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$ 29,447

$ 27,429

$ 24,888

Operating revenues

18,395

16,637

14,277

9,876

9,467

9,365

1,176

1,325

1,246

Regulated Operating Revenue

11,052

10,792

10,611

Reclassifications from accumulated OCI to net income

18,395

16,637

14,277

Purchased power and fuel from affiliates

3,077

3,103

2,540

Purchased power

10,007

9,369

6,928

531

1,256

8,322

8,568

7,270

2,450

2,314

2,153

1,200

1,154

1,095

Equity in (losses) earnings of unconsolidated affiliates

25,056

25,039

21,242

(20)

Gain on sales of assets

437

Gain on consolidation and acquisition of businesses

289

4,409

3,096

3,669

(992)

(1,024)

(1,315)

(41)

(46)

455

460

(1,079)

(610)

(896)

3,330

2,486

2,773

3,330

2,486

2,773

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

1,073

666

1,044

(7)

(20)

Net income (loss) attributable to noncontrolling interest and preference stock dividends

2,250

1,820

1,729

(197)

(10)

Net income attributable to common shareholders

2,269

1,623

1,719

Pension and non-pension postretirement benefit plans:

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

(46)

(30)

Actuarial loss reclassified to periodic cost, net of tax

220

147

208

Pension and non-pension postretirement benefit plans valuation adjustment, net of tax

(99)

(497)

669

Unrealized gain (loss) on cash flow hedges, net of taxes

(148)

(248)

Unrealized gain (loss) on marketable securities, net of taxes

Unrealized gain (loss) on equity investments, net of taxes

(3)

106

Unrealized gain (loss) on foreign currency translation, net of taxes

(21)

(9)

(10)

(116)

(644)

^[1]

727

Average shares of common stock outstanding:

$ 2,310

$ 1,176

$ 2,456

Basic

890

860

856

Diluted

893

864

860

Earnings per average common share:

Basic (in usd per share)

$ 2.55

$ 1.89

$ 2.01

Diluted (in usd per share)

2.54

1.88

2.00

Dividends per common share (in usd per share)

$ 1.24

$ 1.46

$ 19,135

$ 17,393

$ 15,630

Operating revenues

18,386

16,614

14,207

Reclassifications from accumulated OCI to net income

749

779

1,423

18,386

16,614

14,207

Purchased power and fuel from affiliates

10,007

9,368

6,927

557

1,270

4,688

4,943

3,960

620

623

574

1,054

967

856

489

465

389

Equity in (losses) earnings of unconsolidated affiliates

16,872

16,923

13,976

(20)

Gain on sales of assets

437

Gain on consolidation and acquisition of businesses

289

2,275

1,176

1,677

(322)

(303)

(298)

(43)

(53)

(59)

(60)

406

355

(425)

(2)

1,850

1,226

1,675

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

502

207

615

(8)

Net income (loss) attributable to noncontrolling interests

1,340

1,019

1,060

(32)

184

(10)

Net income attributable to membership interest

1,372

835

1,070

Pension and non-pension postretirement benefit plans:

Unrealized gain (loss) on cash flow hedges, net of taxes

(3)

(132)

(398)

Unrealized gain (loss) on marketable securities, net of taxes

(1)

Unrealized gain (loss) on equity investments, net of taxes

(3)

107

Unrealized gain (loss) on foreign currency translation, net of taxes

(21)

(9)

(10)

(116)

(27)

(250)

^[1]

(299)

1,313

769

761

Electric operating revenues

4,905

4,564

4,464

4,901

4,560

4,461

Purchased power from affiliate

1,301

1,001

662

176

512

1,372

1,263

1,211

195

166

157

707

687

669

296

293

299

Equity in (losses) earnings of unconsolidated affiliates

3,889

3,586

3,510

Gain on sales of assets

1,017

980

954

(319)

(308)

(566)

(13)

(311)

(304)

(553)

706

676

401

280

268

152

Pension and non-pension postretirement benefit plans:

426

408

249

7,528

426

408

249

3,032

3,094

3,100

2,485

2,446

2,499

545

646

600

Purchased power from affiliate

235

327

296

Purchased power

735

740

612

220

194

392

684

767

647

110

101

260

236

228

160

159

158

Gain (Loss) on Disposition of Other Assets

2,404

2,522

2,434

Equity in (losses) earnings of unconsolidated affiliates

630

572

666

(102)

(101)

(103)

(12)

(109)

(106)

(109)

521

466

557

143

114

162

Preferred security dividends and redemption

378

352

395

(7)

Net income attributable to common shareholders

378

352

388

Pension and non-pension postretirement benefit plans:

378

352

395

3,135

3,165

3,065

2,490

2,460

2,405

631

680

647

Purchased power from affiliate

498

382

452

Utilities Operating Expense, Purchased Power

602

733

676

Utilities Operating Expense, Fuel Used

205

302

293

565

614

551

118

103

366

371

348

224

221

213

Gain (Loss) on Disposition of Other Assets

2,578

2,726

2,616

Equity in (losses) earnings of unconsolidated affiliates

558

439

449

(83)

(90)

(106)

(16)

(81)

(88)

(105)

477

351

344

189

140

134

Preferred security dividends and redemption

288

211

210

(13)

Net income attributable to common shareholders

275

198

197

Pension and non-pension postretirement benefit plans:

$ 288

$ 211

$ 210

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

Consolidated Statements of Operations and Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commonwealth Edison Co [Member]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$ 0	$ 0	$ 0
PECO Energy Co [Member]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$ 0	$ 0	$ 0

