(29)

6,777

5,568

(153)

(180)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

6,624

5,388

Collateral received from counterparties, net of collateral paid to counterparties

289

(124)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

2,529

2,271

2,529

2,271

273

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

416

294

114

2,059

1,753

Residential mortgage-backed securities (non-agency)

325

3,062

2,209

Nuclear decommissioning trust fund investments subtotal

^[8]

5,954

4,494

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

172

227

199

251

Pledged assets for Zion Station decommissioning subtotal

^[9]

246

278

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]

2,969

2,582

Effect of netting and allocation of collateral received/(paid)

712

1,315

^[11]

(3,119)

(3,131)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

562

766

(2,803)

(1,890)

Effect of netting and allocation of collateral received/(paid)

(707)

(1,256)

^[11]

3,408

3,007

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]

(102)

(139)

Effect of netting and allocation of collateral received/(paid)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]

Effect of netting and allocation of collateral received/(paid)

(6)

(1)

(28)

(13)

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

(22)

(12)

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[1]

1,205

1,054

(228)

(112)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

977

942

Collateral received from counterparties, net of collateral paid to counterparties

152

(26)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies

Debt securities issued by states of the United States and political subdivisions of the states

181

181

376

314

Nuclear decommissioning trust fund investments subtotal

^[8]

592

350

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Pledged assets for Zion Station decommissioning subtotal

133

112

^[9]

133

112

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]

1,413

885

Effect of netting and allocation of collateral received/(paid)

184

122

^[11]

(1,127)

(430)

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

470

577

(1,331)

(397)

Effect of netting and allocation of collateral received/(paid)

(176)

(119)

^[11]

1,279

404

(228)

(112)

(8)

(142)

(201)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(141)

(196)

Mark-to-market derivative liabilities (current liabilities)

Mark-to-market derivative liabilities (noncurrent liabilities)

121

176

Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member]

Commonwealth Edison Co [Member] | Derivative Financial Instruments Assets [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair value swap contract noncurrent asset

Commonwealth Edison Co [Member] | Derivative Financial Instruments Liabilities [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Fair value of energy swap contract current liability

Fair value of energy swap contract noncurrent liability

121

176

Commonwealth Edison Co [Member] | Commodity Mark To Market Derivative Liabilities [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member]

^[12]

134

193

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 1 [Member] | Derivative Financial Instruments Liabilities [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member]

^[12]

(8)

(8)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(8)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 2 [Member] | Derivative Financial Instruments Liabilities [Member]

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

^[12]

(134)

(193)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(134)

(193)

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]

^[12]

134

193

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

175

(15)

(17)

184

(15)

(17)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

167

PECO Energy Co [Member] | Rabbi Trust Investments [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

^[13],[14]

Cash surrender value of life insurance investments excluded from Rabbi Trust investments

PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

175

184

PECO Energy Co [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

184

PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member]

^[13],[14]

(15)

(17)

(15)

(17)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(15)

(17)

PECO Energy Co [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

PECO Energy Co [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(5)

(6)

(5)

(6)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member]

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member]

^[14]

Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 1 [Member] | Rabbi Trust Investments [Member]

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member]

^[14]

(5)

(6)

(5)

(6)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]

(5)

(6)

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 2 [Member] | Rabbi Trust Investments [Member]

$ 6

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 3 [Member]

Baltimore Gas and Electric Company [Member] | Fair Value Inputs Level 3 [Member] | Rabbi Trust Investments [Member]

Fair Value Inputs Level 3 [Member]

$ 0

[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[2]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[3]	Excludes net assets (liabilities) of $14 million and $(5) million at June 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[4]	Excludes net assets of $7 million at both June 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[5]	Excludes $34 million and $32 million of the cash surrender value of life insurance investments at June 30, 2014 and December 31, 2013, respectively.
[6]	The mutual funds held by the Rabbi trusts include $42 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at June 30, 2014, and $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013.
[7]	Includes collateral postings to counterparties. Collateral posted to counterparties, net of collateral paid to counterparties, totaled $49 million, $289 million and $152 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.
[8]	Excludes net assets (liabilities) of $14 million and $(5) million at June 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[9]	Excludes net assets of $7 million at both June 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[10]	Excludes $10 million of the cash surrender value of life insurance investments at both June 30, 2014 and December 31, 2013.
[11]	Includes collateral postings to counterparties. Collateral posted to counterparties, net of collateral paid to counterparties, totaled $49 million, $289 million and $152 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2014. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.
[12]	The Level 3 balance includes the current and noncurrent liability of $13 million and $121 million at June 30, 2014, respectively, and $17 million and $176 million at December 31, 2013, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[13]
[14]	Excludes $14 million of the cash surrender value of life insurance investments at both June 30, 2014 and December 31, 2013.

Fair Value of Financial Assets and Liabilities (Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation) (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

$ 752

$ 583

$ 749

$ 656

Included in payable for Zion Station decommissioning

(46)

159

(357)

(2)

(9)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

178

127

308

110

(26)

(20)

(33)

(41)

(12)

(19)

(4)

(30)

(28)

(27)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

843

793

843

793

188

(425)

109

Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

486

210

350

183

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

109

249

(1)

(2)

(12)

(19)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

592

240

592

240

Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

137

104

112

Included in payable for Zion Station decommissioning

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(21)

(5)

(25)

(12)

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

133

111

133

111

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

119

260

272

367

(48)

^[1]

158

^[2]

(360)

^[1]

^[2]

(10)

^[3]

(18)

^[3]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

178

^[4]

(4)

(6)

(4)

(30)

(28)

(20)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

108

431

108

431

187

(427)

108

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Gain (loss) reclassified to results of operating due to the settlement of derivative contracts

(67)

(55)

(140)

Increase (decrease) in fair value related to the swap contract

(3)

(35)

(11)

(86)

Realized gains (losses) related to swap contract with unaffiliated parties

(82)

(119)

(215)

(427)

Fair value of Constellation fair value assets acquired

Other Investments [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

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

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

920

743

942

949

Included in other comprehensive income

(46)

169

(357)

(95)

(219)

Included in payable for Zion Station decommissioning

Included in noncurrent payables to affiliates

(8)

(9)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

178

127

308

110

(26)

(20)

(33)

(41)

(12)

(19)

(4)

(30)

(28)

(27)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

977

878

977

878

184

(425)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair value of Constellation fair value assets acquired

310

Acquisition of marketable securities

Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

486

210

350

183

Included in noncurrent payables to affiliates

(8)

(9)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

109

249

(1)

(2)

(12)

(19)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

592

240

592

240

Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member] | Fair Value Inputs Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

137

104

112

Included in payable for Zion Station decommissioning

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(21)

(5)

(25)

(12)

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

133

111

133

111

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

287

420

465

660

Included in other comprehensive income

(48)

^[5]

168

^[6]

(360)

^[7]

^[2]

(95)

^[3]

^[7]

(219)

^[3]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

178

^[4]

(4)

(6)

(4)

(30)

(28)

(20)

The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities

242

516

242

516

183

(427)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Gain (loss) reclassified to results of operating due to the settlement of derivative contracts

(67)

(15)

(73)

Increase (decrease) in fair value related to the swap contract

(3)

Fair value of Constellation fair value assets acquired

(82)

(215)

Payment For Purchase Contracts

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

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Increase (decrease) in fair value related to the swap contract

Realized gains (losses) related to swap contract with unaffiliated parties

309

(1)

(2)

Increase (decrease) in fair value related to floating-to-fixed energy swap contracts

(19)

(54)

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

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

(168)

(160)

(193)

(293)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Purchases Sales Issuances Settlements [Abstract]

(34)

208

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

(134)

(85)

(134)

(85)

Increase (decrease) in fair value related to the swap contract

(3)

Increase (decrease) in fair value related to floating-to-fixed energy swap contracts

(82)

(215)

$ (9)

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

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Increase (decrease) in fair value related to the swap contract

Increase (decrease) in fair value related to floating-to-fixed energy swap contracts

$ (34)

$ 64

[1]	Includes the increase for the reclassification of $67 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three months ended June 30, 2014.
[2]	Includes the reclassification of $29 million and $77 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2013, respectively.
[3]	Excludes decreases in fair value of $3 million and $11 million and realized losses reclassified due to settlements of $82 million and $215 million associated with Generation’s financial swap contract with ComEd for the three and six months ended June 30, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
[4]	Includes $10 million which Generation was paid to enter into out of the money purchase contracts.
[5]	Includes the reclassification of $##D<gqtdreclasssettlement> million and $##D<gytdreclasssettlement> million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and ##D<curmonth> months ended ##D<cyperiod>, respectively
[6]	) Includes the reclassification of $15 million and $73 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and six months ended June 30, 2013, respectively.
[7]	Includes $##D<gcomedfvpretaxqtd> million of decreases in fair value and $121 million of increases in fair value and realized losses due to settlements of $##D<gcomedreclassqtd> million and $308 million associated with Generation's financial swap contract with ComEd for the ##D<threemonth> and ##D<curmonth> months ended ##D<cyperiod>, respectively. This position was de-designated as a cash flow hedge prior to the merger date. All prospective changes in fair value and reclassifications of realized amounts are being recorded to income offset by the amortization of the frozen mark in OCI. All items eliminate upon consolidation in Exelon's Consolidated Financial Statements

Fair Value of Financial Assets and Liabilities (Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings) (Details) - Fair Value Inputs Level 3 [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Operating Revenue [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	$ (62)	$ 137	$ (330)	$ (22)
Change in the unrealized gains (losses) relating to assets and liabilities held	(10)	156	(435)	39
Purchased Fuel and Electric [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	14	21	(30)	53
Change in the unrealized gains (losses) relating to assets and liabilities held	29	31	8	69
Other, net [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	2	1	3	2
Change in the unrealized gains (losses) relating to assets and liabilities held	2	1	2	1
Exelon Generation Co L L C [Member] \| Operating Revenue [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	(62)	148	(330)	(28)
Change in the unrealized gains (losses) relating to assets and liabilities held	(10)	153	(435)	29
Exelon Generation Co L L C [Member] \| Purchased Fuel and Electric [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	14	20	(30)	52
Change in the unrealized gains (losses) relating to assets and liabilities held	29	30	8	68
Exelon Generation Co L L C [Member] \| Other, net [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	2	1	3	2
Change in the unrealized gains (losses) relating to assets and liabilities held	$ 2	$ 1	$ 2	$ 1

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

6 Months Ended

12 Months Ended

Jun. 30, 2014

Dec. 31, 2013

Forward Power Basis

$ 2.57

Forward Gas Basis

0.41

Fair Value Inputs Level 3 [Member]

Cash collateral excluded

152,000,000

Cash collateral excluded

$ 26,000,000

Outstanding Commitments to invest

430,000,000

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

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

82,000,000

^[1]

488,000,000

^[2]

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

226,000,000

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

16,000,000

8,000,000

^[3]

Forward gas price assets

2.19

2.98

^[3]

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

170,000,000

176,000,000

^[3]

Forward gas price assets

$ 19.84

$ 16.63

^[3]

Renewable factor

128.00%

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

8.00%

15.00%

^[3]

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

260.00%

142.00%

^[3]

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

^[2]

$ (3,000,000)

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

^[1]

$ (8,000,000)

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

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

(13,000,000)

(10,000,000)

^[3]

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

$ (168,000,000)

$ (176,000,000)

^[3]

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

8.00%

14.00%

^[3]

Exelon Generation Co L L C [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member]

260.00%

19.00%

^[3]

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

$ 0

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

^[1]

$ 134,000,000

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

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

^[2]

$ 193,000,000

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

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

Marketability Reserve

3.50%

Forward heat rate

(8.00%)

^[4]

Renewable factor

86.00%

84.00%

Commonwealth Edison Co [Member] | Fair Value Inputs Level 3 [Member] | Business Intersegment Transactions [Member]

Marketability Reserve

8.00%

Forward heat rate

(9.00%)

^[4]

Renewable factor

123.00%

Fair value swap contract current liability

$ 0

[1]	The fair values do not include cash collateral held on level three positions of $152 million as of June 30, 2014.
[2]	The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013 The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $100 and $5.70, respectively.
[3]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[4]	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

Derivative Financial Instruments (Commodity Price Risk) (Details) - GWh	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Exelon Generation Co L L C [Member]
Proprietary Trading Volumes [Abstract]
Proprietary trading activities volume	2,629	1,995	5,123	3,567
Exelon Generation Co L L C [Member] \| Minimum [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Expected generation hedged in next twelve months			92.00%
Expected generation hedged in year two			75.00%
Expected generation hedged in year three			46.00%
Exelon Generation Co L L C [Member] \| Maximum [Member]
Percent Of Expected Generation Being Hedged [Abstract]
Expected generation hedged in next twelve months			95.00%
Expected generation hedged in year two			78.00%
Expected generation hedged in year three			49.00%
PECO Energy Co [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged			30.00%
Baltimore Gas and Electric Company [Member] \| Minimum [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged			10.00%
Baltimore Gas and Electric Company [Member] \| Maximum [Member]
Percent Of Gas Purchases Being Hedged [Abstract]
Estimated percentage of natural gas purchases hedged			20.00%

Derivative Financial Instruments (Interest Rate Risk) (Details)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

USD ($)

Jun. 30, 2013

USD ($)

Jun. 30, 2014

USD ($)

Jun. 30, 2013

USD ($)