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash flows from operating activities
Net income	$ 2,250	$ 1,820	$ 1,729
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	3,987	3,868	3,779
Impairment of long-lived assets	36	687	171
Gain on consolidation and acquisition of businesses	0	(296)	0
Gain on sales of assets	(18)	(437)	(13)
Gain on sales of assets	(18)	(437)	(13)
Deferred income taxes and amortization of investment tax credits	752	502	119
Net fair value changes related to derivatives	(367)	716	(445)
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments	131	(210)	(170)
Other non-cash operating activities	1,109	1,054	718
Changes in assets and liabilities:
Accounts receivable	240	(318)	(97)
Inventories	4	(380)	(100)
Accounts payable and accrued expenses	(121)	49	(116)
Option premiums received (paid), net	58	38	(36)
Collateral received (posted), net	347	(1,719)	215
Income taxes	97	(143)	883
Pension and non-pension postretirement benefit contributions	(502)	(617)	(422)
Other assets and liabilities	(387)	(157)	128
Net cash flows provided by operating activities	7,616	4,457	6,343
Cash flows from investing activities
Capital expenditures	(7,624)	(6,077)	(5,395)
Proceeds from termination of direct financing lease investment	0	335	0
Proceeds from nuclear decommissioning trust fund sales	6,895	7,396	4,217
Investment in nuclear decommissioning trust funds	(7,147)	(7,551)	(4,450)
Acquisitions of businesses	(40)	(386)	0
Proceeds from sales of long-lived assets	147	1,719	32
Proceeds from sales of investments	0	7	22
Cash and restricted cash acquired from consolidations and acquisitions	0	140	0
Purchases of investments	0	(3)	(4)
Change in restricted cash	66	(104)	(43)
Distribution from CENG	0	13	115
Other investing activities	(119)	(88)	112
Net cash flows used in investing activities	(7,822)	(4,599)	(5,394)
Cash flows from financing activities
Payment of accounts receivable agreement	0	0	(210)
Issuance of long-term debt	6,709	3,463	2,055
Retirement of long-term debt	(2,687)	(1,545)	(1,589)
Redemption of preferred securities	0	0	(93)
Distribution to noncontrolling interest of consolidated VIE	0	(421)	0
Dividends paid on common stock	(1,105)	(1,065)	(1,249)
Proceeds from employee stock plans	32	35	47
Other financing activities	67	178	119
Contributions from parent			0
Net cash flows provided by (used in) financing activities	4,830	411	(826)
Proceeds from Issuance of Common Stock	1,868	0	0
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	80	122	332
Increase in cash and cash equivalents	4,624	269	123
Cash and cash equivalents at beginning of period	1,878	1,609	1,486
Cash and cash equivalents at end of period	6,502	1,878	1,609
Parent Company [Member]
Cash flows from operating activities
Net income	2,269	1,623	1,719
Changes in assets and liabilities:
Net cash flows provided by operating activities	3,071	806	1,053
Cash flows from investing activities
Capital expenditures	0	1	0
Proceeds from termination of direct financing lease investment	0	335	0
Change in restricted cash	0	0	38
Other investing activities	(55)	(126)	15
Changes in Exelon intercompany money pool	(1,217)	(83)	(60)
Net cash flows used in investing activities	(934)	57	439
Cash flows from financing activities
Issuance of long-term debt	4,200	1,150	0
Retirement of long-term debt	(2,263)	(23)	(450)
Dividends paid on common stock	(1,105)	(1,065)	(1,249)
Proceeds from employee stock plans	32	35	47
Other financing activities	58	84	6
Contribution from member	3,209	1,370	1,175
Net cash flows provided by (used in) financing activities	2,674	13	(1,648)
Proceeds from Issuance of Common Stock	1,868	0	0
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	0	0	10
Increase in cash and cash equivalents	4,811	876	(156)
Cash and cash equivalents at beginning of period	879	3	159
Cash and cash equivalents at end of period	5,690	879	3
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	1,340	1,019	1,060
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	2,589	2,519	2,559
Impairment of long-lived assets	12	663	157
Gain on consolidation and acquisition of businesses	0	(296)	0
Gain on sales of assets	(12)	(437)	(13)
Gain on sales of assets	(12)	(437)	(13)
Deferred income taxes and amortization of investment tax credits	49	(198)	315
Net fair value changes related to derivatives	(249)	635	(448)
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments	131	(210)	(170)
Other non-cash operating activities	268	346	270
Changes in assets and liabilities:
Accounts receivable	194	(215)	109
Receivables from and payables to affiliates, net	15	15	2
Inventories	16	(359)	(88)
Accounts payable and accrued expenses	(149)	29	(160)
Option premiums received (paid), net	58	38	(36)
Collateral received (posted), net	407	(1,748)	162
Income taxes	(18)	265	402
Pension and non-pension postretirement benefit contributions	(245)	(297)	(149)
Other assets and liabilities	(207)	57	(85)
Net cash flows provided by operating activities	4,199	1,826	3,887
Cash flows from investing activities
Capital expenditures	(3,841)	(3,012)	(2,752)
Proceeds from nuclear decommissioning trust fund sales	6,895	7,396	4,217
Investment in nuclear decommissioning trust funds	(7,147)	(7,551)	(4,450)
Acquisitions of businesses	(40)	(386)	0
Proceeds from sales of long-lived assets	147	1,719	32
Cash and restricted cash acquired from consolidations and acquisitions	0	140	0
Change in restricted cash	35	(87)	(64)
Distribution from CENG	0	13	115
Other investing activities	(118)	(43)	30
Changes in Exelon intercompany money pool	0	44	(44)
Net cash flows used in investing activities	(4,069)	(1,767)	(2,916)
Cash flows from financing activities
Issuance of long-term debt	1,309	1,112	854
Retirement of long-term debt	(89)	(586)	(570)
Repayments of Related Party Debt	(550)
Changes in Exelon intercompany money pool	1,252	0	0
Distribution to noncontrolling interest of consolidated VIE	0	(421)	0
Other financing activities	(26)	67	82
Distribution to member	(2,474)	(645)	(625)
Contribution from member	47	53	26
Contributions from parent			0
Net cash flows provided by (used in) financing activities	(479)	(537)	(384)
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	0	17	13
Increase in cash and cash equivalents	(349)	(478)	587
Cash and cash equivalents at beginning of period	780	1,258	671
Cash and cash equivalents at end of period	431	780	1,258
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	426	408	249
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	707	687	669
Gain on sales of assets	(1)	(2)	0
Deferred income taxes and amortization of investment tax credits	353	433	(57)
Other non-cash operating activities	416	255	28
Changes in assets and liabilities:
Accounts receivable	(93)	(121)	(12)
Receivables from and payables to affiliates, net	(19)	(11)	(12)
Inventories	(40)	(16)	(18)
Accounts payable and accrued expenses	68	95	91
Collateral received (posted), net	(33)	2	53
Income taxes	192	(159)	178
Pension and non-pension postretirement benefit contributions	(150)	(248)	(122)
Other assets and liabilities	69	1	171
Net cash flows provided by operating activities	1,896	1,326	1,218
Cash flows from investing activities
Capital expenditures	(2,398)	(1,689)	(1,433)
Proceeds from sales of investments	0	7	7
Purchases of investments	0	(3)	(4)
Change in restricted cash	2	(2)	(2)
Other investing activities	34	32	45
Net cash flows used in investing activities	(2,362)	(1,655)	(1,387)
Cash flows from financing activities
Issuance of long-term debt	850	900	350
Retirement of long-term debt	(260)	(617)	(252)
Dividends paid on common stock	(299)	(307)	(220)
Other financing activities	16	10	1
Contributions from parent	202	273	176
Net cash flows provided by (used in) financing activities	467	359	61
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	(10)	120	184
Increase in cash and cash equivalents	1	30	(108)
Cash and cash equivalents at beginning of period	66	36	144
Cash and cash equivalents at end of period	67	66	36
PECO Energy Co [Member]
Cash flows from operating activities
Net income	378	352	395
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	260	236	228
Deferred income taxes and amortization of investment tax credits	90	88	20
Net realized and unrealized losses (gains) on nuclear decommissioning trust fund investments	2
Other non-cash operating activities	70	92	108
Changes in assets and liabilities:
Accounts receivable	37	(16)	(79)
Receivables from and payables to affiliates, net	3	(6)	(18)
Inventories	10	2	2
Accounts payable and accrued expenses	(25)	58	31
Income taxes	(9)	(57)	87
Pension and non-pension postretirement benefit contributions	(40)	(16)	(31)
Other assets and liabilities	(4)	(21)	4
Net cash flows provided by operating activities	770	712	747
Cash flows from investing activities
Capital expenditures	(601)	(661)	(537)
Change in restricted cash	(1)	0	(2)
Other investing activities	14	12	8
Net cash flows used in investing activities	(588)	(649)	(531)
Cash flows from financing activities
Payment of accounts receivable agreement	0	0	(210)
Issuance of long-term debt	350	300	550
Retirement of long-term debt	0	(250)	(300)
Redemption of preferred securities	0	0	(93)
Dividends paid on common stock	(279)	(320)	(332)
Other financing activities	4	4	2
Contributions from parent	16	24	27
Dividends paid on preferred securities	0	0	(1)
Net cash flows provided by (used in) financing activities	83	(250)	(361)
Increase in cash and cash equivalents	265	(187)	(145)
Cash and cash equivalents at beginning of period	30	217	362
Cash and cash equivalents at end of period	295	30	217
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	288	211	210
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	366	371	348
Deferred income taxes and amortization of investment tax credits	165	116	125
Other non-cash operating activities	137	180	153
Changes in assets and liabilities:
Accounts receivable	84	46	(127)
Receivables from and payables to affiliates, net	(2)	(1)	(14)
Inventories	18	(6)	1
Accounts payable and accrued expenses	(3)	(75)	(6)
Collateral received (posted), net	(27)	27	0
Income taxes	(54)	45	(33)
Pension and non-pension postretirement benefit contributions	(17)	(16)	(24)
Other assets and liabilities	(173)	(158)	(72)
Net cash flows provided by operating activities	782	740	561
Cash flows from investing activities
Capital expenditures	(719)	(620)	(587)
Change in restricted cash	26	(22)	2
Other investing activities	18	20	14
Net cash flows used in investing activities	(675)	(622)	(571)
Cash flows from financing activities
Issuance of long-term debt	0	0	300
Retirement of long-term debt	(75)	(70)	(467)
Dividends paid on common stock	(158)	0	0
Other financing activities	13	(13)	3
Contributions from parent	7	0	0
Dividends paid on preferred securities	(13)	(13)	(13)
Net cash flows provided by (used in) financing activities	(162)	(85)	(48)
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	90	(15)	135
Increase in cash and cash equivalents	(55)	33	(58)
Cash and cash equivalents at beginning of period	64	31	89
Cash and cash equivalents at end of period	$ 9	$ 64	$ 31

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

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

$ 6,502

$ 1,878

6,502

1,878

$ 1,609

$ 1,486

205

271

3,187

3,482

912

1,227

1,365

1,279

254

462

579

1,104

1,024

759

847

Assets held for sale

147

748

865

15,334

11,853

57,439

52,170

6,065

6,076

10,342

10,537

639

544

2,672

2,625

758

773

484

549

206

319

1,445

923

22,611

22,393

^[1]

95,384

86,416

533

460

1,500

1,802

2,883

3,048

2,376

1,539

Payables to affiliates

205

234

Energy Marketing Accounts Payable

100

238

302

192

369

310

842

931

9,118

8,762

23,645

19,212

^[2]

641

Deferred income taxes and unamortized investment tax credits

13,776

12,778

8,585

7,295

3,385

3,366

Spent nuclear fuel obligation

1,618

1,742

1,021

4,201

4,550

374

403

Payable for Zion Station decommissioning

117

211

155

1,491

2,147

34,658

33,668

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[1]

68,062

62,283

Treasury stock, at cost (35 shares at December 31, 2015 and 2014, respectively)

18,676

16,709

(2,327)

12,068

10,910

(2,624)

(2,684)

^[3]

(2,040)

^[3]

BGE preference stock not subject to mandatory redemption

25,793

22,608

193

Noncontrolling interest

1,308

1,332

Total equity

27,294

24,133

22,940

21,730

95,384

86,416

Member’s equity

Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]

(2,624)

(2,684)

^[3]

(2,040)

^[3]

8,268

8,159

3,264

2,728

144

533

477

272

648

199

Inventories, net

164

125

218

349

1,518

1,723

17,502

15,793

895

852

Receivable from affiliates

2,625

2,172

2,571

1,490

1,551

324

237

7,512

7,842

26,532

25,358

294

304

665

260

660

598

706

331

Customer deposits

131

128

155

125

2,766

1,923

5,844

5,665

205

Deferred income taxes and unamortized investment tax credits

4,914

4,561

111

103

259

263

3,459

3,655

224

187

507

889

9,474

9,658

18,289

17,451

1,588

Other paid-in capital

5,677

5,468

978

851

8,243

7,907

7,323

26,532

25,358

431

780

431

780

1,258

671

123

158

2,095

2,295

360

318

1,365

1,276

113

254

384

465

880

847

Assets held for sale

147

531

658

6,342

7,311

25,843

23,028

10,342

10,537

210

104

733

771

1,689

1,704

484

549

Deferred income taxes

206

319

627

578

14,344

14,612

^[4]

46,529

44,951

1,583

1,759

935

886

Payables to affiliates

556

104

107

182

214

Energy Marketing Accounts Payable

100

238

302

192

Exelon Money Pool Borrowing Current

356

413

1,252

4,933

4,459

7,936

6,639

933

943

Deferred income taxes and unamortized investment tax credits

5,845

5,707

8,431

7,146

Spent nuclear fuel obligation

924

915

1,021

150

105

Payable for Zion Station decommissioning

117

211

155

602

719

2,577

2,880

19,757

18,859

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[4]

33,559

30,900

(63)

(36)

^[3]

214

^[3]

Noncontrolling interest

1,307

1,333

Member’s equity

Membership interest

8,997

8,951

Undistributed earnings

2,701

3,803

Total liabilities and equity

(63)

(36)

^[3]

214

^[3]

Total member’s equity

11,635

12,718

Total equity

12,942

14,051

12,742

12,665

46,529

44,951

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

8,235

8,118

3,135

2,512

295

217

362

258

320

146

141

Prepaid utility taxes

842

645

7,141

6,801

1,583

1,529

Receivable from affiliates

405

490

347

344

2,384

2,414

10,367

9,860

300

281

337

109

Customer deposits

112

944

653

2,280

2,232

184

Deferred income taxes and unamortized investment tax credits

2,792

2,602

287

527

657

3,723

3,670

7,131

6,739

2,455

2,439

780

681

^[3]

3,236

3,121

3,065

2,982

10,367

9,860

Member’s equity

^[3]

300

390

112

Prepaid utility taxes

267

214

845

951

6,597

6,204

514

510

319

370

853

901

^[5]

8,295

8,056

210

120

378

209

215

110

131

Customer deposits

102

1,134

794

1,480

1,857

252

Deferred income taxes and unamortized investment tax credits

2,081

1,911

209

212

184

200

2,552

2,400

^[5]

5,418

5,303

1,367

1,360

1,320

1,203

BGE preference stock not subject to mandatory redemption

2,687

2,563

190

Total equity

2,877

2,753

$ 2,555

$ 2,358

Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]

8,295

8,056

Constellation Energy Group LLC [Member]