Dec. 31, 2013

USD ($)

Cost Of Capital Strategies [Abstract]

Hypothetical increase in interest rates associated with variable-rate debt

0.50%

Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound

$ 4

Mark-to-market derivative assets (noncurrent assets)

$ (2)

(2)

$ (1)

Mark-to-market derivative liabilities (current liabilities)

(1)

Mark-to-market derivative liabilities (noncurrent liabilities)

(27)

(15)

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

(28)

(16)

Derivative, Gain (Loss) on Derivative, Net [Abstract]

Gain on swaps/borrowings

$ 3

$ 4

Loss on swaps/borrowings

(3)

(7)

Interest Rate Risk - Fair Value Hedges [Abstract]

Notional amount of interest rate swaps acquired from merger

150

Fair value of interest rate swaps acquired from merger

Interest Rate Risk - Cash Flow Hedges [Abstract]

262

300

Designated as Hedging Instrument [Member]

(751)

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

1,111

Designated as Hedging Instrument [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member]

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

300

Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member]

Derivative, Gain (Loss) on Derivative, Net [Abstract]

Gain on swaps/borrowings

Loss on swaps/borrowings

(6)

(12)

Interest Rate Risk - Fair Value Hedges [Abstract]

Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments

Interest Rate Risk - Cash Flow Hedges [Abstract]

Increase In Notional Amount Of Derivative Instruments

1,400

1,275

Increase In Notional Amount Of Derivative Instruments1

Designated as Hedging Instrument [Member] | Interest Rate Swap | Cash Flow Hedging [Member]

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

400

Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

Derivative [Member] | Interest Rate Swap

Interest Rate Risk - Cash Flow Hedges [Abstract]

1,550

Mark-to-market derivative assets (noncurrent assets)

(2)

(1)

Mark-to-market derivative liabilities (current liabilities)

(1)

Mark-to-market derivative liabilities (noncurrent liabilities)

(21)

(11)

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

(22)

(12)

(4)

Derivative, Gain (Loss) on Derivative, Net [Abstract]

Gain on swaps/borrowings

$ 2

^[1]

$ 1

^[1]

Interest Rate Risk - Cash Flow Hedges [Abstract]

Percentage of interest rate swap in relation to DOE guarantee

Notional amount of interest rate swap DOE advance

$ 350

Percent of DOE loan advance offset

75.00%

Notional amount of remaining cash flow hedges

135

$ 135

135

120

Exelon Generation Co L L C [Member] | Antelope Valle [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]

(760)

Interest Rate Risk - Cash Flow Hedges [Abstract]

DOE interest rate swap

485

Exelon Generation Co L L C [Member] | Other Solar Projects [Member]

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional amounts on forward starting interest rate swaps

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

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(1)

Mark-to-market derivative liabilities (noncurrent liabilities)

(19)

(10)

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

(20)

(11)

(4)

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

411

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member]

Interest Rate Risk - Cash Flow Hedges [Abstract]

Increase In Notional Amount Of Derivative Instruments

223

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Foreign Currency Fair Value Hedge Derivatives

Interest Rate Risk - Cash Flow Hedges [Abstract]

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

121

Interest Rate Risk - Cash Flow Hedges [Abstract]

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Rate Swap | Fair Value Hedging [Member]

257

Derivative, Gain (Loss) on Derivative, Net [Abstract]

Loss on swaps/borrowings

^[1]

(3)

(5)

(8)

(9)

Interest Rate Risk - Fair Value Hedges [Abstract]

Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments

Interest rate swaps previously held by acquiree

550

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

Interest Rate Risk - Cash Flow Hedges [Abstract]

Notional amounts on forward starting interest rate swaps

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member] | Interest Rate Cash Flow Hedge Derivatives | Cash Flow Hedging [Member]

Mark-to-market derivative assets (noncurrent assets)

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Interest Expense [Member] | Interest Rate Swap | Fair Value Hedging [Member]

Derivative Instruments Gain Loss Recognized In Income Net Footnotes [Abstract]

GainLossOnFairValueHedgesRecognizedInEarnings

(4)

$ (4)

(8)

$ (8)

Exelon Generation Co L L C [Member] | Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(4)

(1)

Mark-to-market derivative liabilities (noncurrent liabilities)

(2)

(1)

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

(6)

(2)

(2)

Exelon Generation Co L L C [Member] | Derivative [Member] | Interest Rate Swap

Interest Rate Risk - Cash Flow Hedges [Abstract]

Exelon Generation Co L L C [Member] | Derivative [Member] | Other Solar Projects [Member]

700

Interest Rate Risk - Cash Flow Hedges [Abstract]

Exelon Generation Co L L C [Member] | Derivative [Member] | Interest Expense [Member] | Antelope Valle [Member]

Interest Rate Risk - Cash Flow Hedges [Abstract]

Exelon Generation Co L L C [Member] | Proprietary Trading [Member]

Mark-to-market derivative assets (noncurrent assets)

^[2]

^[2]

Mark-to-market derivative liabilities (current liabilities)

^[2]

^[2]

(15)

(18)

Mark-to-market derivative liabilities (noncurrent liabilities)

^[2]

(11)

(13)

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

^[2]

(26)

(31)

^[2]

(1)

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

Mark-to-market derivative assets (noncurrent assets)

(18)

^[3]

(18)

^[3]

(19)

(10)

^[3]

(10)

^[3]

(13)

Mark-to-market derivative liabilities (current liabilities)

(28)

^[3]

(28)

^[3]

^[3]

(19)

Mark-to-market derivative liabilities (noncurrent liabilities)

^[3]

(13)

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

^[3]

(32)

^[3]

Other Segments [Member] | Designated as Hedging Instrument [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (noncurrent liabilities)

(6)

(4)

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

(6)

(4)

$ 12

$ 3

[1]	For the three and six months ended June 30, 2014, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing. For the three and six months ended June 30, 2013, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing.
[2]	Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
[3]	Represents the netting of fair value balances with the same counterparty and any associated cash collateral.

Derivative Financial Instruments (Fair Value Measurments) (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

Mar. 31, 2014

Jun. 30, 2013

Mar. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Ineffective portion recognized in income

$ 8

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gain (loss) of reclassifications from accumulated OCI to net income related to settlements of block contracts

$ 0

Net gains (losses) related to interest rate swaps and treasury rate locks

(22)

Cash Flow Hedge Activity Impact [Abstract]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

240

Mark-to-market derivative assets (noncurrent assets)

$ 629

629

$ 727

482

607

Mark-to-market derivative liabilities (current liabilities)

(228)

(159)

Mark-to-market derivative liabilities (noncurrent liabilities)

(262)

(300)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

CorporateNonSegmentMember

(15)

$ 416

(745)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income

Cash Flow Hedge Activity Impact [Abstract]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

141

102

Operating Revenue [Member]

Operating Revenue [Member] | Intersegment Eliminations [Member]

(6)

(7)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Interest Expense [Member] | CorporateNonSegmentMember

(10)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

631

728

444

569

Mark-to-market derivative liabilities (current liabilities)

1,075

1,297

(227)

(158)

Mark-to-market derivative liabilities (noncurrent liabilities)

(235)

(285)

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

(462)

(443)

613

854

CommodityOptionMember

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(13)

370

(693)

(46)

(5)

CommodityOptionMember | Operating Revenue [Member]

(10)

418

(739)

(8)

(1)

(7)

CommodityOptionMember | Operating Revenue [Member] | Intersegment Eliminations [Member]

(7)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(13)

(6)

Interest Rate Swap [Member]

(10)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(4)

(2)

(5)

(3)

(1)

Interest Rate Swap [Member] | CorporateNonSegmentMember

(5)

(2)

(6)

(3)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Interest Rate Swap [Member] | Operating Revenue [Member]

(1)

(1)

Interest Rate Swap [Member] | Interest Expense [Member] | CorporateNonSegmentMember

(1)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Total Cash Flow Hedges [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Accumulated OCI derivative gain - Beginning Balance

$ 120

310

$ 368

120

368

Effective portion of changes in fair value

(10)

^[1]

(11)

^[2]

Accumulated OCI derivative gain - Ending Balance

245

310

245

120

$ 368

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gains (losses) related to interest rate swaps and treasury rate locks

(11)

Net gain (loss) related to effective portion of changes in fair value of treasury rate locks

(18)

(25)

Total Cash Flow Hedges [Member] | Operating Revenue One [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Ineffective portion recognized in income

Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

(86)

(144)

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

3,588

3,718

7,644

6,859

Cash Flow Hedge Activity Impact [Abstract]

Net unrealized pre-tax gain (loss) on effective cash flow hedges

1,928

Net unrealized pre-tax gain (loss) on effective cash flow hedges related to swap contract

693

Expected reclassification from accumulated other comprehensive income to results of operations

Expected reclassification from accumulated other comprehensive income to results of operations related to fair value of swap contracts

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

236

102

459

Change in cash flow hedge ineffectiveness

Cash flow hedge ineffectiveness adjustment to accumulated other comprehensive income

Mark-to-market derivative assets with affiliate (current assets)

629

727

Mark-to-market derivative assets (noncurrent assets)

464

600

Mark-to-market derivative assets with affiliate (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(215)

(142)

Mark-to-market derivative liabilities (noncurrent liabilities)

(135)

(120)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

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

(15)

426

(745)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(83)

504

(843)

(82)

Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member]

(6)

(7)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Exelon Generation Co L L C [Member] | Interest Expense [Member]

(76)

107

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Exelon Generation Co L L C [Member] | Derivative [Member]

(1)

(2)

(1)

(3)

Mark-to-market derivative assets (noncurrent assets)

631

^[3]

631

^[3]

728

^[4]

444

^[3]

444

^[3]

569

^[4]

Mark-to-market derivative liabilities (current liabilities)

1,075

^[3]

1,075

^[3]

1,297

^[4]

(214)

^[3]

(214)

^[3]

(141)

^[4]

Mark-to-market derivative liabilities (noncurrent liabilities)

(114)

^[3]

(114)

^[3]

(109)

^[4]

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

(328)

^[3]

(328)

^[3]

(250)

^[4]

747

^[3]

747

^[3]

1,047

^[4]

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

Mark-to-market derivative assets (noncurrent assets)

3,422

2,616

1,394

1,344

Mark-to-market derivative liabilities (current liabilities)

4,816

3,960

(3,354)

(2,023)

Mark-to-market derivative liabilities (noncurrent liabilities)

(1,214)

(804)

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

(4,568)

(2,827)

248

1,133

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Current assets collateral offset

(126)

Noncurrent assets collateral offset

(56)

Current liabilities collateral offset

(198)

(12)

Noncurrent liabilities collateral offset

(110)

Total cash collateral received net of cash collateral posted

490

144

Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member]

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Fair value swap contract noncurrent asset

Noncurrent liability DOE interest rate swap

Exelon Generation Co L L C [Member] | Proprietary Trading [Member]

Mark-to-market derivative assets (noncurrent assets)

925

1,476

149

285

Mark-to-market derivative liabilities (current liabilities)

1,074

1,761

(900)

(1,410)

Mark-to-market derivative liabilities (noncurrent liabilities)

(165)

(293)

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

(1,065)

(1,703)

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

Mark-to-market derivative assets (noncurrent assets)

^[5]

(3,716)

(3,364)

^[5]

(1,099)

(1,060)

Mark-to-market derivative liabilities (current liabilities)

^[5]

(4,815)

(4,424)

^[5]

4,040

3,292

Mark-to-market derivative liabilities (noncurrent liabilities)

^[5]

1,265

988

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

^[5]

5,305

4,280

^[5]

490

(144)

Exelon Generation Co L L C [Member] | CommodityOptionMember

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(13)

383

(693)

(46)

(18)

Exelon Generation Co L L C [Member] | CommodityOptionMember | Operating Revenue [Member]

(10)

428

(739)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(124)

460

(975)

(26)

137

(56)

(79)

504

(838)

(82)

(8)

(1)

(7)

Exelon Generation Co L L C [Member] | CommodityOptionMember | Purchased Power And Fuel [Member]

(7)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

111

(77)

282

(42)

(183)

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

(76)

107

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(4)

(2)

(5)

(3)

(1)

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Operating Revenue [Member]

(5)

(2)

(6)

(3)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(3)

(4)

(1)

(4)

(5)

(1)

(1)

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Purchased Power And Fuel [Member]

(1)

Other Derivatives Not Designated As Hedging Instruments [Abstract]

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Interest Expense [Member]

Other Derivatives Not Designated As Hedging Instruments [Abstract]

(1)

(2)

(1)

(3)

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member]

(1)

(2)

(1)

(3)

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Accumulated OCI derivative gain - Beginning Balance

119

^[6]

397

^[7],[8]

532

^[9],[10]

119

^[6]

532

^[9],[10]

532

^[9],[10]

Effective portion of changes in fair value

Accumulated OCI derivative gain - Ending Balance

^[6]

255

^{[7],[8],[9],[10]}

397

^[7],[8]

^[6]

255

^{[7],[8],[9],[10]}

119

^[6]

532

^[9],[10]

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Unrealized gain (loss) related to fair value of swap contract

133

420

Unrealized gain (loss) related to fair value of block contract

Net gain (loss) related to effective portion of changes in fair value of swap contract

133

Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract

(58)

Net gains (losses) related to interest rate swaps and treasury rate locks

$ 3

(11)

$ 16

$ (20)