122

$ 197

Beginning Balance at Dec. 31, 2012

$ 187

[1]	Exelon’s consolidated assets include $8,268 million and $8,159 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,264 million and $2,728 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[3]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[4]	Generation’s consolidated assets include $8,235 million and $8,118 million at December 31, 2015 and 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,135 million and $2,512 million at December 31, 2015 and 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[5]	BGE’s consolidated assets include $26 million and $24 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $122 million and $197 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	919,924,742	859,833,343
Treasury Stock, Shares held	35,000,000	35,000,000
Commonwealth Edison Co [Member]
Common stock, shares authorized	250,000,000
Common Stock, Shares, Outstanding	127,016,973	127,016,947
PECO Energy Co [Member]
Common stock, shares authorized	500,000,000
Common Stock, Shares, Outstanding	170,478,507	170,478,507
Baltimore Gas and Electric Company [Member]
Common stock, shares authorized	175,000,000
Common Stock, Shares, Outstanding	1,000	1,000

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

Total

Common Stock [Member]

Treasury Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

PECO Energy Co [Member]

Common Stock [Member]

PECO Energy Co [Member]

Retained Earnings [Member]

PECO Energy Co [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Exelon Generation Co L L C [Member]

Noncontrolling Interest [Member]

Exelon Generation Co L L C [Member]

Membership Interest [Member]

Exelon Generation Co L L C [Member]

Undistributed Earnings [Member]

Commonwealth Edison Co [Member]

Common Stock [Member]

Commonwealth Edison Co [Member]

Other Paid-In Capital [Member]

Commonwealth Edison Co [Member]

Retained Deficit Unappropriated [Member]

Commonwealth Edison Co [Member]

Retained Earnings Appropriated [Member]

Baltimore Gas and Electric Company [Member]

Common Stock [Member]

Baltimore Gas and Electric Company [Member]

Retained Earnings [Member]

Baltimore Gas and Electric Company [Member]

Membership Interest [Member]

Baltimore Gas and Electric Company [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

$ 21,730

$ 16,632

$ (2,327)

$ 9,893

$ (2,767)

$ 106

$ 193

$ 2,358

$ 1,360

$ 808

$ 2,168

$ 190

Beginning Balance (in shares) at Dec. 31, 2012

889,525

Beginning Balance at Dec. 31, 2012

$ 2,982

$ 2,388

$ 593

$ 1

$ 7,323

$ 1,588

$ 5,014

$ (1,639)

$ 2,360

Beginning Balance at Dec. 31, 2012

$ 12,665

$ 513

$ 108

$ 8,876

$ 3,168

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

Long-term incentive plan activity, shares

$ 1,729

1,719

(10)

395

1,060

(10)

1,070

249

210

1,445

Long-term incentive plan activity

$ 81

Employee stock purchase plan issuances

$ 28

Employee stock purchase plan issuances, shares

1,064

Common stock issuance Constellation merger, shares

$ (1,254)

(1,254)

(6)

(332)

(220)

Consolidated VIE dividend to noncontrolling interest

$ (63)

(63)

Deconsolidation of VIE

(18)

(19)

(18)

(1)

Redemption of preferred securities

(6)

Other comprehensive income, net of income taxes

(14)

(1)

(13)

727

(299)

7,528

Tax benefit on stock compensation

(63)

Other comprehensive loss, net of income taxes

727

Distribution to member

(625)

Allocation of tax benefit from member

Parent tax matter indemnification

176

Appropriation of retained earnings for future dividends

(249)

249

Ending Balance at Dec. 31, 2013

$ 22,940

16,741

(2,327)

10,358

(2,040)

193

2,555

1,360

1,005

2,365

190

Ending Balance (in shares) at Dec. 31, 2013

892,034

Ending Balance at Dec. 31, 2013

3,065

2,415

649

1,588

5,190

(1,639)

2,389

Ending Balance at Dec. 31, 2013

12,742

214

8,898

3,613

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

Allocated Share-based Compensation Expense, Net of Tax

$ 74

Long-term incentive plan activity, shares

$ 1,820

1,623

184

352

1,019

184

835

408

211

1,574

Long-term incentive plan activity

$ 72

Employee stock purchase plan issuances

$ 35

Employee stock purchase plan issuances, shares

960

Consolidated VIE dividend to noncontrolling interest

(320)

(307)

421

Deconsolidation of VIE

(1,548)

Other comprehensive income, net of income taxes

$ (131)

(13)

^[1]

(644)

(250)

(421)

(1,071)

Tax benefit on stock compensation

(13)

Fair value of financing contract payments

(2)

(5)

(131)

Transfer of CENG pension and non-pension postretirement benefit obligations

(2)

Reversal of CENG equity method AOCI, net of income taxes

(116)

Other comprehensive loss, net of income taxes

(528)

(134)

Distribution to member

(645)

Allocation of tax benefit from member

Noncontrolling interest acquired

(1,548)

(116)

116

Parent tax matter indemnification

Appropriation of retained earnings for future dividends

(408)

408

Contribution from parent

273

Ending Balance at Dec. 31, 2014

$ 24,133

16,709

(2,327)

10,910

(2,684)

1,332

193

2,753

1,360

1,203

2,563

190

Ending Balance (in shares) at Dec. 31, 2014

894,568

Ending Balance at Dec. 31, 2014

$ 22,608

3,121

2,439

681

7,907

1,588

5,468

(1,639)

2,490

2,563

Ending Balance at Dec. 31, 2014

14,051

(36)

1,333

8,951

3,803

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

Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options

(8)

Allocated Share-based Compensation Expense, Net of Tax

Long-term incentive plan activity, shares

$ 2,250

2,269

(32)

378

1,340

(32)

1,372

426

288

1,430

Long-term incentive plan activity

$ 70

Employee stock purchase plan issuances

$ 32

Employee stock purchase plan issuances, shares

1,170

$ (1,111)

(1,111)

(279)

(299)

(158)

Other comprehensive income, net of income taxes

(13)

(27)

Tax benefit on stock compensation

Temporary Equity, Other Changes

(4)

(1)

(2)

Other comprehensive loss, net of income taxes

(27)

Distribution to member

(2,474)

Allocation of tax benefit from member

Noncontrolling interest acquired

(32)

Parent tax matter indemnification

Appropriation of retained earnings for future dividends

(426)

426

Contribution from parent

202

Ending Balance at Dec. 31, 2015

$ 27,294

18,676

$ (2,327)

$ 12,068

$ (2,624)

$ 1,308

$ 193

2,877

$ 1,367

$ 1,320

$ 2,687

$ 190

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

954,668

Ending Balance at Dec. 31, 2015

$ 25,793

$ 3,236

$ 2,455

$ 780

$ 1

$ 8,243

$ 1,588

$ 5,677

$ (1,639)

$ 2,617

$ 2,687

Ending Balance at Dec. 31, 2015

$ 12,942

$ (63)

$ 1,307

$ 8,997

$ 2,701

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

Stock Issued During Period, Shares, New Issues

57,500

Stock Issued During Period, Value, New Issues

$ 1,868

Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options

(3)

Allocated Share-based Compensation Expense, Net of Tax

$ 73

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

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($)
Other comprehensive income, income taxes	$ (468)
Exelon Generation Co L L C [Member]
Other comprehensive income, income taxes	190
PECO Energy Co [Member]
Other comprehensive income, income taxes	0
Commonwealth Edison Co [Member]
Other comprehensive income, income taxes	$ 0

Significant Accounting Policies

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Significant Accounting Policies (Exelon, Generation, ComEd, PECO and BGE)

(Exelon, Generation, ComEd, PECO and BGE)

Description of Business (Exelon, Generation, ComEd, PECO and BGE)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy delivery 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 5 — Investment in Constellation Energy Nuclear Group, LLC 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 Power 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.

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

This is a combined annual report of Exelon, Generation, ComEd, PECO and BGE. The Notes to the Consolidated Financial Statements apply to Exelon, Generation, ComEd, PECO and BGE as indicated above in the Index to Combined Notes to Consolidated Financial Statements and parenthetically next to each corresponding disclosure. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures.

Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. As a result of the Registrants' 2014 divestiture of certain unconsolidated affiliates considered integral to their operations and the consolidation of CENG during 2014, all Equity in earnings (losses) from unconsolidated affiliates have been presented below Income taxes in the Registrants' Consolidated Statements of Operations and Comprehensive Income starting in the first quarter of 2015.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.

Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preference stock. Exelon owned none of PECO’s preferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2015 and December 31, 2014, as equity, PECO’s preferred securities as preferred securities of subsidiary through their redemption in 2013, and BGE’s preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain Exelon Wind projects, of which Generation holds a majority interest of 99% for certain periods of time, and CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the noncontrolling members for these certain subsidiaries.

ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of which ComEd owns 75% and an additional 12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2015 and December 31, 2014, as equity.

Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity, it applies proportionate consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in Upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd, PECO, and BGE. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon’s percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions.

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

Use of Estimates (Exelon, Generation, ComEd, PECO and BGE)

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

Reclassifications (Exelon, Generation, ComEd, PECO and BGE)

Certain prior year amounts in the registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income, financial positions, or cash flows from operating activities.

Exelon revised the presentation on the Statements of Operations and Comprehensive Income for PECO and BGE to reflect separately operating revenues from the sale of electricity and operating revenues from the sale of natural gas, as well as, purchased power expense and purchased fuel expense within the operating expenses section of the Statement of Operations and Comprehensive Income. Further, Exelon revised the presentation from total operating revenues to "Rate-regulated utility revenues" and "Competitive businesses revenues" on the face of Exelon’s consolidated Statement of Operations and Comprehensive Income for all periods presented. Similarly, Exelon will separately present rate-regulated purchased power and fuel expense and non-rate regulated purchased power and fuel expense on the face of Exelon’s consolidated Statement of Operations and Comprehensive Income for all periods presented. The reclassifications described herein were made for presentation purposes and did not affect any of the Registrants’ total revenues or net income.

Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE)

Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities’ costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd’s, PECO’s or BGE’s business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3 — Regulatory Matters for additional information.

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

Revenues (Exelon, Generation, ComEd, PECO and BGE)

Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records its best estimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resulting from changes in rates that BGE believes are probable of approval by FERC in accordance with its formula rate mechanism. See Note 3 — Regulatory Matters and Note 6 — Accounts Receivable for further information.

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

Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As ComEd receives full cost recovery for energy procurement and related costs from retail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 3 — Regulatory Matters and Note 13 — Derivative Financial Instruments for further information.

Proprietary Trading Activities. Exelon and Generation account for Generation’s trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 13 — Derivative Financial Instruments for further information.

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

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

Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 15 — Income Taxes for further information.

Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE)

Exelon, Generation, ComEd, PECO and BGE collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 24 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s and BGE’s utility taxes that are presented on a gross basis.

Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)

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

Restricted Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2015 and 2014, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, as of December 31, 2015 and 2014, Generation’s restricted cash and cash equivalents primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which is required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2015 and 2014, ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2015 and 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2015 and 2014, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds and cash collateral held from suppliers.

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2015 and 2014, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2015, Exelon, Generation, ComEd, PECO and BGE had investments in Rabbi trusts classified as noncurrent assets.

Allowance for Uncollectible Accounts (Exelon, Generation, ComEd, PECO and BGE)

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable aging, historical experience and other currently available information. ComEd, PECO and BGE estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. ComEd, PECO and BGE customers’ accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.

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

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


•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,


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


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

Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities:


•	Exelon has disclosed, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon’s consolidated VIEs for which creditors do not have recourse to Exelon’s general credit.


•	Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity.

See Note 2 — Variable Interest Entities for additional information.

Inventories (Exelon, Generation, ComEd, PECO and BGE)

Inventory is recorded at the lower of weighted average cost or market. Provisions are recorded for excess and obsolete inventory.

Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, propane and oil. The costs of natural gas, propane and oil are generally included in inventory when purchased and charged to fuel expense when used or sold.

Materials and Supplies. Materials and supplies inventory generally includes the weighted average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant and equipment, as appropriate, when installed or used.

Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other deferred debits (for emission allowances that are exercisable beyond one year) and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations.

Marketable Securities (Exelon, Generation, ComEd, PECO and BGE)

All marketable securities are reported at fair value. Marketable securities held in the NDT funds are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Unrealized gains and losses, net of tax, for Exelon's available-for-sale securities are reported in OCI. Any decline in the fair value of Exelon's available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 16 — Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 24 — Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities.

Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)

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

Third parties reimburse ComEd, PECO and BGE for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE have been accounted for as CIAC.

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

For ComEd, PECO and BGE, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd’s and BGE’s depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility’s regulatory recovery method. ComEd’s and BGE’s actual incurred removal costs are applied against a related regulatory liability. PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.

Generation’s oil and gas exploration and production activities consist of working interests in gas producing fields. Generation accounts for these activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.

See Note 7 — Property, Plant and Equipment, Note 10 — Jointly Owned Electric Utility Plant and Note 24 — Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. On-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 23 — Commitments and Contingencies for additional information regarding the SNF disposal fee.

Nuclear Outage Costs (Exelon and Generation)

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

New Site Development Costs (Exelon and Generation)

New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management’s determination that the project is economically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. New site development costs incurred prior to a project’s completion being deemed probable are expensed as incurred. Approximately $22 million, $13 million and $10 million of costs were expensed by Exelon and Generation for the years ended December 31, 2015, 2014, and 2013, respectively. These costs are related to the possible development of new power generating facilities.

Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE)

Costs incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized within property, plant, and equipment. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:



Net unamortized software costs	Exelon		Generation		ComEd		PECO		BGE
December 31, 2015	$	633	$	180	$	172	$	86	$	178
December 31, 2014	596		193		133		84		163

Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO		BGE
2015	$	208	$	73	$	47	$	33	$	46
2014	186		59		45		28		43
2013	198		67		52		33		36

Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE)

Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd’s and BGE’s depreciation includes a provision for estimated removal costs as authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation’s operating nuclear generating stations except for Oyster Creek. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. The estimated service lives of the fossil fuel and other renewable generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic and capital requirement considerations.

See Note 7 — Property, Plant and Equipment for further information regarding depreciation.

Depletion of oil and gas exploration and production activities is recorded using the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for oil and gas reserves are based on internal calculations.

Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets is recorded to Operating revenues. Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

See Note 3 — Regulatory Matters and Note 24 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of ComEd’s, PECO’s and BGE’s regulatory assets.

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

The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, 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. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years unless circumstances warrant more frequent updates (such as a change in assumed operating life for a nuclear plant). As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income or, in the case of the majority of ComEd’s, PECO’s, and BGE’s accretion, through an increase to regulatory assets. See Note 16 — Asset Retirement Obligations for additional information.

Capitalized Interest and AFUDC (Exelon, Generation, ComEd, PECO and BGE)

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

Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.

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



		Exelon^(a)		Generation^(a)		ComEd		PECO		BGE
2015	Total incurred interest ^(b)	$	1,170	$	445	$	336	$	116	$	113
	Capitalized interest	79		79		—		—		—
	Credits to AFUDC debt and equity	44		—		9		7		28
2014	Total incurred interest ^(b)	$	1,144	$	419	$	323	$	115	$	118
	Capitalized interest	63		63		—		—		—
	Credits to AFUDC debt and equity	37		—		5		8		24
2013	Total incurred interest ^(b)	$	1,423	$	411	$	584	$	117	$	129
	Capitalized interest	54		54		—		—		—
	Credits to AFUDC debt and equity	35		—		16		6		13

_______________________


(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.


(b)	Includes interest expense to affiliates.

Guarantees (Exelon, Generation, ComEd, PECO and BGE)

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

The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 23 — Commitments and Contingencies for additional information.

Asset Impairments (Exelon, Generation, ComEd, PECO and BGE)

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

Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level along with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generation assets (typically contracted renewables). See Note 8 — Impairment of Long-Lived Assets for additional information.

Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 11 — Intangible Assets for additional information regarding Exelon’s, Generation's and ComEd’s goodwill.

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

Debt and Equity Security Investments. Exelon and Generation regularly monitor and evaluate debt and equity investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.

Direct Financing Lease Investments. Direct financing lease investments represent the estimated residual values of leased coal-fired plants in Georgia. Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if the review indicates an other-than-temporary decline in the fair value of the residual values below their carrying values. See Note 8 — Impairment of Long-Lived Assets for additional information.

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

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivative contracts intended to serve as economic hedges and that are not designated or do not qualify for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the Consolidated Statement of Operations based on the activity the transaction is economically hedging. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.

For commodity derivative contracts Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred through March 31, 2015. The effect of this decision is that all derivatives executed to hedge economic risk related to commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company.

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 13 — Derivative Financial Instruments for additional information.

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.

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 17 — Retirement Benefits for additional discussion of Exelon’s accounting for retirement benefits.

Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation)

Exelon and Generation include equity in earnings from equity method investments in qualifying facilities, power projects and joint ventures, in equity in earnings (losses) of unconsolidated affiliates within their Consolidated Statements of Operations and Comprehensive Income. Equity in earnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land, between their cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment.

Exelon and Generation continuously monitor for issues that potentially could impact future profitability of these equity method investments and which could result in the recognition of an impairment loss if such investment experiences an other-than-temporary decline in value.

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

Exelon has identified the following new accounting standards that have been recently adopted that management believes may significantly affect the Registrants.

Balance Sheet Classification of Deferred Taxes

In November 2015, the FASB issued authoritative guidance that requires deferred tax assets and deferred tax liabilities to be classified as noncurrent in a classified statement of financial position. The guidance is effective for periods beginning after December 15, 2016, with early adoption permitted. The guidance can be applied either prospectively or retrospectively. The Registrants early adopted the standard retrospectively in the fourth quarter of 2015, resulting in the following impacts as of December 31, 2014 in the Consolidated Balance Sheets of the Registrants:



For the year ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Increase (Decrease)
Current assets - Deferred income taxes	$	(244	)	$	(327	)	$	—		$	(69	)	$	(6	)
Deferred debits and other assets - Other	3			—			—			—			—
Current liabilities - Deferred income taxes	—			—			(63		)	—			(52		)
Deferred credits and other liabilities - Deferred income taxes	(241		)	(327		)	63			(69		)	46

The adoption of this guidance had no impact on the Registrants’ Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows.

Simplifying the Accounting for Measurement-Period Adjustments

In September 2015, the FASB issued authoritative guidance that requires an acquirer in a business combination to recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined and to record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. Under current guidance, such effects would be retrospectively recorded in prior periods. The guidance is effective for periods beginning after December 15, 2015. The guidance is required to be applied prospectively to adjustments to provisional amounts that occur after the effective date with earlier application permitted for financial statements that have not been issued. The Registrants early adopted the standard in the fourth quarter of 2015. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Application of Normal Purchases Normal Sales Exception to Power Contracts in Nodal Energy Markets

In August 2015, the FASB issued authoritative guidance addressing the ability of entities to elect the normal purchase normal sales (NPNS) scope exception when the contract for the purchase or sale of electricity on a forward basis is delivered to a nodal energy market or transmitted through a nodal energy market. The NPNS scope exception allows entities to treat certain contracts that qualify as derivatives as contracts that do not require recognition at fair value. The guidance specifies that the use of locational marginal pricing by an independent system operator in such transactions does not constitute net settlement of a contract for the purchase or sale of electricity, even in scenarios in which legal title to the associated electricity is conveyed to the independent system operator during transmission. Consequently, the use of locational marginal pricing by the independent system operator does not cause that contract to fail to meet the physical delivery criterion of the NPNS scope exception. Consistent with the Registrants' current practice, if the physical delivery criterion is met, along with all of the other criteria of the NPNS scope exception, an entity may elect to designate that contract as NPNS. The guidance is effective upon issuance and should be applied prospectively. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Simplifying the Presentation of Debt Issuance Costs

In April 2015, the FASB issued authoritative guidance that changes the presentation of debt issuance costs in financial statements. The new guidance requires entities to present such costs in the balance sheet as a direct reduction to the related debt liability rather than as a deferred cost (i.e., an asset) as required by current guidance. The new guidance does not change the recognition or measurement of debt issuance costs. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The guidance is required to be applied retrospectively to all prior periods presented. The Registrants early adopted the standard retrospectively in the fourth quarter of 2015. The adoption of this guidance resulted in a reclassification of $157 million, $70 million, $34 million, $14 million, and $16 million as of December 31, 2014, from Other long-term assets to Long-term debt, including Long-term debt to financing trusts, in the Consolidated Balance Sheets of Exelon, Generation, ComEd, PECO and BGE, respectively. The standard did not impact the Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows of the Registrants.

In August 2015, the FASB issued clarifying authoritative guidance for debt issuance costs incurred in connection with line-of-credit arrangements. The guidance states that an entity should defer and present debt issuance costs as an asset and subsequently amortize the deferred debt issuance costs ratably over the term of the line-of-credit arrangement. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of the Registrants.

Recognition and Measurement of Financial Assets and Financial Liabilities

In January 2016, the FASB issued authoritative guidance which (i) requires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

Simplifying the Measurement of Inventory

In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share

In May 2015, FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the statement of financial position. The guidance also removes the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share practical expedient. Rather, those disclosures are limited to investments for which the entity has elected to measure the fair value using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015 with early adoption permitted. The guidance is required to be applied retrospectively to all prior periods presented. The Registrants are currently assessing the impacts this guidance may have on their disclosures. There will be no impact to the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows.

Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either run the software on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. Beginning January 1, 2016, the Registrants will apply the standard prospectively and do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the assessment of limited partnerships as VIEs, (2) amends the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity, and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance is effective for the Registrants for the first interim period beginning on or after December 15, 2015. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are in the process of evaluating the standard and have not identified any changes to consolidation conclusions as a result of the new guidance and therefore have not elected an adoption method. Based on the analysis completed to date, a limited number of additional entities will be considered variable interest entities when the guidance is adopted, and required disclosures will be included in the Variable Interest Entities footnote.