Net gain (loss) related to effective portion of changes in fair value of treasury rate locks

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Ineffective portion recognized in income

Accumulated OCI derivative gain - Ending Balance

(133)

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

(38)

(62)

Exelon Generation Co L L C [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedge reclassified from AOCI to net income

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

(142)

^[11]

(277)

Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member]

Footnotes To Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Net gain (loss) related to effective portion of changes in fair value of swap contract

Net gains (losses) related to interest rate swaps and treasury rate locks

(15)

Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

(38)

(62)

Mark-to-market derivative liabilities (current liabilities)

(13)

(17)

Mark-to-market derivative liability with affiliate (current liability)

Mark-to-market derivative liabilities (noncurrent liabilities)

(121)

(176)

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]

Mark-to-market derivative liabilities (current liabilities)

(13)

^[12]

(13)

^[12]

(17)

Mark-to-market derivative liabilities (noncurrent liabilities)

(121)

^[12]

(121)

^[12]

(176)

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

(134)

^[12]

(134)

^[12]

(193)

(134)

^[12]

(134)

^[12]

(193)

Commonwealth Edison Co [Member] | Cash Flow Hedging [Member]

Footnotes To Derivative Instruments In Statement Of Financial Position Fair Value [Abstract]

Fair value swap contract current liability

Fair value swap contract noncurrent liability

Cash Flow Hedge Accumulated Other Comprehensive Income [Abstract]

Reclassifications from accumulated OCI to net income

651

$ 649

1,689

$ 1,525

$ 0

[1]	Includes $18 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the three months ended June 30, 2013.
[2]	Includes $22 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.
[3]	Current and noncurrent assets are shown net of collateral of $(126) million and $(56) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(198) million and $(110) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $490 million at June 30, 2014.
[4]	(b) Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral received, net of cash collateral posted and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.
[5]	Exelon and Generation net all available amounts allowed under the derivative accounting 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.
[6]	Excludes $9 million of gains and $15 million of losses, net of taxes, related to interest rate swaps and treasury locks as of June 30, 2014 and December 31, 2013, respectively.
[7]	Excludes $11 million and $16 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of June 30, 2013 and March 31, 2013, respectively.
[8]	Includes $58 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of March 31, 2013.
[9]	Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of June 30, 2013 and December 31, 2012, respectively.
[10]	Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012.
[11]	Includes $58 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd
[12]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative Financial Instruments (Credit Risk) (Details) - USD ($) $ in Millions	Jun. 30, 2014	Dec. 31, 2013
Exelon Generation Co L L C [Member]
Counter Party With Exposure [Abstract]
Cash Collateral Held		$ 206
Letters Of Credit Held		$ 34
Credit Risk [Abstract]
Financial institutions	$ 185
Investor-owned utilities, marketers and power producers	360
Energy cooperative and municipalities	729
Other	22
Exelon Generation Co L L C [Member] \| Commonwealth Edison Co Affiliate [Member]
Due From Related Parties [Abstract]
Net receivable from electric utility	6
Exelon Generation Co L L C [Member] \| Total Exposure Before Credit Collateral [Member]
Credit Risk [Abstract]
Investment grade	1,095
Non-investment grade	12
No external ratings - internally rated - investment grade	286
No external ratings - internally rated - non-investment grade	21
Total	1,414
Exelon Generation Co L L C [Member] \| Credit Collateral [Member]
Credit Risk [Abstract]
Investment grade	103
Non-investment grade	9
No external ratings - internally rated - investment grade	2
No external ratings - internally rated - non-investment grade	4
Total	118
Exelon Generation Co L L C [Member] \| Net Exposure [Member]
Credit Risk [Abstract]
Investment grade	992
Non-investment grade	3
No external ratings - internally rated - investment grade	284
No external ratings - internally rated - non-investment grade	17
Total	1,296
Exelon Generation Co L L C [Member] \| Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Credit Risk [Abstract]
Investment grade	1
Non-investment grade	0
No external ratings - internally rated - investment grade	1
No external ratings - internally rated - non-investment grade	0
Total	2
Exelon Generation Co L L C [Member] \| Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Credit Risk [Abstract]
Investment grade	417
Non-investment grade	0
No external ratings - internally rated - investment grade	189
No external ratings - internally rated - non-investment grade	0
Total	606
Commonwealth Edison Co [Member]
Counter Party With Exposure [Abstract]
Cash Collateral Held	19
Commonwealth Edison Co [Member] \| Net Exposure [Member]
Credit Risk [Abstract]
Total	2
PECO Energy Co [Member]
Natural Gas Supply And Management Agreement Credit Exposure [Abstract]
Credit exposure under natural gas supply and management agreements	6
PECO Energy Co [Member] \| PECO Energy Co Affiliate [Member]
Due From Related Parties [Abstract]
Net receivable from affiliated electric and gas utility	23
Baltimore Gas and Electric Company [Member]
Natural Gas Supply And Management Agreement Credit Exposure [Abstract]
Credit exposure under off system sales	1
Baltimore Gas and Electric Company [Member] \| Baltimore Gas And Electric Company Affiliate [Member]
Due From Related Parties [Abstract]
Net receivable from affiliated electric and gas utility	36
Baltimore Gas and Electric Company [Member] \| Net Exposure [Member]
Credit Risk [Abstract]
Total	$ 38

Derivative Financial Instruments (Collateral and Contingent-Related Features) (Details) - USD ($)
$ in Millions

Jun. 30, 2014

Dec. 31, 2013

Collateral And Contingent Related Features [Abstract]

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

^[1]

$ (1,102)

$ (1,056)

Contractual right of offset related to derivative assets

^[2]

825

846

Net liability position after contractual right of offset

^[3]

(277)

(210)

Incremental collateral for loss of investment grade credit rating

2,000

Cash collateral held

206

Cash collateral posted

623

Letters of credit held

Letters of credit posted

466

364

Master Netting Arrangements [Abstract]

Cash collateral received not offset against net derivative positions

$ 10

Collateral And Contingent Related Features [Abstract]

Cash collateral held

Swap Contract Collateral Posting Limit [Abstract]

Credit Derivative, Collateral Held Directly or by Third Parties Monetary Amount

Collateral And Contingent Related Features [Abstract]

Incremental collateral for loss of investment grade credit rating

Collateral And Contingent Related Features [Abstract]

Incremental collateral for loss of investment grade credit rating

$ 73

[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.

Debt and Credit Agreements (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Apr. 02, 2014

Dec. 31, 2013

Mar. 14, 2013

$ 648

Derivative, Gain on Derivative

131

$ 3

$ 4

DebtInstrumentCollateralAmount

1,900

18,133

17,623

8,500

621

341

BridgeLoan

$ 4,200

4,200

$ 7,200

$ 228

246

$ 445

863

EquitySecuritiesOfferingTotalNumber

57,500,000

Share Price

$ 35

UnderwritingDiscount

$ 60

underwriting fees

$ 35

Coupon rate of interest on Equity Unites

2.50%

ForwardContractPaymentRate

4.40%

Per unit conversion rate for Equity Security units

$ 33.96

Shares issueable at June 30, 2014 ifsettlement occurred

4,000,000

Shares to be used in Physical settlement

57,700,000

Daily accretion rate less spread

0.75%

Maximum [Member]

CommonSharesIssueableAt Maturity

1.4286

Proceeds at forward price

$ 1,950

Exelon's Stock Price At Maturity

43.75

Minimum [Member]

CommonSharesIssueableAt Maturity

1.1429

Proceeds at forward price

$ 1,850

Exelon's Stock Price At Maturity

35.00

BridgeLoanMember

Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Fair Value Hedging [Member]

$ 9

Derivative, Gain on Derivative

$ 3

$ 5

Footnotes To Long-Term Debt [Abstract]

Notional amount of interest rate cash flow hedge derivatives

1,400

1,275

convertible debt member

Proceeds from the issuance of subordinate debt

1,100

SubordinatedLongTermDebt

$ 1,200

Per unit conversion rate for Equity Security units

$ 50

Long Term Debt Issuances [Member]

Long Term Debt Issuances [Member] | Suboridanted Debentures [Member]

2.50%

Exelon Corporate [Member]

SubordinatedLongTermDebt

1,150

0.275

Exelon Corporate [Member] | Syndicated Revolver [Member]

1.275

Exelon Corporate [Member] | Letter of Credit [Member] | DebtInstrumentRedemptionPeriodThreeMember

$ 500

100

Long-term debt to affiliate

948

1,523

Long-term debt to PECO Energy Transition Trust due within one year

563

Derivative, Gain on Derivative

^[1]

Footnotes To Line Of Credit Facility [Abstract]

5,944

5,645

Credit facility agreements with minority and community banks

$ 53

$ 74

$ 77

$ 147

$ 142

0.275

Exelon Generation Co L L C [Member] | Commercial Paper [Member]

1.275

Commercial paper borrowings

$ 0

Exelon Generation Co L L C [Member] | Letter of Credit [Member]

Exelon Generation Co L L C [Member] | Letter of Credit [Member] | DebtInstrumentRedemptionPeriodOneMember

100

Exelon Generation Co L L C [Member] | Letter of Credit [Member] | DebtInstrumentRedemptionPeriodTwoMember

300

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

100

Footnotes To Long-Term Debt [Abstract]

Notional amount of interest rate cash flow hedge derivatives

121

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

Footnotes To Long-Term Debt [Abstract]

Notional amount of interest rate cash flow hedge derivatives

257

Exelon Generation Co L L C [Member] | ExgenRenewablesI425June62021[Member] | Interest Rate Swap [Member]

Non-Recourse Debt - Interest Rate Swap

$ 240

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | CEU Credit Agreement [Member]

4.40%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | UpstreamGasLending221July222016[Member]

$ 9

2.21%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | NuclearFuelPurchaseContract3.350%June302018 [Member]

$ 3

3.35%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | DOE Financing Project [Member]

$ 38

Minimum interest rate on long-term debt

2.33%

Maximum interest rate on long-term debt

3.092%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | DOE Financing Project [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member]

300

$ 300

Minimum interest rate on long-term debt

0.02535%

Maximum interest rate on long-term debt

0.02922%

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | DOE Financing Project [Member] | Floating Rate Debt [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member]

Exelon Generation Co L L C [Member] | Long Term Debt Issuances [Member] | Non Recourse Debt [Member] | ExgenRenewablesI425June62021[Member]

197

$ 197

4.25%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member]

$ 300

$ 3

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Armstrong Co Tax Exempt, 5% December 1,2042 [Member]

450

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Sacramento PV Energy [Member]

125

2.56%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Clean Horizons [Member]

$ 1

2.56%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | MEDCO Tax-Exempt Bonds [Member]

$ 1

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Continental Wind 6000 February 28, 2033 [Member] | Continetal Wind [Member]

6.00%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Capital Lease Obligations [Member] | Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member]

$ 11

7.83%

$ 2

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Senior Notes [Member] | SeniorSecuredNotes525January152014Member [Member]

5.35%

Exelon Generation Co L L C [Member] | Long Term Debt Retirements [Member] | Pollution Control Notes [Member] | Fixed Rate Debt [Member]

$ 500

4.10%

$ 20

206

Footnotes To Line Of Credit Facility [Abstract]

5,448

5,058

Credit facility agreements with minority and community banks

$ 498

498

184

$ 76

$ 153

422

Additional amounts available upon request under current credit facilities

$ 500

0.075

Amount Of Aggregate Letters of Credit Available

1.075

500

Revolver Under Amendment

$ 1,000

Commonwealth Edison Co [Member] | Commercial Paper [Member]

Commercial paper borrowings

$ 498

Commonwealth Edison Co [Member] | Syndicated Revolver [Member]

Commonwealth Edison Co [Member] | Long Term Debt Issuances [Member] | First Mortgage Bonds [Member] | FirstMortgageBondSeries215January152019 [Member]

$ 1,000

2.15%

Commonwealth Edison Co [Member] | Long Term Debt Issuances [Member] | First Mortgage Bonds [Member] | FirstMortgageBondSeries47January152044Member [Member]

$ 300

4.70%

Commonwealth Edison Co [Member] | Long Term Debt Retirements [Member] | First Mortgage Bonds [Member] | FirstMortgageBond163January12014 [Member]

$ 350

1.63%

Commonwealth Edison Co [Member] | Long Term Debt Retirements [Member] | Pollution Control Notes [Member] | Fixed Rate Debt [Member]

$ 600

5.85%

$ 17

184

Footnotes To Line Of Credit Facility [Abstract]

1,947

Credit facility agreements with minority and community banks

$ 21

$ 25

$ 50

PECO Energy Co [Member] | Syndicated Revolver [Member]

0.900

$ 600

258

Footnotes To Line Of Credit Facility [Abstract]

1,904

1,941

Credit facility agreements with minority and community banks

$ 70

$ 135

$ 23

$ 28

$ 47

$ 58

Baltimore Gas and Electric Company [Member] | Commercial Paper [Member]

Commercial paper borrowings

$ 70

Baltimore Gas and Electric Company [Member] | Syndicated Revolver [Member]

Baltimore Gas and Electric Company [Member] | Long Term Debt Issuances [Member] | Senior Notes [Member]

$ 600

Baltimore Gas and Electric Company [Member] | Long Term Debt Retirements [Member] | Rate Stabilization Bonds, April 1, 2017 [Member]

3.35%

5.72%

$ 35

Baltimore Gas and Electric Company [Member] | Long Term Debt Retirements [Member] | Medium Term, Notes 6.73% 6.75% June 15, 2012 [Member]

$ 6

$ 1

[1]

For the three and six months ended June 30, 2014, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing. For the three and six months ended June 30, 2013, the loss on Generation swaps included $4 million and $8 million realized in earnings, respectively, with an immaterial amount excluded from hedge effectiveness testing.