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on our ability to recognize revenue for certain contracts where collectability is in question, our accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require us to recognize revenue at prices other than the contract price (e.g., straight line or forward curve). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. In August 2015, the FASB issued an amendment to provide a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017, as well as an option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard.

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

12 Months Ended

Dec. 31, 2015

Variable Interest Entity [Abstract]

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

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

At December 31, 2015 and 2014, Exelon, Generation, and BGE collectively consolidated seven and six VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of December 31, 2015 and 2014, the Registrants had significant interests in eight and six other VIEs, respectively, for which the Registrants do not have the power to direct the entities’ activities and, accordingly, were not the primary beneficiary (see Unconsolidated Variable Interest Entities below).

Consolidated Variable Interest Entities

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial statements at December 31, 2015 and 2014 are as follows:



	December 31, 2015						December 31, 2014 ^(a)
	Exelon ^(b)		Generation		BGE		Exelon ^(b)		Generation		BGE
Current assets	$	909	$	881	$	23	$	1,275	$	1,247	$	21
Noncurrent assets	8,009		8,004		3		7,573		7,560		3
Total assets	$	8,918	$	8,885	$	26	$	8,848	$	8,807	$	24
Current liabilities	$	473	$	387	$	81	$	611	$	526	$	77
Noncurrent liabilities	2,927		2,884		41		2,728		2,597		120
Total liabilities	$	3,400	$	3,271	$	122	$	3,339	$	3,123	$	197

_______________________


(a)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to classification of deferred taxes and simplifying the presentation of debt costs. See Note 1- Significant Accounting Policies for additional information.


(b)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

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

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

RSB BondCo LLC. In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1. BGE has determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE consolidates BondCo.

BondCo’s assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2015, 2014, and 2013, BGE remitted $86 million, $85 million, and $83 million, respectively, to BondCo.

BGE did not provide any additional financial support to BondCo during 2015. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.

Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with its existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third-party gas supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group’s activities without the additional credit support that is provided in the form of a parental guarantee. Generation is the primary beneficiary of the retail gas entity group; accordingly, Generation consolidates the retail gas entity group as a VIE.

The third-party gas supply arrangement is collateralized as follows:


•	the assets of the retail gas entity group must be used to settle obligations under the third-party gas supply agreement before it can make any distributions to Generation,


•	the third-party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and


•	Generation provides a $75 million parental guarantee to the third-party gas supplier in support of the retail gas entity group.

Other than credit support provided by the parental guarantee, Exelon or Generation do not have any contractual or other obligations to provide additional financial support under the collateralized third-party gas supply agreement. The third-party gas supply creditors do not have any recourse to Exelon’s or Generation’s general credit other than the parental guarantee.

Solar Project Entity Group. In 2011, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley) from First Solar, Inc., a 242-MW solar PV project in northern Los Angeles County, California. In addition, Generation owns a number of limited liability companies that build, own, and operate solar power facilities. While Generation owns 100% of these entities, it has been determined that certain of the individual solar project entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the solar project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar power facilities. 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. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $655 million, as of December 31, 2015, for which the creditors have no recourse to Generation. For additional information on these project-specific financing arrangements refer to Note 14 — Debt and Credit Agreements.

Retail Power and Gas Companies. In March 2014, Generation began consolidating retail power and gas VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $12 million in credit support for the retail power and gas companies. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs do not have a material impact on Generation’s financial results or financial condition.

Wind Project Entity Group. Generation owns and operates a number of wind project limited liability entities, the majority of which were acquired during 2010 with the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has evaluated the significant agreements and ownership structures and the risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either the projects have noncontrolling equity interest holders that absorb variability from the wind projects, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the wind project entities that qualify as VIEs because Generation controls the design, construction, and operation of the wind generation facilities. While Generation owns 100% of the majority of the wind project entities, nine of the projects have noncontrolling equity interests of 1% held by third parties. Generation’s current economic interests in eight of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation is to provide financial support to the projects in proportion to its current 99% economic interests in the projects. However, no additional support to these projects beyond what was contractually required has been provided during 2015. As of December 31, 2015, the carrying amount of the assets and liabilities that are consolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relates to the wind generating assets, PPA intangible assets and working capital amounts.

Other Generating Facilities. During the second quarter of 2015, Generation formed a limited liability company to build, own, and operate a backup generator. While Generation owns 100% of the backup generator company, it was determined that the entity is a VIE because the customer absorbs price variability from the entity through the fixed price backup generator agreement. Generation provides operating and capital funding to the backup generator company. Generation also owns 90% of a biomass fueled, combined heat and power company. In the second quarter of 2015, the entity was deemed to be a VIE because the entity requires additional subordinated financial support in the form of a parental guarantee provided by Generation for up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract for the facility (see Note 14 - Debt and Credit Agreements for additional details on Albany Green Energy, LLC). In addition to the parental guarantee, Generation provides operating and capital funding to the biomass fueled, combined heat and power company. Generation is the primary beneficiary of both entities since Generation has the power to direct the activities that most significantly affect the economic performance of the entities.

CENG. Through March 31, 2014, CENG was operated as a joint venture with EDF 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 EDF through the Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain special matters; 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 Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. As a result of executing the NOSA, CENG 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 and the CENG fleet conveyed through the NOSA. Further, since Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and, therefore, is required to consolidate the 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 EDF noncontrolling 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 year ended December 31, 2014. For additional information on this transaction refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC.

Generation and Exelon, where indicated, provide the following support to CENG (See Note 5 — Investment in Constellation Energy Nuclear Group, LLC and Note 26 — Related Party Transactions for additional information regarding Generation and Exelon’s transactions with CENG):


•	under the 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 and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF,


•	under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,

•

under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However, pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs have been suspended during the term of the expected Reliability Support Services Agreement (RSSA). (see Note 3 — Regulatory Matters for additional details),


•	Generation provided a $400 million loan to CENG. As of December 31, 2015, the remaining obligation is $300 million including accrued interest, which reflects the principal payment made in January 2015 (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC for more details),

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 23 — 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 2014 through 2016. As of December 31, 2015, the remaining obligation is approximately $1 million,


•	Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance (See Note 23 — Commitments and Contingencies for more details),


•	Generation provides a guarantee of approximately $7 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,


•	Generation and EDF 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 23 — 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.

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.

As of December 31, 2015 and 2014, ComEd and PECO did not have any material consolidated VIEs.

Assets and Liabilities of Consolidated VIEs

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of December 31, 2015 and 2014, these assets and liabilities primarily consisted of the following:



		December 31, 2015									December 31, 2014 (a)
		Exelon			Generation			BGE				Exelon		Generation		BGE
Cash and cash equivalents			$	164		$	164		$	—		$	392	$	392	$	—
Restricted cash			100			77			23			117		96		21
Accounts receivable, net
	Customer		219			219			—			297		297		—
	Other		43			43			—			57		57		—
Mark-to-market derivatives assets			140			140			—			171		171		—
Inventory
	Materials and supplies		181			181			—			172		172		—
Other current assets			35			30			—			37		30		—
	Total current assets		882			854			23			1,243		1,215		21

Property, plant and equipment, net			5,160			5,160			—			4,638		4,638		—
Nuclear decommissioning trust funds			2,036			2,036			—			2,097		2,097		—
Goodwill			47			47			—			47		47		—
Mark-to-market derivatives assets			53			53			—			44		44		—
Other noncurrent assets			90			85			3			90		77		3
	Total noncurrent assets		7,386			7,381			3			6,916		6,903		3
	Total assets		$	8,268		$	8,235		$	26		$	8,159	$	8,118	$	24

Long-term debt due within one year			$	111		$	27		$	79		$	87	$	5	$	75
Accounts payable			216			216			—			292		292		—
Accrued expenses			115			113			2			111		108		2
Mark-to-market derivative liabilities			5			5			—			24		24		—
Unamortized energy contract liabilities			12			12			—			22		22		—
Other current liabilities			13			13			—			25		25		—
	Total current liabilities		472			386			81			561		476		77

	Long-term debt		666			623			41			212		81		120
	Asset retirement obligations		1,999			1,999			—			1,763		1,763		—
	Pension obligation^(b)		9			9			—			9		9		—
	Unamortized energy contract liabilities		39			39			—			51		51		—
	Other noncurrent liabilities		79			79			—			132		132		—
	Noncurrent liabilities		2,792			2,749			41			2,167		2,036		120
	Total liabilities		$	3,264		$	3,135		$	122		$	2,728	$	2,512	$	197

___________


(a)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to classification of deferred taxes and simplifying the presentation of debt costs. See Note 1- Significant Accounting Policies for additional information.


(b)	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 17—Retirement Benefits 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. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.

As of December 31, 2015 and 2014, Exelon and Generation had significant unconsolidated variable interests in eight and six 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 the execution of an energy purchase and sale agreement with a new unconsolidated VIE and an equity investment in a new unconsolidated VIE.

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



December 31, 2015	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	263	$	164	$	427
Total liabilities^(a)	22		125		147
Exelon's ownership interest in VIE^(a)	—		11		11
Other ownership interests in VIE^(a)	241		28		269
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		21		21
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	17		—		17



December 31, 2014	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	114	$	91	$	205
Total liabilities^(a)	3		49		52
Exelon's ownership interest in VIE^(a)	—		9		9
Other ownership interests in VIE^(a)	111		33		144
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		13		13
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	27		—		27

___________________

(a)

These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon corrected an error in the December 31, 2014 balances within Commercial Agreement VIEs for an overstatement of Total assets, Total liabilities and Other ownership interests in VIE of $392 million, $234 million and $158 million, respectively. The error is not considered material to any prior period.

(b) These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $206 million and $319 million as of December 31, 2015 and December 31, 2014, respectively; offset by payables to ZionSolutions LLC of $189 million and $292 million as of December 31, 2015 and December 31, 2014, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

For each unconsolidated VIE, Exelon and Generation assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities.

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

ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 16 — Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning activities under the asset sale agreement are complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions’ creditors do not have any recourse to Exelon’s or Generation’s general credit.

Investment in Energy Development Projects, Distributed Energy Companies, and Energy Generating Facilities. Generation has several equity investments in energy development projects and energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because the entity has an insufficient amount of equity at risk to finance its activities, Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.

In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy company. Generation’s total equity commitment in this arrangement was $91 million and is paid incrementally over an approximate two year period (see Note 23 - Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and is recorded as an equity method investment.

In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company. Separate from the equity investment, Generation provided $27 million in cash to the other (10%) equity holder in the distributed energy company in exchange for a convertible promissory note. In November 2015, Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute $250 million of equity incrementally through December 2016 in proportion to their ownership interests, which equates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 23 - Commitments and Contingencies for additional details). Generation and the tax equity investor provide a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015 ESA Investco, LLC's obligation to make equity contributions to the distributed energy company. The investment in the distributed energy company was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. Generation continues to consolidate 2015 ESA Investco, LLC under the voting interest model.

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

ComEd, PECO and BGE

The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon’s, ComEd’s, PECO’s or BGE’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 14 —Debt and Credit Agreements for additional information.

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

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

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

(Exelon, Generation, ComEd, PECO and BGE)

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

Illinois Regulatory Matters

Energy Infrastructure Modernization Act (Exelon and ComEd).

Background

Since 2011, ComEd’s electric distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities to modernize Illinois’ electric utility infrastructure. EIMA was scheduled to sunset, ending ComEd’s performance based rate formula and investment commitment, at December 31, 2017, unless approved to continue through 2022 by the Illinois General Assembly. On April 3, 2015, the Governor signed legislation extending the EIMA sunset from 2017 to 2019.

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 (initial revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred for that year (annual reconciliation). See Annual Electric Distribution Filings below for further details. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to Operating revenue for any differences between the revenue requirement 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 December 31, 2015, and December 31, 2014, ComEd had a regulatory asset associated with the electric distribution formula rate of $189 million and $371 million, respectively. The regulatory asset associated with electric distribution true-up is amortized to Operating revenue in ComEd's Consolidated Statement of Operations and Comprehensive Income as the associated amounts are recovered through rates.

Participating utilities are also required to file an annual update on their AMI implementation progress. On April 1, 2015, ComEd filed an annual progress report on its AMI Implementation Plan with the ICC, which allows for the installation of more than four million smart meters throughout ComEd's service territory by 2018. To date, approximately two million smart meters have been installed in the Chicago area.

Pursuant to EIMA, ComEd annually contributes $4 million for customer education for as long as the AMI Deployment Plan remains in effect. Additionally, ComEd contributes $10 million annually through 2016 to fund customer assistance programs for low-income customers, which will not be recoverable through rates.

Annual Electric Distribution Filings

For each of the following years, the ICC approved the following total increases/(decreases) in ComEd's electric distributions formula rate filings:



Annual Distribution Filings	2015				2014				2013
ComEd's requested total revenue requirement (decrease) increase	$	(50	)		$	269			$	353

Final ICC Order
Initial revenue requirement increase	$	85			$	160			$	160
Annual reconciliation (decrease) increase	(152		)		72				181
Total revenue requirement (decrease) increase	$	(67	)		$	232			$	341

Allowed Return on Rate Base:
Initial revenue requirement	7.05		%		7.06		%		6.94		%
Annual reconciliation	7.02		%		7.04		%		6.94		%
Allowed ROE:
Initial revenue requirement	9.14		%	^(a)	9.25		%	^(a)	8.72		%
Annual reconciliation	9.09		%	^(a)	9.20		%	^(a)	8.72		%

Effective date of rates	January 2016				January 2015				January 2014

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(a) Includes a reduction of 5 basis points for a reliability performance metric penalty.

Formula Rate Structure Investigation

In October 2013, the ICC opened an investigation (the Investigation), in response to a complaint filed by the Illinois Attorney General, to change the formula rate structure by requesting three changes: the elimination of the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance, the netting of associated accumulated deferred income taxes against the annual reconciliation balance in calculating interest, and the use of average rather than year-end rate base for determining any ROE collar adjustment. On November 26, 2013, the ICC issued its final order in the Investigation, rejecting two of the proposed changes but accepting the proposed change to eliminate the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance. The accepted change became effective in January 2014, and reduced ComEd’s 2014 revenue by approximately $8 million. This change had no financial statement impact on ComEd in 2013. ComEd and intervenors requested rehearing, however all rehearing requests were denied by the ICC. ComEd and intervenors filed appeals with the Illinois Appellate Court. ComEd subsequently withdrew its appeal, but the Illinois Attorney General and the Citizens Utility Board continued to argue that the ICC had wrongly approved ComEd’s treatment of accumulated deferred income taxes (ADIT) relating to the annual reconciliation. On July 29, 2015, the Illinois Appellate Court rejected that appeal and affirmed the ICC's decision and its acceptance of ComEd’s treatment of ADIT. The period in which to file requests for further review has expired and that decision is final.

Appeal of Initial Formula Rate Tariff

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. On September 14, 2014, the Illinois Supreme Court declined to hear that appeal. ComEd elected not to seek review by the United States Supreme Court on the Federal law issues. Accordingly, the decision of the Illinois Appellate Court is considered final.

Grand Prairie Gateway Transmission Line (ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. 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. The costs incurred for the project prior to May 21, 2014 were immaterial. ComEd has acquired numerous easements across the project route through voluntary transactions. ComEd will seek to acquire the property rights on the remaining 28 parcels through condemnation proceedings in the circuit courts. ComEd began construction of the line during the second quarter of 2015 with an in-service date expected in the second quarter of 2017.

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, 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. As of December 31, 2015, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through 2021.

ComEd is required to purchase an increasing percentage of the electricity for customer deliveries from renewable energy resources. Purchases by customers of electricity from competitive electric 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 Illinois' RPS. All associated costs are recoverable from customers.

FutureGen Industrial Alliance, Inc (Exelon and ComEd). 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 ComEd and Ameren 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 ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, 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 sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014.

A significant portion of the cost of the development of FutureGen was being funded by the DOE under the American Recovery and Reinvestment Act of 2009. In early February 2015, the DOE suspended funding for the project until further clarity could be obtained on certain significant hurdles facing the project, including the outcome of the litigation described above. Whether or not the DOE funding will be reinstated at some later date is unknown at this time.

On January 13, 2016, FutureGen informed the Illinois Supreme Court that it had ceased all development efforts on the FutureGen project and would soon be seeking to terminate the FutureGen supply agreements. Accordingly, FutureGen requested that the court dismiss the proceeding as moot. A decision from the Illinois Supreme Court dismissing the matter is expected in early 2016. In February 2016, FutureGen terminated its sourcing agreement with ComEd. As a result, ComEd is under no further obligation under this agreement.

Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). Electric utilities in Illinois are required to include cost-effective energy efficiency resources in their plans to meet an incremental annual program energy savings requirement of 2% of energy delivered in the year commencing June 1, 2015 and each year thereafter. Additionally, during the ten-year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. In January 2014, the ICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June 2014 through May 2017. The plans are designed to meet Illinois' energy efficiency and demand response goals through May 2017, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers.

EIMA provides for additional energy efficiency in Illinois. Starting in the June 2013 through May 2014 period and occurring annually thereafter, as part of the IPA procurement plan, ComEd is to include cost-effective expansion of current energy efficiency programs, and additional new cost-effective and/or third-party energy efficiency programs that are identified through a request for proposal process. All cost-effective energy efficiency programs are included in the IPA procurement plan for consideration of implementation. While these programs are monitored separately from the Energy Efficiency Portfolio Standard (EEPS), funds for both the EEPS portfolio and IPA energy efficiency programs are collected under the same rider.

Illinois utilities are required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of December 31, 2015, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois legislation. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates.

Pennsylvania Regulatory Matters

2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO). On March 27, 2015, PECO filed a petition with the PAPUC requesting an increase of $190 million to its annual service revenues for electric delivery, which requested an ROE of 10.95%. On September 10, 2015, PECO and interested parties filed with the PAPUC a petition for joint settlement for an increase of $127 million in annual distribution service revenue. No overall ROE was specified in the settlement. On December 17, 2015, the PAPUC approved the settlement of PECO’s electric distribution rate case. The approved electric delivery rates became effective on January 1, 2016.

The settlement includes approval of the In-Program Arrearage Forgiveness (“IPAF”) Program, which provides for forgiveness of a portion of the eligible arrearage balance of its low-income Customer Assistance Program (CAP) accounts receivable that will be determined as of program inception in October 2016. The forgiveness will be granted to the extent CAP customers remain current with payments. The Settlement guarantees PECO’s recovery of two-thirds of the arrearage balance through a combination of customer payments and rate recovery, including through future rates cases if necessary. The remaining one-third of the arrearage balance will be absorbed by PECO, of which a portion has already been expensed as bad debt for CAP customer’s accounts receivable balances.

Although the actual arrearage balance is not defined until program inception, PECO believes that it can reasonably estimate certain CAP customer accounts receivable balances as of December 31, 2015 that will remain outstanding at program inception. Management determined its best estimate based on historical collectability information. As a result, a regulatory asset of $7 million, representing the previously incurred bad debt expense associated with the estimated eligible accounts receivable balances, was recorded on Exelon’s and PECO’s Consolidated Balance Sheets as of December 31, 2015. This estimate will be revisited on a quarterly basis through program inception.

2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO’s electric and natural gas distribution rate cases, which were filed in March 2010, providing increases in annual service revenue of $225 million and $20 million, respectively.

The settlements included a stipulation regarding how tax benefits related to the application of any new IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements required that the expected cash benefit from the application of any new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safe harbor and elected a method change for the 2010 tax year. The total refund to customers for the tax cash benefit from the application of the safe harbor to costs incurred prior to 2010 was $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute the refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, which is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2012.

In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million. This amount is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2013. PECO is awaiting IRS guidance that will provide a safe harbor method of accounting for gas transmission and distribution property.

The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return. As agreed to in the 2010 distribution rate case settlements, these benefits were reflected in the determination of revenue requirements in the 2015 electric distribution rate case discussed above and will be reflected in the next natural gas distribution rate case. See Note 15 — Income Taxes for additional information.

The 2010 electric and natural gas distribution rate case settlements did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. PECO has not filed a transmission rate case since rates have been unbundled.

Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s first two PAPUC approved DSP Programs, PECO procured electric supply for its default electric customers through PAPUC approved competitive procurements. DSP I and DSP II expired on May 31, 2013 and May 31, 2015, respectively.

The second DSP Program included 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 CAP customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan with the PAPUC. By an 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, the Office of Consumer Advocate (OCA) and 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 July 14, 2015, the Court issued opinions on the OCA and low-income advocacy group appeal. Specifically, the Court remanded the issue to the PAPUC with instructions that it approve a rule revision to the PECO CAP Shopping Plan that would prohibit CAP customers from entering into contracts with an EGS that would impose early cancellation/termination fees. The PAPUC has appealed the Court's decision. PECO does not have information at this time as to what action it may be required to take following remand to the PAPUC.

On December 4, 2014, the PAPUC approved PECO's third DSP Program. 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. Under the program, PECO is procuring electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June 2016, the medium commercial class (101-500 kW) will move to spot market pricing. As of December 31, 2015, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the first two of its four scheduled procurements. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO's Consolidated Statement of Operations and Comprehensive Income.