Debt and Credit Agreements (Maturitites of Long-term Debt) (Details) $ in Millions	Jun. 30, 2014 USD ($)
Long Term Debt By Maturity [Abstract]
Long Term Debt	$ 131
Exelon Generation Co L L C [Member]
Long Term Debt By Maturity [Abstract]
Long Term Debt	$ 1

Income Taxes (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2011

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2012

Jun. 30, 2011

Dec. 31, 2012

Dec. 31, 2011

Dec. 31, 2010

Dec. 31, 2013

Dec. 31, 1999

35.00%

State income taxes, net of Federal income tax benefit

2.10%

4.10%

(0.60%)

8.60%

Qualified nuclear decommissioning trust fund income (losses)

4.10%

(1.80%)

5.90%

2.80%

(2.00%)

0.10%

(3.20%)

(0.00%)

(0.10%)

(0.00%)

0.10%

0.00%

0.10%

(0.20%)

(0.40%)

(1.80%)

(1.20%)

0.20%

(1.60%)

(1.40%)

(3.00%)

(3.50%)

(0.80%)

(1.40%)

(2.40%)

(3.10%)

Fines and Penalties

(2.80%)

(1.20%)

(0.30%)

(3.10%)

0.10%

(2.00%)

(1.90%)

Accounting for Uncertainty in Income Taxes [Abstract]

33.20%

32.50%

25.60%

37.10%

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

$ 1,858

$ 2,175

1999 Sale of Fossil Generating Assets [Abstract]

Deferred tax gain on sale of fossil generating assets

$ 2,800

Deferred tax gain under involuntary conversion provisions of the IRC

1,600

Deferred tax gain under like-kind exchange provisions of the IRC

$ 1,200

IRS asserted penalties for understatement of tax

265

Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position

830

IRS asserted penalties for understatement of tax related to like-kind exchange

FIN 48 Tax Remeasurement Interest Expense

$ 65

Tax Settlement [Abstract]

Payment to IRS for open tax positions

$ 302

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Gross Deferred Income tax benefit recorded as a result of re-apportionment of state income taxes

$ 116

$ 3

Deferred state tax liability resulting from purchase accounting

DeferredStateTaxAssetFromStateTaxApportionment

TaxesPayableCurrent

Taxes Payable Current

285

Income Tax Expense Benefit Continuing Operations [Line Items]

Deferred Tax Impact [Member]

$ 277

$ 239

$ 224

$ 294

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Gross Deferred Income tax benefit recorded as a result of re-apportionment of state income taxes

$ 8

Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes

$ 22

$ 1

35.00%

State income taxes, net of Federal income tax benefit

1.70%

3.50%

(14.70%)

0.40%

Qualified nuclear decommissioning trust fund income (losses)

6.00%

(2.70%)

27.70%

4.80%

(2.90%)

0.20%

(14.80%)

(0.00%)

(0.20%)

(0.00%)

(0.10%)

0.00%

0.00%

(0.40%)

(0.50%)

(2.50%)

(4.90%)

0.00%

0.00%

(5.60%)

(1.10%)

(2.20%)

(11.10%)

(0.00%)

Fines and Penalties

(4.90%)

(0.40%)

0.10%

^[1]

(8.90%)

3.10%

(2.90%)

(8.80%)

Accounting for Uncertainty in Income Taxes [Abstract]

34.90%

31.20%

^[1]

(0.50%)

32.30%

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

$ 1,403

1,415

Information by nature of uncertainty related to unrecognized tax benefits

225

Status Of Like Kind Exchange Position [Abstract]

FIN 48 Tax Remeasurement Current Tax Expense (Benefit)

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Gross Deferred Income tax benefit recorded as a result of re-apportionment of state income taxes

Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes

$ 7

Deferred state tax liability resulting from purchase accounting

$ 14

Income Tax Expense Benefit Continuing Operations [Line Items]

Exelon Generation Co L L C [Member] | Deferred Tax Impact [Member]

$ 199

$ 149

$ (1)

$ 148

Income tax benefit recorded as a result of re-apportionment of state income taxes [Abstract]

Gross Deferred Income tax expense recorded as a result of re-apportionment of state income taxes

$ 11

35.00%

State income taxes, net of Federal income tax benefit

4.60%

5.60%

5.00%

4.10%

Qualified nuclear decommissioning trust fund income (losses)

0.00%

0.00%

(0.00%)

0.40%

0.20%

0.00%

(0.30%)

5.70%

(0.40%)

(0.50%)

(4.90%)

(0.00%)

(8.70%)

0.20%

0.40%

^[1]

0.20%

5.50%

0.00%

(0.30%)

Accounting for Uncertainty in Income Taxes [Abstract]

39.30%

40.70%

39.60%

36.40%

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

$ 170

324

1999 Sale of Fossil Generating Assets [Abstract]

Deferred tax gain under like-kind exchange provisions of the IRC

155

IRS asserted penalties for understatement of tax

170

Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position

310

Status Of Like Kind Exchange Position [Abstract]

172

FIN 48 Tax Remeasurement Interest Expense

FIN 48 Tax Remeasurement Current Tax Expense (Benefit)

Income Tax Expense Benefit Continuing Operations [Line Items]

$ 72

$ 66

$ 137

$ 8

35.00%

State income taxes, net of Federal income tax benefit

(0.50%)

2.90%

0.40%

2.90%

Qualified nuclear decommissioning trust fund income (losses)

0.00%

0.00%

(0.00%)

0.00%

0.00%

(0.10%)

0.00%

(13.20%)

(8.60%)

(10.80%)

(0.10%)

(0.00%)

(7.50%)

0.30%

(0.10%)

0.30%

0.00%

0.00%

Accounting for Uncertainty in Income Taxes [Abstract]

21.50%

29.10%

24.80%

30.30%

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

$ 44

Status Of Like Kind Exchange Position [Abstract]

$ 0

FIN 48 Tax Remeasurement Interest Expense

$ 22

Income Tax Expense Benefit Continuing Operations [Line Items]

$ 23

$ 32

$ 57

$ 87

35.00%

State income taxes, net of Federal income tax benefit

4.10%

5.60%

5.00%

5.70%

Qualified nuclear decommissioning trust fund income (losses)

0.00%

0.00%

(0.00%)

0.20%

(0.30%)

0.20%

0.00%

(0.70%)

(0.60%)

(0.30%)

0.20%

5.10%

(0.70%)

0.40%

(0.30%)

(0.00%)

(0.60%)

(1.30%)

0.10%

(0.20%)

0.00%

Income Tax Expense Benefit Continuing Operations [Line Items]

42.40%

39.00%

40.40%

39.80%

Nuclear Decommissioning Trust Fund Investments [Abstract]

$ 14

$ 16

$ 72

$ 70

[1]

Asset Retirement Obligation (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Percent of additional decommissioning shortfall with recourse

$ 50

5.00%

$ 10,437

$ 8,071

Nuclear Decommissioning Obligation [Line Items]

115

402

$ 458

402

$ 458

458

^[1]

357

414

^[2]

109

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

^[3]

575

498

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[4]

172

(102)

234

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[5],[6]

128

(40)

141

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

^[7]

4,855

154

(3)

Footnotes To Asset Retirement Obligation [Abstract]

^[7]

6,707

4,855

Nuclear Decommissioning Trust Fund Investments [Abstract]

Percent of additional decommissioning shortfall with recourse

$ 50

5.00%

$ 10,437

8,071

Nuclear Decommissioning Obligation [Line Items]

115

402

458

402

458

^[1]

357

414

^[2]

109

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

^[3]

575

498

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[4]

172

(102)

234

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[5],[6]

128

$ (40)

141

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

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

$ 2

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

^[7]

4,855

154

(3)

Footnotes To Asset Retirement Obligation [Abstract]

^[7]

6,707

4,855

Nuclear Decommissioning Trust Fund Investments [Abstract]

$ 9

[1]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	Cumulative withdrawals since September 1, 2010.
[4]	Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets.
[5]	Excludes $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended June 30, 2014 and 2013, respectively, and $20 million and $3 million of net unrealized gains related to the Zion Station pledged assets for the six months ended June 30, 2014 and 2013, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets.
[6]	Net unrealized gains (losses) 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.
[7]	Includes $9 million as the current portion of the ARO at June 30, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Nuclear Decommissioning (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Current annual recovery of decommissioning costs

$ 10,437

$ 8,071

Decommissioning Shortfall Percentage

$ 50

5.00%

Decommissioning [Abstract]

$ 402

$ 458

$ 402

$ 458

458

^[1]

357

414

^[2]

109

^[3]

575

498

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

115

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[4]

172

(102)

234

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[5],[6]

128

(40)

141

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

^[7]

4,855

154

(3)

Footnotes To Asset Retirement Obligation [Abstract]

^[7]

6,707

4,855

Nuclear Decommissioning Trust Fund Investments [Abstract]

10,437

8,071

Decommissioning Shortfall Percentage

$ 50

5.00%

Decommissioning [Abstract]

$ 402

458

$ 402

458

^[1]

357

414

^[2]

109

^[3]

575

498

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

115

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[4]

172

(102)

234

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[5],[6]

128

$ (40)

141

Footnotes To Unrealized Gains Losses On NDT Funds [Abstract]

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

$ 2

Asset Retirement Obligation Roll Forward Analysis [Roll Forward]

^[7]

4,855

154

(3)

Footnotes To Asset Retirement Obligation [Abstract]

^[7]

6,707

4,855

$ 9

Nuclear Decommissioning Trust Fund Investments [Abstract]

Current annual recovery of decommissioning costs

$ 24

[1]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	Cumulative withdrawals since September 1, 2010.
[4]	Net unrealized gains (losses) related to Generation's NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon's Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation's Consolidated Balance Sheets.
[5]	Excludes $ 10 million and $2 million of net unrealized gains related to the Zion Station pledged assets for the three months ended June 30, 2014 and 2013, respectively, and $20 million and $3 million of net unrealized gains related to the Zion Station pledged assets for the six months ended June 30, 2014 and 2013, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon's and Generation's Consolidated Balance Sheets.
[6]	Net unrealized gains (losses) 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.
[7]	Includes $9 million as the current portion of the ARO at June 30, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Retirement Benefits (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Mar. 31, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:

Changes in plan assets and benefit obligations recognized in OCI

$ 1

$ (12)

Increase in regulatory assets due valuation received by Exelon for its legacy pension and other postretirement benefit obligations.

Increase in regulatory liabilities due to updated valuation of Exelon's legacy pension and postretirement benefit obligations

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

$ 499

$ 284

Defined Contribution Plan Contributions By Employer [Abstract]

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

$ 21

CENGMember [Member]

Amount included in capital and operating & maintenance expense

Defined Contribution Plan Contributions By Employer [Abstract]

Business Services Company [Member]

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

^[1]

Defined Contribution Plan Contributions By Employer [Abstract]

Business Services Company [Member] | Remeasurement [Member]

Design Changes Impact [Abstract]

Other comprehensive income (loss) due to design changes

(259)

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

210

120

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

139

173

Defined Contribution Plan Contributions By Employer [Abstract]

Exelon Generation Co L L C [Member] | CENGMember [Member]

Defined Contribution Plan Contributions By Employer [Abstract]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

236

119

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

154

Defined Contribution Plan Contributions By Employer [Abstract]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

Defined Contribution Plan Contributions By Employer [Abstract]

Pension And Other Postretirement Benefit Contributions [Abstract]

Pension and non-pension postretirement benefit contributions

Defined Benefit Plan Expense Included In Capital And Operational And Maintenance Expense [Abstract]

Amount included in capital and operating & maintenance expense

Defined Contribution Plan Contributions By Employer [Abstract]

Pension Plans Defined Benefit [Member]

^[2]

138

^[2]

159

184

^[2]

163

367

^[2]

326

Change in plan assets:

^[2]

138

^[2]

159

Amortization of actuarial gain (loss)

184

^[2]

163

367

^[2]

326

Settlement charges

^[2]

104

^[2]

141

209

^[2]

281

Prior service cost (credit)

^[2]

Expected return on assets

(242)

^[2]

(254)

(483)

^[2]

(508)

Contractual termination benefit cost

Valuation Adjustment Impact [Abstract]

119

^[2]

133

238

^[2]

265

Benefit obligation increase (decrease) reflecting actual census data

Pension Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member] | CENGMember [Member]

Expected return on assets

(9)

Other Postretirement Benefit Plans Defined Benefit [Member]

^[2]

^[2]

101

^[2]

^[2]

Amortization of actuarial gain (loss)

^[2]

101

^[2]

^[2]

Prior service cost (credit)

(30)

^[2]

(6)

(34)

^[2]

(10)

Expected return on assets

(38)

^[2]

(33)

(76)

^[2]

(66)

Curtailments charges

Contractual termination benefit cost

Changes in plan assets and benefit obligations recognized in OCI and regulatory assets:

^[2]

144

Amortization of transition obligation

$ 0

Valuation Adjustment Impact [Abstract]

Benefit obligation increase (decrease) reflecting actual census data

$ 12

Other Postretirement Benefit Plans Defined Benefit [Member] | Subsequent Event [Member]

DefinedBenefitPlanBenefitObligationPeriodIncreaseDecrease

(790)

Other Postretirement Benefit Plans Defined Benefit [Member] | NetPeriodicBenefitCostDecrease [Member] | Subsequent Event [Member]

Other Postretirement Benefit Plans Defined Benefit [Member] | Business Services Company [Member] | Remeasurement [Member]

Plan amendments

(149)

Valuation Adjustment Impact [Abstract]

Regulatory asset increase (decrease) due to updated valuation adjustment

125

Design Changes Impact [Abstract]

Regulatory Asset increase (decrease) due to design changes

(240)

Other Postretirement Benefit Plans Defined Benefit [Member] | Exelon Generation Co L L C [Member] | CENGMember [Member]

Defined Benefit Plan Disclosure [Line Items]

$ 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 or BGE amounts above.
[2]	Excludes components of CENG’s net periodic benefit costs for the period April 1, 2014 to June 30, 2014 as presented in the below table.