On March 12, 2015, PECO settled the CAP Design with the Office of Consumer Advocates (OCA) and Low Income Advocates, and filed the proposed plan with the PAPUC on March 20, 2015. The program design changes the rate structure of PECO's CAP to make the bills more affordable to customers enrolled in the assistance program. The CAP discounts continue to be recovered through PECO's universal service fund cost. On July 8, 2015, the CAP Design was approved by the PAPUC. PECO plans to implement the program changes in October 2016.

Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, pursuant to Act 129 and the follow-on Implementation Order of 2009, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million electric smart meters and an AMI communication network by 2020. PECO is currently in the second phase of the SMPIP and has deployed substantially all remaining smart meters as of December 31, 2015, for a total of 1.7 million smart meters. In total, PECO currently expects to spend up to $589 million, excluding the cost of the original meters, on its smart meter infrastructure and approximately $155 million on smart grid investments through final deployment of which $200 million has been funded by SGIG. As of December 31, 2015, PECO has spent $578 million and $155 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received. Recovery of smart meter costs will be reflected in base rates effective January 1, 2016.

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. On November 15, 2013, PECO filed its final compliance report with the PAPUC communicating PECO had met all Phase I reduction targets.

The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provided energy consumption reduction requirements for the second phase of Act 129’s EE&C program, which went into effect on June 1, 2013. Pursuant to the Phase II implementation order, PECO filed its three-year EE&C Phase II Plan with the PAPUC on November 1, 2012. The plan set forth how PECO would reduce electric consumption by at least 1,125,852 MWh in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permitted PECO to apply any excess savings achieved during Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions had to be through programs directed toward PECO’s public and low income sectors, respectively. If PECO failed to achieve the required reductions in consumption, it would have been subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of the plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006.

On March 15, 2013 and February 28, 2014, PECO filed Petitions for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers through May 31, 2014 and May 31, 2016, respectively. PECO proposed to fund the estimated $10 million annual costs of the plan by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Plan surcharge along with other Phase II Plan costs. The PAPUC granted PECO’s Petitions on May 5, 2013 and April 23, 2014, respectively.

The PAPUC issued its Phase III EE&C implementation order on June 19, 2015, that provides energy consumption reduction requirements for the third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021. The order tentatively established PECO’s five-year cumulative consumption reduction target at 2,080,553 MWh.

Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for the period June 1, 2016 through May 31, 2021. PECO expects a final decision from the PAPUC on PECO’s EE&C Phase III Plan during the first quarter of 2016.

Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2011, following the expiration of PECO’s rate cap transition period, certain percentages of electric energy sold to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8%, and the requirement for Tier II alternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 and the AEPS Act.

PECO continues to procure alternative energy credits through full requirements contracts and its existing long-term solar contracts to meet the annual AEPS compliance requirements. All AEPS compliance costs are being recovered on a full and current basis from default service customers through the GSA.

Pennsylvania Retail Electricity and Gas Markets (Exelon and PECO). Beginning in 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electricity market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. Through various orders, the PAPUC issued default electric service pricing for customers in PECO’s service territory. See Pennsylvania procurement proceedings discussed above for additional details.

In early 2014, the extreme weather in PECO's service territory resulted in increased electricity 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 were to be in place within 30 days and six months of approval of the orders, respectively. The orders became final on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowing PECO to implement accelerated switching by the December 15, 2014 deadline.

On September 12, 2013, the PAPUC issued an Order that initiated an investigation into Pennsylvania’s natural gas retail market, including the role of the existing default service model and opportunities for market enhancements. On December 18, 2014, the PAPUC issued a Final Order directing the Office of Competitive Market Oversight (OCMO) to continue its investigation, confirming that natural gas distribution companies should remain with the default service model for the time being and directing establishment of a working group to examine other competitive issues. The OCMO has established a working group to review operation of the natural gas retail market and to consider potential recommendations on competitive issues.

Pennsylvania Act 11 of 2012 (Exelon and PECO). In February 2012, Act 11 was signed into law, which provided the PAPUC authority to approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure.

On May 7, 2015, the PAPUC approved PECO's modified natural gas LTIIP. In accordance with the approved LTIIP, PECO plans to spend $534 million through 2022 to further accelerate the replacement of existing gas mains and to relocate meters from indoors to outside in accordance with recent PAPUC rulemaking. In addition, on March 20, 2015, PECO filed a petition with the PAPUC for approval of its gas DSIC mechanism for recovery of gas LTIIP expenditures. On September 11, 2015, the PAPUC entered its Opinion and Order approving PECO’s petition for a gas DSIC.

On March 27, 2015, PECO filed a petition with the PAPUC for approval of its proposed electric DSIC and LTIIP. In accordance with the LTIIP (System 2020 plan), PECO plans to spend $275 million over the next five years to modernize and storm-harden its electric distribution system, making it more weather resistant and less vulnerable to damage. The DSIC will allow PECO the opportunity to recover the costs, subject to certain criteria, incurred to repair, improve or replace its electric distribution property between rate cases. On October 22, 2015, the PAPUC entered its Opinion and Order approving PECO’s proposed petition for its electric LTIIP and DSIC.

Maryland Regulatory Matters

2015 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On November 6, 2015, and as amended on January 5, 2016, BGE filed for electric and gas base rate increases with the MDPSC, ultimately requesting an increase of $121 million and $79 million, respectively, of which $103 million and $37 million, respectively, is related to recovery of smart grid initiative costs. BGE requested a ROE for the electric and gas distribution rate case of 10.6% and 10.5%, respectively. The new electric and gas base rates are expected to take effect in June 2016. BGE is also proposing to recover an annual increase of approximately $30 million for Baltimore City conduit lease fees through a surcharge. BGE cannot predict how much of the requested increase the MDPSC will approve or if it will approve BGE's request for a conduit fee surcharge.

2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, and as amended on September 15, 2014, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $99 million and $68 million, respectively.

On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the Settlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates and an increase of $38 million in gas base rates. The Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately $20 million, primarily for electric. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order on December 12, 2014. The approved distribution rate order authorizing BGE to increase electric and gas distribution rates became effective for services rendered on or after December 15, 2014.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, respectively. In addition to these requested rate increases, BGE’s application includes 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 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, and an allowed return on equity of 9.75% and 9.60%, respectively. Rates became effective for services rendered on or after December 13, 2013. The MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. 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. The ERI initiative surcharge became effective June 1, 2014. On November 2, 2015, BGE filed a surcharge update including a true-up of cost estimates included in the 2015 surcharge, along with its work plan and cost estimates for 2016, to be included in the 2016 surcharge. The MDPSC subsequently approved BGE's 2016 work plan and the 2016 surcharge.

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 residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC's approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. On October 26, 2015, the Circuit Court for Baltimore City issued an order affirming the MDPSC's decision. However, on November 30, 2015, the residential consumer advocate filed an appeal of the Circuit Court's decision with the Maryland Court of Special Appeals. BGE cannot predict the outcome of this appeal. If the residential consumer advocate's appeal is successful, BGE could recover ERI expenditures through other regulatory mechanisms.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of December 31, 2015 and December 31, 2014, BGE recorded a regulatory asset of $196 million and $128 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE's 2014 electric and gas distribution rate case, the cost of the retired non-AMI meters will be amortized over 10 years.

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 of BGE's smart meter installation program, 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. On November 25, 2014, the MDPSC issued a decision approving BGE's proposal to automatically enroll unresponsive customers into the opt-out program and to charge those customers opt-out fees after BGE has exhausted attempts to schedule a meter installation. On November 5, 2015, the MDPSC held a hearing to evaluate the $11 recurring monthly fee paid by opt-out customers. Effective with January 2016 bills, the monthly recurring fee was reduced to $5.50.

As part of the 2015 electric and gas distribution rate case filed on November 6, 2015, BGE is seeking recovery of its smart grid initiative costs. Of BGE's requested $200 million, $140 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs by a ratio of 2.3 to 1.0, on a nominal basis.

New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that CPV projected will be in commercial operation by June 1, 2015. CPV subsequently sought to extend that date. The initial term of the proposed contract is 20 years. The CfD mandates that BGE and the other utilities pay (or receive) the difference between CPV’s contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The MDPSC’s order requires the three Maryland utilities to enter into a CfD in amounts proportionate to their relative SOS load. On April 16, 2013, the MDPSC issued an order that required BGE to execute a specific form of contract with CPV, and the parties executed the contract as of June 6, 2013.

On April 27, 2012, a civil complaint was filed in the U.S. District Court for the District of Maryland by certain unaffiliated parties that challenged the actions taken by the MDPSC on Federal law grounds. On October 24, 2013, the U.S. District Court issued a judgment order finding that the MDPSC’s Order directing BGE and the two other Maryland utilities to enter into a CfD, which assures that CPV receives a guaranteed fixed price regardless of the price set by the federally regulated wholesale market, violates the Supremacy Clause of the United States Constitution. On November 22, 2013, the MDPSC and CPV appealed the District Court’s ruling to the United States Court of Appeals for the Fourth Circuit. The Fourth Circuit affirmed the District Court ruling in an opinion issued June 2, 2014. The MDPSC and CPV filed petitions for certiorari, seeking review of the case by the U.S. Supreme Court. On October 29, 2015, the U.S. Supreme Court granted the petition to review the Fourth Circuit decision, and that appeal is now pending in the Supreme Court with oral argument scheduled for February 24, 2016.

On February 9, 2011, a civil complaint was filed by Exelon and other unaffiliated parties in the United States District Court for the District of New Jersey, challenging a 2011 New Jersey law, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity in the PJM capacity market. On October 25, 2013, the U.S. District Court issued a judgment order finding that LCAPP violates the Supremacy Clause of the United States Constitution. CPV and New Jersey appealed the District Court’s ruling to the United States Court of Appeals for the Third Circuit. On September 11, 2014, the Third Circuit affirmed the District Court’s ruling finding LCAPP unconstitutional. On November 26, 2014, CPV and New Jersey sought Supreme Court review of the Third Circuit decision. On October 29, 2015, the Supreme Court stayed the petition to review the Third Circuit case pending their review of the Fourth Circuit Maryland case described above.

On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order under state law. That petition was subsequently transferred to the Circuit Court for Baltimore City and consolidated with similar appeals that have been filed by other interested parties. On October 1, 2013, the Circuit Court Judge issued a Memorandum Opinion and Order finding the decisions of the MDPSC were within its statutory authority under Maryland law. This decision is separate from the judgment in the federal litigation that the MDPSC Order is unconstitutional and the CfD is unenforceable under federal law. The federal judgment, if upheld, would prevent enforcement of the CfD even if the Circuit Court decision stands. On October 29, 2013, BGE and the two other Maryland utilities appealed the Circuit Court’s ruling to the Maryland Court of Special Appeals. That appeal has been stayed pending decision by the U.S. Supreme Court in the federal action described above.