Retirement Benefits - Assumptions Used In Calculations (Details)		1 Months Ended
	Apr. 02, 2014	Jun. 30, 2014	Apr. 30, 2014
Pension Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets			7.00%
Discount rate			4.80%
Pension Plans Defined Benefit [Member] \| CENGMember [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets	7.75%
Pension Plans Defined Benefit [Member] \| CENGMember [Member] \| Maximum [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.30%
Pension Plans Defined Benefit [Member] \| CENGMember [Member] \| Minimum [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	3.60%
Other Postretirement Benefit Plans Defined Benefit [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Expected return on plan assets		6.59%
Discount rate		4.90%	4.30%
Other Postretirement Benefit Plans Defined Benefit [Member] \| CENGMember [Member]
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	4.55%

Retirement Benefits - Fair Value Recurring Basis (Details) - USD ($)
$ in Millions

Jun. 30, 2014

Dec. 31, 2013

Common Stock without par - Authorized

$ 1,034

^[1]

$ 1,230

^[2]

[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[2]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.

Retirement Benefits - Additional (Details) $ in Millions	Jun. 30, 2014 USD ($)
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	$ 317
Expected non-qualified pension plan contributions	18
Expected other postretirement benefit plan contributions	290
Business Services Company [Member] \| CENGMember [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	51
Exelon Generation Co L L C [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	169
Expected non-qualified pension plan contributions	9
Expected other postretirement benefit plan contributions	128
Exelon Generation Co L L C [Member] \| CENGMember [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	53
Expected non-qualified pension plan contributions	3
Expected other postretirement benefit plan contributions	5
Commonwealth Edison Co [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	119
Expected non-qualified pension plan contributions	1
Expected other postretirement benefit plan contributions	121
PECO Energy Co [Member]
Defined Benefit Plan Contributions [Abstract]
Expected qualified pension plan contributions	11
Expected other postretirement benefit plan contributions	4
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Contributions [Abstract]
Expected non-qualified pension plan contributions	1
Expected other postretirement benefit plan contributions	$ 18

Severance and Plant Retirements (Details) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	$ 4	$ 1
Restructuring Reserve [Roll Forward]
Severance Charges	2
Payments	3
Business Acquisition, Costs Recognized Post Merger [Abstract]
Business Acquisition Charitable Contributions Per Year	7
Plant Retirement Cost [Abstract]
Inventory write down related to plant retirements	3
CENGMember [Member]
Restructuring Reserve [Roll Forward]
Severance Charges	19
Payments	20
Severance [Member]
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Period Start	2
Restructuring Reserve, Period End	20
Severance [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Period Start	53
Restructuring Reserve, Period End	33
Other Severance Charges [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	6	2
Exelon Generation Co L L C [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	2	1
Restructuring Reserve [Roll Forward]
Severance Charges	2
Payments	3
Plant Retirement Cost [Abstract]
Inventory write down related to plant retirements	3
Exelon Generation Co L L C [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Severance Charges	19
Non-Merger Severance Costs	6
Payments	2
Exelon Generation Co L L C [Member] \| Severance [Member]
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Period Start	2
Restructuring Reserve, Period End	20
Exelon Generation Co L L C [Member] \| Severance [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Period Start	10
Restructuring Reserve, Period End	8
Exelon Generation Co L L C [Member] \| Other Severance Charges [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	4	1
Commonwealth Edison Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	0	0
Plant Retirement Cost [Abstract]
Inventory write down related to plant retirements	1
Commonwealth Edison Co [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Payments	0
Commonwealth Edison Co [Member] \| Severance [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Period Start	0
Restructuring Reserve, Period End	0
Commonwealth Edison Co [Member] \| Other Severance Charges [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded		1
PECO Energy Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	0	0
Baltimore Gas and Electric Company [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	0	$ 0
Baltimore Gas and Electric Company [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Payments	3
Baltimore Gas and Electric Company [Member] \| Severance [Member] \| CENGMember [Member]
Restructuring Reserve [Roll Forward]
Restructuring Reserve, Period Start	6
Restructuring Reserve, Period End	$ 3

Preferred Securities (Details) $ in Millions	Dec. 31, 2013 USD ($)
PECO Energy Co [Member]
Temporary Equity [Line Items]
Dollar amount	$ 0

Stock-Based Compensation Plans (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2013

Common Stock [Abstract]

2,000,000,000

Common Stock without par - Outstanding

893,940,600

857,000,000

Total stock-based compensation included in operating and maintenance expense

$ 68

$ 70

Other stock-based awards

$ 1

Income Tax Benefit

(10)

(8)

(37)

(34)

Total after-tax stock based compensation expense

Share Based Compensation Pre Tax Expense [Line Items]

Share Based Compensation Pre Tax Expense [Line Items]

Share Based Compensation Pre Tax Expense [Line Items]

Share Based Compensation Pre Tax Expense [Line Items]

Share Based Compensation Pre Tax Expense [Line Items]

Business Services Company [Member]

^[1]

Share Based Compensation Pre Tax Expense [Line Items]

Accumulated Other Comprehensive Income Loss [Line Items]

^[2]

$ 12

$ 7

$ 43

$ 39

[1]

BGE's stock-based compensation expense (pre-tax) for the six months ended June 30, 2013 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon's merger with Constellation on March 12, 2012. This amount is not included in Exelon's stock-based compensation expense for the six months ended June 30, 2013 shown in the tables titled Components of Stock-Based Compensation Expense and Subsidiaries above.

[2]

These amounts primarily represent amounts billed to Exelon's subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.

Earnings Per Share and Equity (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013
Earnings Per Share And Equity Additional Narrative Information [Abstract]
Stock options not included in the calculation of diluted common shares outstanding	16	17	16	18
Treasury Stock, Shares held	35		35		35
Treasury stock, at cost	$ 2,327		$ 2,327		$ 2,327
Earnings Per Share Diluted
Net income on common stock	$ 522	$ 490	$ 612	$ 486
Average common shares outstanding - basic	860	856	860	856
Assumed exercise of stock options, performance share awards and restricted stock	4	4	3	3
Average common shares outstanding - diluted	864	860	863	859
Preferred Stock [Member] \| Cumulative Preferred Stock [Member]
Preferred Stock [Line Items]
PECO Cumulative Preferred Securities Redeemable
Retained Earnings \| Cumulative Preferred Stock [Member]
Preferred Stock [Line Items]
Preferred stock redemption premium

Changes in Accumulated Other Comprehensive Income (Changes in accumulated other comprehensive income by component)(Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Mar. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

$ (2,040)

^[1]

246

^[1],[2]

(112)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

$ 131

$ 0

$ 94

^[1]

(1,906)

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Actuarial loss reclassified to periodic cost, taxes

(23)

(32)

(46)

(66)

Transition obligation

(1)

Pension and non-pension postretirement benefit plan valuation adjustment, taxes

(166)

(159)

(50)

Change in unrealized gain (loss) on cash flow hedges, taxes

Change in unrealized gain (loss) on equity investments taxes

(5)

(23)

Deferred Compensation Unit Valuation Adjustment tax

(6)

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member]

(79)

(82)

(67)

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

$ 368

120

^[1]

368

(11)

^[1]

(62)

^[1],[2]

(147)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(73)

^[1]

(123)

^[1]

245

^[1]

245

Accumulated Net Unrealized Investment Gain Loss [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

^[1]

(1)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

^[1]

(1)

^[1]

(1)

^[1]

(1)

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Accumulated Defined Benefit Plans Adjustment [Member]

(1)

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

(3,137)

(2,260)

^[1]

(3,137)

246

^[1]

^[1],[2]

101

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

312

^[1]

188

(1,948)

^[1]

(2,949)

(1,948)

^[1]

(2,949)

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Accumulated Translation Adjustment [Member]

(1)

^[2]

^[1]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

(10)

(1)

^[1]

(6)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(1)

^[1]

(6)

(11)

^[1]

(6)

(11)

^[1]

(6)

Accumulated Equity Investment [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

108

^[1]

^[1]

(116)

^[1],[2]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(105)

^[1]

^[1]

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Change in unrealized gain (loss) on equity investments taxes

(5)

193

Accumulated Other Comprehensive (Loss) Income, Net

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

(2,767)

135

(41)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

250

(2,673)

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

159

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

214

^[1]

^[1],[2]

(178)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(155)

(134)

(238)

^[1]

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Change in unrealized gain (loss) on cash flow hedges, taxes

175

Change in unrealized gain (loss) on marketable securities, taxes

(2)

Change in unrealized gain (loss) on equity investments taxes

(5)

(23)

Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member]

102

112

152

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

512

114

^[1]

512

(8)

^[1]

(62)

^[1],[2]

(279)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(70)

^[1]

(267)

^[1]

245

^[1]

245

Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain Loss [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

(1)

^[1]

(1)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

^[1]

(1)

^[1]

(1)

^[1]

(1)

Exelon Generation Co L L C [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]

(6)

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

(10)

^[1]

(1)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

^[1]

(1)

(11)

^[1]

(6)

(11)

^[1]

(6)

Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

108

^[1]

^[1]

(116)

^[1],[2]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(105)

^[1]

^[1]

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Change in unrealized gain (loss) on equity investments taxes

(5)

Exelon Generation Co L L C [Member] | Accumulated Other Comprehensive (Loss) Income, Net

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

513

(274)

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

(61)

(238)

275

OtherComprehensiveIncomeLossTaxParentheticalDisclosuresAbstract

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

^[1]

PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain Loss [Member]

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

^[1]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

$ 1

^[1]

$ 1

^[1]

PECO Energy Co [Member] | Accumulated Other Comprehensive (Loss) Income, Net

Accumulated Other Comprehensive Income Loss [Line Items]

Accumulated Other Comprehensive Income (Loss), Net of Tax, Beginning Balance

$ 1

Accumulated Other Comprehensive Income (Loss), Net of Tax, Ending Balance

$ 1

[1]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[2]	(b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 13 for additional details).

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

3 Months Ended

6 Months Ended

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

$ 6,024

$ 6,141

$ 13,261

^[1]

$ 12,223

^[1]

228

246

445

863

(269)

(117)

(721)

834

736

875

792

277

239

224

294

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

557

497

498

Transition obligation

(1)

Reclassification out of Accumulated Other Comprehensive Income [Member]

(21)

(20)

(30)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

$ 35

123

^[2]

112

^[2]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[3]

(8)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

240

(1)

239

141

^[2]

102

^[2]

(92)

(52)

(25)

^[2]

(40)

^[2]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]

147

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

141

^[2]

102

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Derivative [Member]

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Accumulated Net Unrealized Investment Gain Loss [Member]

^[2]

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

Accumulated Defined Benefit Plans Adjustment [Member]

(1)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(83)

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

(51)

Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

(1)

^[3]

^[4]

Actuarial gains/losses

^[3]

(165)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(166)

(49)

^[2]

(107)

^[2]

^[2]

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

(101)

(31)

^[2]

(66)

^[2]

Deferred compensation unit

(82)

^[2]

Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Plans Defined Benefit [Member]

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

Actuarial gains/losses

^[2]

(61)

(117)

Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(8)

193

^[2]

(77)

^[2]

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

(5)

(3)

116

^[2]

(5)

^[2]

193

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

3,789

4,070

8,179

7,603

147

142

142

(126)

146

(81)

571

477

187

458

199

149

(1)

148

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

372

328

188

310

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

(1)

(21)

(20)

(30)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

274

141

154

^[2]

178

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

459

460

237

^[2]

102

^[2]

(181)

(93)

(25)

^[2]

(40)

^[2]

Exelon Generation Co L L C [Member] | Accumulated Net Gain Loss From Designated Or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]

279

144

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

236

^[2]

102

^[2]

Exelon Generation Co L L C [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

Exelon Generation Co L L C [Member] | Equity Method Investments

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

Exelon Generation Co L L C [Member] | Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[3]

(8)

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

(8)

193

^[2]

(77)

^[2]

Other Comprehensive Income Loss Reclassification Adjustment From AOCI Pension And Other Postretirement Benefit PlansTax [Abstract]

(5)

(3)

116

^[2]

$ (5)

193

^[2]

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

1,128

1,080

2,262

2,239

153

422

(75)

(70)

(150)

(418)

183

162

346

137

111

209

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

656

672

1,649

1,567

(27)

(28)

(53)

(54)

107

110

230

287

173

200

Reclassification Adjustment Out Of Accumulated Other Comprehensive Income [Line Items]

653

1,707

1,533

(22)

(28)

(46)

(57)

178

176

$ 19

$ 25

$ 106

[1]	For the six months ended June 30, 2014 and 2013, utility taxes of $45 million and $39 million, respectively, are included in revenues and expenses for Generation. For the six months ended June 30, 2014 and 2013, utility taxes of $119 million and $117 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2014 and 2013, utility taxes of $65 million and $64 million, respectively, are included in revenues and expenses for PECO. For the six months ended June 30, 2014 and 2013, utility taxes of $43 million and $41 million, respectively, are included in revenues and expenses for BGE.
[2]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in net income.
[3]	(b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 13 for additional details).
[4]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Commitments and Contingencies (Details)

1 Months Ended

6 Months Ended

12 Months Ended

Apr. 12, 2012

Defendants

Feb. 28, 2012

Defendants

Jul. 11, 2011

Customers

Jan. 31, 2005

USD ($)

Jan. 31, 2013

USD ($)

Oct. 31, 2007

USD ($)

Jun. 30, 2014

USD ($)

Reactors

OpenClaims

Customers

MGPSites

Claiments

PrincipleResponsibleParties

States

Dec. 31, 2013

USD ($)

May 15, 2014

Jun. 30, 2013

USD ($)

Jun. 30, 2012

USD ($)

Commercial Commitments Footnote [Abstract]

$ 9,839,000,000

UnderwritingDiscount

60,000,000

Business Acquisition Potential Cash Payment

40,000,000

Environmental Issues - Water [Abstract]

Low end of range of cooling tower cost

430,000,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Net investment in long-term direct financing leases

$ 353,000,000

$ 698,000,000

Climate Change Regulation [Abstract]

Minimum GHG emissions by stationary sources to qualify for regulation | T

100,000

Minimum additional GHG emissions by stationary sources after a modification | T

75,000

Effective Number Of Years For Tailoring Rule

6 years

Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract]

Percentage of ownership interest in CENG (as a percent)

67.00%

Cotter Corporation [Member]

Environmental Issues - Solid and Hazardous Waste [Abstract]

Loss Contingency Number Of Defendants | Defendants

Other Purchase Obligations [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

$ 140,000,000

171,000,000

65,000,000

55,000,000

37,000,000

100,000,000

Financial Standby Letter of Credit [Member]

568,000,000

^[1]

1,514,000,000

Sithe Guarantee [Member]

Nuclear Insurance Premiums [Member]

200,000,000

Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

^[2]

3,559,000,000

Commercial Commitments Footnote [Abstract]

^[3]

4,706,000,000

Estimated net exposure for commercial transaction obligations

600,000,000

Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

Accrual For MGP Investigation And Remediation [Member]

323,000,000

338,000,000

Accrual For Environmental Loss Contingencies [Line Items]

258,000,000

273,000,000

Required nuclear liability insurance per site

6,375,000,000

Nuclear Insurance [Abstract]

$ 375,000,000

Total of U.S. licensed nuclear reactors | Reactors

104

Nuclear financial protection pool value

$ 13,200,000,000

Maximum liability per nuclear incident

$ 3,600,000,000

Spent Nuclear Fuel Obligation [Abstract]

Cost of spent nuclear fuel disposal per kWh of net nuclear generation

0.001

NetNuclearFuelDisposalFees

49,000,000

136,000,000

Environmental Issues - Water [Abstract]

Low end of range of cooling tower cost

430,000,000

Consent decree penalty

$ 1,000,000

Environmental loss contingencies

$ 15,000,000

14,000,000

Environmental Issues - Air [Abstract]

States subject to the Cross State Air Pollution Rule | States

Emissions allowance balance

$ 64,000,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Probable contingency (liability)

21,000,000

Payments for operating leases

$ 10,000,000

Asbestos Loss Contingency [Abstract]

Asbestos liability reserve

104,000,000

90,000,000

Asbestos liability reserve related to open claims

$ 21,000,000

Open asbestos liability claims | OpenClaims

247

Asbestos liability reserve related to anticipated claims

$ 83,000,000

Increase (decrease) in the value of the asbestos liability reserve

15,000,000

25,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

264,000,000

529,000,000

393,000,000

269,000,000

113,000,000

424,000,000

Unrecorded Unconditional Purchase Obligation, Additional Information [Abstract]

$ 1,992,000,000

Percentage of ownership interest in CENG (as a percent)

50.01%

Operating Leases Future Minimum Payments Due Table [Abstract]

Minimum future operating lease payments due in three years

$ 9,000,000

Minimum future operating lease payments due in four years

12,000,000

Minimum future operating lease payments due in five years

12,000,000

Minimum future operating lease payments due beyond five years

270,000,000

Exelon Generation Co L L C [Member] | Maximum [Member]

Business Acquisition, Development Of New Generation Cost

$ 120,000,000

$ 650,000,000

Business Acquisition, Expected New Generation Mwh | MW

300

Exelon Generation Co L L C [Member] | Minimum [Member]

Business Acquisition, Development Of New Generation Cost

$ 95,000,000

$ 600,000,000

Business Acquisition, Expected New Generation Mwh | MW

285

Exelon Generation Co L L C [Member] | Cotter Corporation [Member]

Environmental Issues - Solid and Hazardous Waste [Abstract]

DOJ potential settlement

$ 90,000,000

Total cost of remediation to be shared by PRPs

42,000,000

Exelon Generation Co L L C [Member] | Rossville ash site [Member]

Environmental Issues - Solid and Hazardous Waste [Abstract]

Loss Contingency Esitmate to close site

6,000,000

Exelon Generation Co L L C [Member] | Net Capacity Purchases [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

^[4]

208,000,000

^[4]

353,000,000

^[4]

269,000,000

^[4]

208,000,000

^[4]

98,000,000

^[4]

388,000,000

Exelon Generation Co L L C [Member] | Power Purchases [Member]

^[4]

1,524,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[5]

43,000,000

^[5]

163,000,000

^[5]

122,000,000

^[5]

59,000,000

^[5]

13,000,000

^[5]

4,000,000

Exelon Generation Co L L C [Member] | Transmission Rights Purchases [Member]

^[5]

404,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[6]

13,000,000

^[6]

13,000,000

^[6]

2,000,000

^[6]

2,000,000

^[6]

2,000,000

^[6]

32,000,000

Exelon Generation Co L L C [Member] | Public Utilities, Inventory, Fuel [Member]

^[6]

64,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

694,000,000

1,526,000,000

1,230,000,000

1,276,000,000

929,000,000

4,318,000,000

Exelon Generation Co L L C [Member] | Other Purchase Obligations [Member]

9,973,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

110,000,000

155,000,000

52,000,000

47,000,000

31,000,000

79,000,000

Exelon Generation Co L L C [Member] | Perryman Construction [Member]

474,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

Exelon Generation Co L L C [Member] | Beebe Construction [Member]

84,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

Exelon Generation Co L L C [Member] | FourmileConstructionMember [Member]

53,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]

38,000,000

Exelon Generation Co L L C [Member] | Sithe Guarantee [Member]

^[1]

1,470,000,000

Acquisition of interest in subsidiary

50.00%

Sale of interest in subsidiary

100.00%

Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]

Nuclear insurance liability limit per incident

^[2]

3,559,000,000

Nuclear Insurance [Abstract]

13,600,000,000

Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident

127,300,000,000

Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident

19,000,000

Maximum liability per nuclear incident

2,700,000,000

Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

Commercial Commitments Footnote [Abstract]

^[7]

1,346,000,000

Estimated net exposure for commercial transaction obligations

300,000,000

Exelon Generation Co L L C [Member] | Total Accrual For Environmental Loss Contingencies [Member]

Accrual For Environmental Loss Contingencies [Line Items]

56,000,000

225,000,000

LossContingencySettlementAbstract

Environmental Issues - MGP Site Contingency [Abstract]

$ 2,606,000,000

2,469,000,000

Total number of MGP sites | MGPSites

Approved clean-up | MGPSites

Sites under study/remediation | MGPSites

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Coal Rail Car Lease Proof of Claims

$ 21,000,000

Continuous Power Interruption [Abstract]

Minimum number of customers ComEd can be held liable to for power interruption | Customers

30,000

Number of customers affected by a major storm | Customers

900,000

Number of customers proposed by the ICC that ComEd should not be granted a waiver under Continuous Power Interruption | Customers

34,559

Telephone Consumer Protection Act Lawsuit [Abstract]

PossibleDefendantsNumber | Claiments

1,200,000

Commonwealth Edison Co [Member] | Maximum [Member]

Telephone Consumer Protection Act Lawsuit [Abstract]

LossContingencyDamagesSought

$ 1,500

Commonwealth Edison Co [Member] | Minimum [Member]

Telephone Consumer Protection Act Lawsuit [Abstract]

LossContingencyDamagesSought

500

Commonwealth Edison Co [Member] | Renewable Energy Including Renewable Energy Credits [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

32,000,000

73,000,000

76,000,000

77,000,000

78,000,000

1,212,000,000

Commonwealth Edison Co [Member] | Other Purchase Obligations [Member]

1,548,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

16,000,000

8,000,000

5,000,000

5,000,000

5,000,000

14,000,000

Commonwealth Edison Co [Member] | Energy Supply Procurement [Member]

53,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

217,000,000

232,000,000

151,000,000

140,000,000

Commonwealth Edison Co [Member] | Financial Standby Letter of Credit [Member]

740,000,000

Commonwealth Edison Co [Member] | Trust Preferred Securities [Member]

^[1]

19,000,000

Commonwealth Edison Co [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

200,000,000

Commonwealth Edison Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]

^[8]

206,000,000

Accrual For Environmental Loss Contingencies [Line Items]

Commonwealth Edison Co [Member] | Accrual For MGP Investigation And Remediation [Member]

222,000,000

234,000,000

Accrual For Environmental Loss Contingencies [Line Items]

217,000,000

229,000,000

203,000,000

LossContingencySettlementAbstract

Environmental Issues - MGP Site Contingency [Abstract]

$ 490,000,000

447,000,000

Total number of MGP sites | MGPSites

Approved clean-up | MGPSites

Sites under study/remediation | MGPSites

PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

^[9]

$ 381,000,000

^[9]

169,000,000

PECO Energy Co [Member] | Alternative Energy Credits [Member]

^[9]

550,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[10]

1,000,000

^[10]

2,000,000

^[10]

2,000,000

^[10]

2,000,000

^[10]

2,000,000

^[10]

4,000,000

PECO Energy Co [Member] | Public Utilities, Inventory, Fuel [Member]

^[10]

13,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

90,000,000

112,000,000

93,000,000

35,000,000

15,000,000

66,000,000

PECO Energy Co [Member] | Other Purchase Obligations [Member]

411,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

12,000,000

4,000,000

3,000,000

1,000,000

1,000,000

7,000,000

PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]

28,000,000

PECO Energy Co [Member] | Trust Preferred Securities [Member]

^[1]

22,000,000

PECO Energy Co [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

178,000,000

PECO Energy Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]

^[11]

181,000,000

Accrual For Environmental Loss Contingencies [Line Items]

PECO Energy Co [Member] | Accrual For MGP Investigation And Remediation [Member]

44,000,000

47,000,000

Accrual For Environmental Loss Contingencies [Line Items]

41,000,000

44,000,000

Business Acquisition, Direct Investment With State And Local Governments Due To Settlement

260,000,000

$ 1,000,000,000

Accrual For Environmental Loss Contingencies [Line Items]

Environmental Issues - MGP Site Contingency [Abstract]

$ 1,000,000

Total number of MGP sites | MGPSites

Sites under study/remediation | MGPSites

Environmental Issues - Solid and Hazardous Waste [Abstract]

Total cost of remediation to be shared by PRPs

$ 1,700,000

68th Street and Sauer Dumps [Abstract]

Maximum estimated clean-up costs for all potentially responsible parties

$ 1,700,000

Asbestos Loss Contingency [Abstract]

Number of claimants | Claiments

486

Unrecorded Unconditional Purchase Obligation [Abstract]

Baltimore Gas and Electric Company [Member] | Sixty-Eighth Street Dump [Member]

$ 2,000,000

Environmental Issues - Solid and Hazardous Waste [Abstract]

Loss Contingency Number Of Parties Jointly And Severally Liable In Environmental Protection Agency Action

68th Street and Sauer Dumps [Abstract]

Number of defendants in addition to BGE and Constellation Energy | PrincipleResponsibleParties

Minimum estimated clean-up costs for all potentially responsible parties

$ 50,000,000

Maximum estimated clean-up costs for all potentially responsible parties

64,000,000

Baltimore Gas and Electric Company [Member] | Curtailment Services [Member]

Unrecorded Unconditional Purchase Obligation [Abstract]

^[12]

21,000,000

^[12]

40,000,000

^[12]

34,000,000

^[12]

29,000,000

^[12]

12,000,000

Baltimore Gas and Electric Company [Member] | Public Utilities, Inventory, Fuel [Member]

^[12]

136,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

64,000,000

83,000,000

82,000,000

65,000,000

53,000,000

271,000,000

Baltimore Gas and Electric Company [Member] | Other Purchase Obligations [Member]

618,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

1,000,000

4,000,000

5,000,000

Baltimore Gas and Electric Company [Member] | Energy Supply Procurement [Member]

12,000,000

Unrecorded Unconditional Purchase Obligation [Abstract]

^[13]

448,000,000

^[13]

632,000,000

^[13]

240,000,000

Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]

^[13]

1,320,000,000

Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member]

^[1]

1,000,000

Baltimore Gas and Electric Company [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

250,000,000

Baltimore Gas and Electric Company [Member] | Total Accrual For Environmental Loss Contingencies [Member]

^[14]

259,000,000

Accrual For Environmental Loss Contingencies [Line Items]

Midwest Generation, LLC [Member]

$ 1,000,000

Environmental Issues - Water [Abstract]

Environmental loss contingencies

9,000,000

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Midwest Generation's estimated environmental investigation and remediation costs

53,000,000

Asbestos Loss Contingency [Abstract]

Increase (decrease) in the value of the asbestos liability reserve

$ 6,000,000

[1]	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
[2]	Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
[3]	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.6 billion at June 30, 2014, which represents the total amount Exelon could be required to fund based on June 30, 2014 market prices.
[4]	Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation's expected payments under these arrangements at June 30, 2014, net of fixed capacity payments expected to be received by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts.
[5]	The table excludes renewable energy purchases that are contingent in nature.
[6]	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
[7]	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $0.3 billion at June 30, 2014, which represents the total amount Generation could be required to fund based on June 30, 2014 market prices.
[8]	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.
[9]	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2016. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 - Regulatory Matters for additional information.
[10]	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 5 - Regulatory Matters for additional information.
[11]	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
[12]	BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - Regulatory Matters for additional information
[13]	BGE has entered into various contracts with curtailment services providers related to transactions in PJM's capacity market. See Note 5 - Regulatory Matters for additional information.
[14]	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

Supplemental Financial Information -Operations (Detail) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Taxes Excluding Income And Excise Taxes [Abstract]

$ 6,024

$ 6,141

$ 13,261

^[1]

$ 12,223

^[1]

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

288

271

580

548

(21)

(20)

(30)

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[2]

111

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[2]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

172

(102)

234

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

128

(40)

141

Net unrealized income (losses) on pledged assets

Regulatory offset to decommissioning trust fund-related activities

(204)

^[3]

(299)

^[3]

(148)

^[4]

Total decommissioning-related activities

212

(37)

270

Long-term lease income

Interest income related to uncertain income tax positions

(2)

(1)

Credit facility termination fees

243

(17)

348

155

Taxes Excluding Income And Excise Taxes [Abstract]

3,789

4,070

8,179

7,603

Equity Method Investment Summarized Financial Information Gross Profit Loss [Abstract]

118

101

223

194

(1)

(21)

(20)

(30)

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[2]

111

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[2]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

172

(102)

234

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

128

(40)

141

Net unrealized income (losses) on pledged assets

Regulatory offset to decommissioning trust fund-related activities

(204)

^[3]

(299)

^[3]

(148)

^[4]

Total decommissioning-related activities

(1)

212

(37)

270

Interest income related to uncertain income tax positions

(2)

Credit facility termination fees

228

(33)

318

Taxes Excluding Income And Excise Taxes [Abstract]

1,128

1,080

2,262

2,239

149

145

Interest income related to uncertain income tax positions

AFUDC - equity

Other Income

Taxes Excluding Income And Excise Taxes [Abstract]

656

672

1,649

1,567

Interest income related to uncertain income tax positions

(1)

AFUDC - equity

Other Income

Taxes Excluding Income And Excise Taxes [Abstract]

653

1,707

1,533

113

109

Interest income related to uncertain income tax positions

^[5]

AFUDC - equity

Other Income

(1)

Depreciation, Amortization and Accretion [Abstract]

$ 5

$ 4

$ 9

[1]	For the six months ended June 30, 2014 and 2013, utility taxes of $45 million and $39 million, respectively, are included in revenues and expenses for Generation. For the six months ended June 30, 2014 and 2013, utility taxes of $119 million and $117 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2014 and 2013, utility taxes of $65 million and $64 million, respectively, are included in revenues and expenses for PECO. For the six months ended June 30, 2014 and 2013, utility taxes of $43 million and $41 million, respectively, are included in revenues and expenses for BGE.
[2]	Includes investment income and realized gains and losses on sales of investments of the trust funds.
[3]	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 – Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
[4]	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 of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
[5]	Relates to the cash return on BGE’s rate stabilization deferral. See Note 5 - Regulatory Matters for additional information regarding the rate stabilization deferral.

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

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

$ 1,015

$ 942

117

112

Amortization of energy contract assets and liabilities

^[1]

113

306

Nuclear fuel

^[1]

499

454

Asset retirement obligation accretion

^[2]

159

136

1,925

1,972

Pension and non-pension postretirement benefits costs

315

409

Provision for Obsolete Inventory

Other Decommissioning Related Activity

^[3]

(85)

(62)

Energy-related options

^[4]

Amortization of regulatory asset related to debt costs

Amortization of debt fair value adjustment

(26)

(22)

Discrete impacts from EIMA

(126)

^[5]

Merger related commitments

(6)

Gain (loss) on equity method investments

$ 0

$ 21

Impairment in investment of direct financing leases

Impairment Of Long Lived Asets Held For Use

(26)

(17)

Changes In Other Assets and Liabilities [Abstract]

567

576

(24)

(3)

(157)

(123)

(158)

277

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

(280)

133

Debt exchange

131

Consolidated VIE dividend to non-controlling interest

(415)

Non Cash Fair Value Adjust for CENG

3,400

Non Cash Debt Instrument Issued

Total noncash investing and financing activities

(3,569)

DOE Smart Grid Investment Grant [Abstract]

Amount included in capital expenditures

Smart Grid Grant Reimbursements

Depreciation, Amortization and Accretion [Abstract]

444

402

Amortization of energy contract assets and liabilities

^[1]

118

344

Nuclear fuel

^[1]

499

454

Asset retirement obligation accretion

^[2]

159

136

1,242

1,358

Pension and non-pension postretirement benefits costs

139

173

Provision for Obsolete Inventory

Other Decommissioning Related Activity

^[3]

(85)

(62)

Energy-related options

^[4]

Amortization of debt fair value adjustment

(12)

(22)

Merger related commitments

Gain (loss) on equity method investments

$ 1

$ 21

Impairment Of Long Lived Asets Held For Use

(19)

(7)

Changes In Other Assets and Liabilities [Abstract]

209

315

(134)

(69)

(34)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

(56)

(168)

Consolidated VIE dividend to non-controlling interest

(415)

Non Cash Fair Value Adjust for CENG

3,400

Non Cash Debt Instrument Issued

Total noncash investing and financing activities

(3,438)

Depreciation, Amortization and Accretion [Abstract]

290

275

347

337

Pension and non-pension postretirement benefits costs

154

Provision for Obsolete Inventory

(8)

Amortization of regulatory asset related to debt costs

Discrete impacts from EIMA

(126)

^[5]

(3)

Changes In Other Assets and Liabilities [Abstract]

(61)

(5)

304

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

217

Allocation Of Tax Benefit From Parent

Indemnification of like-kind exchange position

(112)

Total noncash investing and financing activities

(2)

174

Commonwealth Edison Co [Member] | Indemnification Agreement [Member]

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Indemnification of like-kind exchange position

(174)

Depreciation, Amortization and Accretion [Abstract]

112

109

117

113

Pension and non-pension postretirement benefits costs

Amortization of regulatory asset related to debt costs

(1)

Changes In Other Assets and Liabilities [Abstract]

(6)

(89)

(62)

(6)

(1)

DOE Smart Grid Investment Grant [Abstract]

(114)

(49)

Amount included in capital expenditures

Smart Grid Grant Reimbursements

Depreciation, Amortization and Accretion [Abstract]

142

128

197

175

Pension and non-pension postretirement benefits costs

Amortization of regulatory asset related to debt costs

Merger related commitments

(6)

(8)

(3)

Changes In Other Assets and Liabilities [Abstract]

(2)

Cash Flow Noncash Investing And Financing Activities Disclosure [Abstract]

Indemnification of like-kind exchange position

$ 0

DOE Smart Grid Investment Grant [Abstract]

Amount included in capital expenditures

Smart Grid Grant Reimbursements

$ 34

[1]	Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income
[2]	Included in operating and maintenance expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income
[3]	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 of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
[4]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[5]	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 tariff. See Note 5 – Regulatory Matters for more information.

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

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2014

Mar. 31, 2014

Jun. 30, 2013

Mar. 31, 2013

Jun. 30, 2014

Jun. 30, 2013

Dec. 31, 2010

Dec. 31, 2013

Sep. 30, 2000

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Supplemental Financial Information Textuals [Abstract]

$ 0

$ 1,925

Payment to IRS

$ 302

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Estimated residual value of leased assets

685

1,465

$ 1,600

Less: unearned income

(332)

(767)

Net investment in long-term leases

353

698

ImpairedAssetsFairValue

Tangible Asset Impairment Charges

CapitalLeaseNetInvestmentInDirectFinancingLeasesPrepaymentsReceived

1,200

Utilities Operating Expense Maintenance And Operations [Abstract]

Utilities Operating Expense, Impairments

$ 92

$ 21

Cash Proceeds from Direct Finance Lease Contract Termination

2,166

$ 1

1,892

4,024

$ 3,656

Interest Costs Incurred [Abstract]

Interest Costs Incurred

335

Capital Leases Written Off

336

Taxes accrued

285

1,382

1,633

14,369

^[1]

14,369

^[1]

13,713

^[2]

2,411

2,371

Accumulated Other Comprehensive Income (Loss) [Abstract]

293

272

CPS Board San Antonio, Texas | EquipmentLeasedToOtherPartyMember

^[3]

(1,906)

(2,040)

Interest Costs Incurred [Abstract]

Cash Proceeds from Direct Finance Lease Contract Termination

335

Investments In Affiliates Subsidiaries Associates And Joint Ventures [Abstract]

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

1,925

ImpairedAssetsFairValue

Tangible Asset Impairment Charges

Utilities Operating Expense Maintenance And Operations [Abstract]

Utilities Operating Expense, Impairments

$ 21

1,255

1,041

2,194

2,007

Interest Costs Incurred [Abstract]

Interest Costs Incurred

819

976

7,397

^[1]

7,397

^[1]

7,034

^[2]

2,411

2,371

Accumulated Other Comprehensive Income (Loss) [Abstract]

^[3]

214

Utilities Operating Expense Maintenance And Operations [Abstract]

316

319

603

611

274

307

3,325

3,184

Accumulated Other Comprehensive Income (Loss) [Abstract]

Utilities Operating Expense Maintenance And Operations [Abstract]

160

155

416

319

167

106

2,969

2,935

Installment plan receivables

124

107

Installment plan receivables uncollectible accounts reserve

(20)

(18)

Accumulated Other Comprehensive Income (Loss) [Abstract]

PECO Energy Co [Member] | Low To Medium Risk [Member]

^[3]

Installment plan receivables uncollectible accounts reserve

(1)

PECO Energy Co [Member] | Medium Risk [Member]

Installment plan receivables uncollectible accounts reserve

(4)

PECO Energy Co [Member] | High Risk [Member]

Installment plan receivables uncollectible accounts reserve

(15)

(13)

Utilities Operating Expense Maintenance And Operations [Abstract]

163

$ 139

326

$ 266

111

2,781

2,702

$ 42

$ 46

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,411 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.
[3]	(a) All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Segment Information (Details)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

USD ($)

Sep. 30, 2013

USD ($)

Jun. 30, 2013

USD ($)

Jun. 30, 2014

USD ($)

ReportableSegments

Jun. 30, 2013

USD ($)

Dec. 31, 2013

USD ($)

$ 6,024

$ 6,141

$ 13,261

^[1]

$ 12,223

^[1]

277

239

224

294

557

497

498

Segment Reporting Additional Information [Abstract]

83,656

$ 83,656

$ 79,924

Number of reportable segments | ReportableSegments

Intersegment Eliminations [Member]

$ (751)

Operating Segments [Member]

^[1]

(1,155)

(1,334)

^[2]

$ 441

Segment Reporting Additional Information [Abstract]

Number of reportable segments | ReportableSegments

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

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

^[3],[4]

$ 517

710

3,789

4,070

8,179

^[1],[3]

7,603

^[1],[3]

201

329

372

328

188

^[3]

310

^[3]

Segment Reporting Additional Information [Abstract]

44,422

41,232

Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Operating Segments [Member]

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

207

212

Segment Reporting Additional Information [Abstract]

121

173

266

Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member] | Operating Segments [Member]

(10)

(7)

Generation Mid Atlantic [Member]

137

238

Revenue net of purchased power and fuel expense, Total

1,277

1,229

2,695

2,552

920

768

1,615

1,612

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(18)

(2)

(75)

(10)

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

Revenue net of purchased power and fuel expense from external customers

1,272

^[5]

1,220

^[5]

2,713

^[2]

2,551

^[2]

906

^[6]

770

^[6]

1,690

^[7]

1,622

^[7]

Generation Mid Atlantic [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Operating Segments [Member]

Generation Midwest [Member]

Revenue net of purchased power and fuel expense, Total

981

1,071

2,251

2,259

605

684

1,161

1,401

Generation Midwest [Member] | Intersegment Eliminations [Member]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(5)

(3)

Generation Midwest [Member] | Operating Segments [Member]

Revenue net of purchased power and fuel expense from external customers

981

^[5]

1,076

^[5]

2,239

^[2]

2,257

^[2]

604

^[6]

687

^[6]

1,134

^[7]

1,397

^[7]

Generation New England [Member]

Revenue net of purchased power and fuel expense, Total

212

189

761

592

200

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(20)

(8)

(24)

(35)

(42)

(23)

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

Revenue net of purchased power and fuel expense from external customers

211

^[5]

209

^[5]

756

^[2]

600

^[2]

^[6]

242

^[7]

103

^[7]

Generation New York [Member]

Revenue net of purchased power and fuel expense, Total

194

174

381

343

148

127

(8)

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(1)

(3)

(7)

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

Revenue net of purchased power and fuel expense from external customers

194

^[5]

175

^[5]

384

^[2]

350

^[2]

142

^[6]

113

^[7]

(16)

^[7]

Generation ERCOT [Member]

Revenue net of purchased power and fuel expense, Total

197

315

440

608

112

142

213

Generation ERCOT [Member] | Intersegment Eliminations [Member]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(1)

(4)

(1)

(4)

(58)

(130)

(42)

Generation ERCOT [Member] | Operating Segments [Member]

Revenue net of purchased power and fuel expense from external customers

198

^[5]

319

^[5]

612

^[2]

117

^[6]

143

^[6]

272

^[7]

255

^[7]

Generation Other Regions [Member]

Revenue net of purchased power and fuel expense, Total

308

^[8]

240

^[8]

649

^[9]

465

^[9]

^[10]

180

^[11]

105

^[11]

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(6)

^[8]

(6)

^[8]

^[9]

(82)

^[10]

(52)

^[10]

(127)

^[11]

(17)

^[11]

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

Revenue net of purchased power and fuel expense from external customers

314

^[5],[8]

246

^[5],[8]

648

^[2],[9]

429

^[2],[9]

157

^[6],[10]

111

^[6],[10]

307

^[7],[11]

122

^[7],[11]

Generation Reportable Segments Total [Member]

Revenue net of purchased power and fuel expense, Total

3,169

3,218

7,177

6,819

1,871

1,687

3,425

3,403

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(1)

(27)

(4)

(143)

(109)

(333)

(80)

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

Revenue net of purchased power and fuel expense from external customers

3,170

^[5]

3,245

^[5]

7,181

^[2]

6,799

^[2]

2,014

^[6]

1,796

^[6]

3,758

^[7]

3,483

^[7]

Generation Total Consolidated Group [Member]

Revenue net of purchased power and fuel expense from external customers

3,789

4,070

8,179

7,603

^[6]

1,954

2,124

Revenue net of purchased power and fuel expense, Total

1,954

2,124

2,988

3,489

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

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

Revenue net of purchased power and fuel expense from external customers

3,789

^[5]

4,070

^[5]

8,179

^[2]

7,603

^[2]

^[7]

2,988

3,489

Generation All Other Segments [Member]

Revenue net of purchased power and fuel expense, Total

620

^[12]

852

^[12]

1,002

^[13]

784

^[13]

437

^[14]

(437)

^[15]

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

Revenue net of purchased power and fuel expense from external customers

619

^[5],[12]

825

^[5],[12]

998

^[2],[13]

804

^[2],[13]

(60)

^[6],[14]

328

^[6],[14]

(770)

^[7],[15]

Segment Reporting Additional Information [Abstract]

Amortization of intangible assets related to commodity contracts

125

404

Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel

257

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

^[12]

(20)

^[13]

143

^[14]

109

^[14]

333

^[15]

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

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

^[4]

1,128

1,080

2,262

^[1]

2,239

^[1]

111

209

Segment Reporting Additional Information [Abstract]

24,544

24,118

119

117

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

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

^[4]

656

672

1,649

^[1]

1,567

^[1]

173

200

Segment Reporting Additional Information [Abstract]

9,761

9,617

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

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

^[4]

653

1,707

^[1]

1,533

^[1]

106

Segment Reporting Additional Information [Abstract]

7,877

7,861

Corporate and Other [Member]

Revenue net of purchased power and fuel expense, Total

^[14]

Corporate and Other [Member] | Other Segments [Member]

329

297

619

^[1],[16]

615

^[1],[16]

328

298

(29)

(30)

(25)

^[16]

(132)

^[16]

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

8,769

8,317

Segment Elimination [Member] | Intersegment Eliminations [Member]

^[4],[16]

618

615

(531)

(631)

^[4]

(531)

(631)

(1,155)

(1,334)

$ 0

$ (11,717)

$ (11,221)

[1]	For the six months ended June 30, 2014 and 2013, utility taxes of $45 million and $39 million, respectively, are included in revenues and expenses for Generation. For the six months ended June 30, 2014 and 2013, utility taxes of $119 million and $117 million, respectively, are included in revenues and expenses for ComEd. For the six months ended June 30, 2014 and 2013, utility taxes of $65 million and $64 million, respectively, are included in revenues and expenses for PECO. For the six months ended June 30, 2014 and 2013, utility taxes of $43 million and $41 million, respectively, are included in revenues and expenses for BGE.
[2]	Includes all wholesale and retail electric sales from third parties and affiliated sales to ComEd, PECO and BGE.
[3]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the six months ended June 30, 2014 include revenue from sales to PECO of $ 137 million and sales to BGE of $ 207 million in the Mid-Atlantic region, and sales to ComEd of $ 173 million in the Midwest region. For the six months ended June 30, 2013 intersegment revenues for Generation include revenue from sales to PECO of $238 million in the Mid-Atlantic region and sales to BGE of $212 million in the Mid-Atlantic region, and sales to ComEd of $266 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.
[4]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations
[5]	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[6]	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
[7]	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
[8]	Other regions include the South, West and Canada, which are not considered individually significant.
[9]	Other regions include the South, West and Canada, which are not considered individually significant.
[10]	Other regions include the South, West and Canada, which are not considered individually significant.
[11]	Other regions include the South, West and Canada, which are not considered individually significant.
[12]	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $88 million and $234 million, for the three months ended June 30, 2014 and 2013, respectively, and elimination of intersegment revenues.
[13]	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $180 million and $478 million, for the six months ended June 30, 2014 and 2013, respectively, and elimination of intersegment revenues.
[14]	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $50 million and $167 million for the three months ended June 30, 2014 and 2013, respectively
[15]	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $92 million and $341 million, for the six months ended June 30, 2014 and 2013, respectively.
[16]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities

Related Party Transactions (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

May 15, 2014

Dec. 31, 2013

$ 0

287

$ 400

$ 605

(21)

(20)

(30)

(533)

(716)

$ 22

Equity Method Investment Summarized Financial Information[Abstract]

$ 38

116

Impact Of Transactions Under Agreements [Abstract]

49.99%

Amortization of energy contract assets and liabilities

^[1]

$ 113

306

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

67.00%

201

352

535

744

158

148

305

295

(12)

(16)

(25)

(34)

Cash distribution paid to member

(1)

(21)

(20)

(30)

235

474

Contributions from member

Mark-to-market derivative assets with affiliates

Total receivables from affiliates (current)

108

Mark-to-market derivative assets with affiliate (noncurrent assets)

Total payables to affiliates (noncurrent)

108

181

$ 2,917

2,740

Equity Method Investment Summarized Financial Information[Abstract]

Impact Of Transactions Under Agreements [Abstract]

49.99%

Amortization of energy contract assets and liabilities

^[1]

$ 118

344

Schedule of Equity Method Investments [Line Items]

Percentage of ownership interest in CENG (as a percent)

50.01%

Total equity investment earnings (losses) - CENG

$ 19

Basis difference in investment in CENG

204

$ 204

Exelon Generation Co L L C [Member] | Minimum [Member]

Equity Method Investment Summarized Financial Information[Abstract]

Required purchases of power from CENG's nuclear plants not sold to third parties (as a percent)

85.00%

$ 1

121

173

266

Contributions from parent

(153)

(110)

112

Total receivable from affiliates (noncurrent)

2,606

2,469

Mark-to-market derivative liabilities with affiliate (current liabilities)

135

238

Total receivable from affiliates (noncurrent)

(160)

(166)

490

447

(4)

$ (4)

(8)

Contributions from parent

$ 0

Average common shares outstanding - basic

$ 55

[1]	Included in purchased power and fuel expense on the Registrants' Consolidated Statements of Operations and Comprehensive Income

Quarterly Data (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

6 Months Ended

Jun. 30, 2014

Sep. 30, 2013

Jun. 30, 2013

Jun. 30, 2014

Jun. 30, 2013

Earnings Per Share Basic [Abstract]

860

856

860

856

Earnings Per Share, Basic

$ 0.61

$ 0.57

$ 0.71

$ 0.57

Earnings Per Share Diluted

Average common shares outstanding - diluted

864

860

863

859

Earnings Per Share, Diluted

$ 0.60

$ 0.57

$ 0.71

$ 0.57

Selected Quarterly Financial Information [Line Items]

$ 6,024

$ 6,141

$ 13,261

^[1]

$ 12,223

^[1]

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

829

1,005

$ 992

1,513

$ 557

497

498

Share Price And Dividend [Abstract]

$ 35

Selected Quarterly Financial Information [Line Items]

$ 3,789

4,070

$ 8,179

7,603

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

429

603

539

372

328

188

310

Selected Quarterly Financial Information [Line Items]

1,128

1,080

2,262

2,239

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

258

232

496

440

111

209

Selected Quarterly Financial Information [Line Items]

656

672

1,649

1,567

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

134

138

283

341

173

200

Selected Quarterly Financial Information [Line Items]

653

1,707

1,533

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

224

233

$ 19

$ 25

$ 106

[1]

Subsequent Event (Details) - USD ($) $ in Millions	6 Months Ended
Subsequent Event (Details) - USD ($) $ in Millions	Jun. 30, 2014	Jun. 30, 2013
Business Combination, Bargain Purchase [Abstract]
Payments To Acquire Businesses Gross	$ 66	$ 3
LineOfCreditFacilityMaximumBorrowingCapacity	8,500
Pepco Holdings [Member]
Business Combination, Bargain Purchase [Abstract]
CashFundingFromNonCoreAssetSale	1
Business Combination Proposed Customer Benefits Package	100
OtherLongTermInvestmentsMaximum	180
Pepco Holdings [Member] \| Maximum [Member]
Business Combination, Bargain Purchase [Abstract]
BusinessExitCosts	293
Pepco Holdings [Member] \| Minimum [Member]
Business Combination, Bargain Purchase [Abstract]
BusinessExitCosts	259
PECO Energy Co [Member]
Storm Damage Impact [Abstract]
Incremental operating and maintenance expense from storm damage (low estimate)	10
Incremental operating and maintenance expense from storm damage (high estimate)	20
Incremental capital expenditures from storm damage (low estimate)	10
Incremental capital expenditures from storm damage (high estimate)	20
Exelon Generation Co L L C [Member]
Business Combination, Bargain Purchase [Abstract]
Payments To Acquire Businesses Gross	(66)
Exelon Generation Co L L C [Member] \| Subsequent Event [Member]
BusinessCombinationsAbstract
PaymentsToAcquireBusinessesNetOfCashAcquired	60
Business Combination, Recognized Identifiable Assets Acquired And Liabilities Assumed, Working Capital	$ 183

Label

Element

Value

AMI Meter Events [Member]

Electric Generation Related Regulatory Asset [Member]

us-gaap_RegulatoryAssetsNoncurrent

$ 5,000,000

us-gaap_RegulatoryAssetsCurrent

13,000,000

us-gaap_RegulatoryAssetsCurrent

13,000,000

us-gaap_RegulatoryAssetsNoncurrent

24,000,000

Fair Value Of Supply Contract [Member]

us-gaap_RegulatoryAssetsNoncurrent

30,000,000

us-gaap_RegulatoryAssetsCurrent

6,000,000

^[1]

us-gaap_RegulatoryAssetsCurrent

12,000,000

^[1]

us-gaap_RegulatoryAssetsNoncurrent

^[1]

Conservative Voltage Reduction Program [Member]

us-gaap_RegulatoryAssetsNoncurrent

^[1]

Under Recovered Energy And Transmission Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

1,000,000

us-gaap_RegulatoryAssetsCurrent

17,000,000

us-gaap_RegulatoryAssetsCurrent

53,000,000

Merger Integration Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

4,000,000

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsCurrent

2,000,000

us-gaap_RegulatoryAssetsNoncurrent

7,000,000

us-gaap_RegulatoryAssetsNoncurrent

9,000,000

AMI Expenses [Member]

us-gaap_RegulatoryAssetsCurrent

7,000,000

us-gaap_RegulatoryAssetsCurrent

5,000,000

us-gaap_RegulatoryAssetsNoncurrent

222,000,000

Under Recovered Distribution Service Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

159,000,000

us-gaap_RegulatoryAssetsCurrent

219,000,000

us-gaap_RegulatoryAssetsCurrent

178,000,000

us-gaap_RegulatoryAssetsNoncurrent

220,000,000

Deferred Storm Costs [Member]

us-gaap_RegulatoryAssetsNoncurrent

285,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

3,000,000

us-gaap_RegulatoryAssetsNoncurrent

1,000,000

Under Recovered Uncollectible Accounts Expense [Member]

us-gaap_RegulatoryAssetsNoncurrent

3,000,000

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsCurrent

us-gaap_RegulatoryAssetsNoncurrent

70,000,000