Depending on the ultimate outcome of the pending state and federal litigation, on the eventual market conditions, and on the manner of cost recovery as of the effective date of the agreement, the CfD could have a material impact on Exelon and BGE’s results of operations, cash flows and financial positions.

Exelon believes that this and other states’ projects may have artificially suppressed capacity prices in PJM and may continue to do so in future auctions to the detriment of Exelon’s market driven position. In addition to this litigation, Exelon is working with other market participants to implement market rules that will appropriately limit the market suppressing effect of such state activities.

MDPSC Derecho Storm Order (Exelon and BGE). Following the June 2012 Derecho storm which hit the mid-Atlantic region interrupting electrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 requiring BGE and other Maryland utilities to file several comprehensive reports with short-term and long-term plans to improve reliability and grid resiliency that were due at various times before August 30, 2013.

On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of the electric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various storm scenarios. During the summer of 2014, an evaluation of the reports filed by BGE and other Maryland utilities was undertaken by consultants on behalf of the MDPSC and MDPSC Staff. The MDPSC Staff also proposed standards for reliability during major events and estimated times of restoration as well as undertaking an evaluation of performance-based ratemaking principles and methodologies that would more directly and transparently align reliable service with the utilities’ distribution rates and that reduce returns or otherwise penalize sub-standard performance. The MDPSC held hearings in September 2014. BGE currently cannot predict the outcome of these proceedings, which may result in increased capital expenditures and operating costs.

The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation intended to accelerate gas infrastructure replacements in Maryland was signed into law. The law established a mechanism, separate from base rate proceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure replacement projects incurred after June 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject to a cap and require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution 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 November 16, 2015, BGE filed a surcharge update to be effective January 1, 2016, including a true-up of cost estimates included in the 2015 surcharge, along with its 2016 project list and projected capital estimates of $113 million to be included in the 2016 surcharge calculation. The MDPSC subsequently approved BGE's 2016 project list and the proposed surcharge for 2016, which included the 2015 surcharge true-up. As of December 31, 2015, BGE recorded a regulatory asset of less than $1 million, representing the difference between the surcharge revenues and program costs.

In 2014, the residential consumer advocate in Maryland appealed MDPSC's decision on BGE's infrastructure replacement plan and associated surcharge with the Baltimore City Circuit Court, who affirmed the MDPSC's decision. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court. During the third quarter of 2015, the residential consumer advocate, MDPSC and BGE filed briefs. Oral argument in this matter was held before the Court of Special Appeals on November 3, 2015. On January 28, 2016, the Maryland Court of Special Appeals issued a decision affirming the MDPSC's decision.

New York Regulatory Matters

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). Ginna Nuclear Power Plant's (Ginna) prior period fixed-price PPA contract with Rochester Gas & Electric Company (RG&E) expired in June 2014. In light of the expiration of the PPA and prevailing market conditions, in January 2014, Ginna advised the New York Public Service Commission (NYPSC) and the ISO-NY that, in the absence of a reliability need, Ginna management would make a recommendation, subject to approval by the CENG board, that the Ginna plant be retired as soon as practicable. A formal study conducted by the ISO-NY and RG&E dated as of May 12, 2014 concluded that Ginna needs to remain in operation to maintain the reliability of the transmission grid in the Rochester region through September 2018 when planned transmission system upgrades undertaken by RG&E are expected to be completed.

In November 2014, in response to a petition filed by Ginna, the NYPSC directed Ginna and RG&E to negotiate a Reliability Support Services Agreement (RSSA). In February 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continued operation of Ginna for reliability purposes were made with the NYPSC and with the FERC for their approval. Although the RSSA contract is still subject to such regulatory approvals, on April 1, 2015, Ginna began delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the proposed RSSA contract.

In April 2015, the FERC issued an order which directed Ginna to make a compliance filing to ensure that the RSSA does not allow Ginna to receive revenues above its full cost of service and which rejected any extension of the RSSA beyond its initial term; rather the order required that any extension be subject to the rules currently being developed by the ISO-NY. The FERC order also set the RSSA for hearing and settlement procedures. In response to the FERC's April 2015 order, in May 2015, Ginna submitted a compliance filing to the FERC containing proposed revisions to the RSSA addressing the FERC's requirements and maintaining the April 1, 2015 proposed effective date. In July 2015, the FERC accepted Ginna’s compliance filing effective April 1, 2015. The FERC accepted Ginna's proposal for market revenue sharing subject to a cap effective April 1, 2015, and rejected requests for rehearing by intervenors on a number of matters related to jurisdiction, the reliability need, the RSSA term, and possible price suppression.

In August 2015, Ginna reached a settlement in principle with intervenors modifying certain terms and conditions in the originally negotiated agreement. The proposed RSSA under the settlement preserves the value of the contract originally negotiated with RG&E, but shortens the term from 3.5 to 2 years, expiring March 31, 2017 and required RG&E to complete a new transmission reliability study to determine whether an interim reliability solution is required beyond March 31, 2017. That reliability study was completed in October 2015, and it identified certain RG&E projects that are needed to solve reliability problems that would be caused by an early retirement of Ginna. Under the settlement agreement, Ginna was required by December 29, 2015 to submit a bid to provide reliability services beginning April 1, 2017 until the necessary RG&E transmission upgrades are in service, which RG&E expects will be no later than October 31, 2017. Ginna submitted such a bid in December 2015. RG&E has the right until June 30, 2016 to select Ginna as an ongoing reliability solution. If such a need exists, and if Ginna is selected, Ginna and RG&E could enter into an additional RSSA commencing April 1, 2017 on the rates, terms and conditions set forth in Ginna’s bid, or as might be otherwise agreed by Ginna and RG&E.

If RG&E seeks a reliability solution with Ginna, but RG&E and Ginna do not reach an agreement on rates, terms, and conditions of a new RSSA by March 31, 2016 (or by June 30, 2016 if RG&E elects to defer the decision date), the settlement agreement requires Ginna to file an unexecuted additional RSSA with the FERC for adjudication. If Ginna is not selected for continued reliability service and does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the proposed RSSA, if RG&E does not select Ginna to provide reliability service after March 31, 2017, and Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments related to capital expenditures to RG&E.

The August 2015 settlement was filed at the NYPSC and at the FERC in October 2015 and remains subject to review and approval by both agencies; such reviews are not expected to be completed until the first quarter of 2016.

Until final regulatory approvals are received, Generation is recognizing revenue based on market prices for energy and capacity delivered by Ginna into the ISO-NY. Upon receiving regulatory approvals, under the RSSA contract terms, Generation would then recognize revenue based on the final approved pricing contained in the contract retroactively from the April 1, 2015 effective date. While the RSSA is expected to receive regulatory approvals and, therefore, permit Ginna to continue operating through the RSSA term, there is still a risk that, for economic reasons, including the possibility that the FERC or the NYPSC may condition the approval of the RSSA on a modification of the rates set forth in the RSSA, Ginna could be retired before 2029, which is the end of its operating license period. In the event the plant were to be retired before the current license term ends in 2029, Exelon's and Generation's results of operations could be adversely affected by accelerated future decommissioning costs, severance costs, increased depreciation rates, and impairment charges, among other items. However, it is not expected that such impacts would be material to Exelon's or Generation's results of operations.

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 are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year. 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 filed with the FERC for that year’s reconciliation. As of December 31, 2015, and 2014, ComEd had a regulatory asset associated with the transmission formula rate of $31 million and $21 million, respectively. As of December 31, 2015, and 2014, BGE had a net regulatory asset associated with the transmission formula rate of $12 million and $1 million, respectively. The regulatory asset associated with transmission true-up is amortized to Operating revenues within their Consolidated Statements of Operations of Comprehensive Income as the associated amounts are recovered through rates.

For each of the following years, the following total increases/(decreases) were included in ComEd's and BGE's electric transmission formula rate filings:



	ComEd									BGE
Annual Transmission Filings	2015			2014			2013			2015			2014			2013
Initial revenue requirement increase ^(a)	$	68		$	36		$	38		$	—		$	9		$	2
Annual reconciliation (decrease) increase	18			(14		)	30			(3		)	5			(3		)
Total revenue requirement increase	$	86		$	22		$	68		$	(3	)	$	14		$	(1	)

Allowed return on rate base ^(b)	8.61		%	8.62		%	8.7		%	8.46		%	8.53		%	8.35		%
Allowed ROE	11.5		%	11.5		%	11.5		%	11.3		%	11.3		%	11.3		%

Effective date of rates ^(c)	June 2015			June 2014			June 2013			June 2015			June 2014			June 2013

_____________

(a) For BGE, this excludes the increase in revenue requirement associated with dedicated facilities charges. The increases for dedicated facilities were $13 million and $3 million for 2015 and 2014, respectively. There were no dedicated facilities charges in 2013 for BGE.

(b)

Refers to the weighted average debt and equity return on transmission rate bases for ComEd and BGE. 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%. As part of the FERC-approved settlement of BGE's 2005 transmission rate case, the rate of return on common equity is 11.30%, inclusive of a 50 basis point incentive for participating in PJM.

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

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) and a 50 basis point incentive for participating in PJM (and certain additional incentive basis points on certain projects). The parties sought a reduction in the base return on equity to 8.7% and changes to the formula rate process. Under FERC rules, any revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint.

On August 21, 2014, FERC issued an order in the BGE and PHI companies' proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013.

On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regarding the base ROE of the transmission business seeking a reduction from 10.8% to 8.8%. The filing of the second complaint created a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants' requested refund effective date of December 8, 2014. On February 20, 2015, the Chief Judge issued an order consolidating the two complaint proceedings and established an Initial Decision issuance deadline of February 29, 2016.

On November 6, 2015, BGE and the PHI companies and the complainants filed a settlement with FERC covering the issues raised in the complaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM incentive adder of 50 basis points, and refunds to BGE customers of $13.7 million. The settlement also provides a moratorium on any change in the ROE until June 1, 2018. On December 16, 2015, the Presiding Administrative Law Judge submitted a Certification of the Uncontested Settlement to the FERC Commissioners. The settlement remains subject to FERC approval.

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. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit for review of the decision.

In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. The hearing only concerns new facilities approved by the PJM Board prior to February 1, 2013. As of December 31, 2015, settlement discussions are continuing.

Because a new cost allocation had been adopted for projects approved by the PJM Board on or after February 1, 2013, this latest remand only involves the cost allocation for facilities 500 kV and above approved prior to that date. 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.

ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE’s estimated commitments are as follows:



	Total		2016		2017		2018		2019		2020
ComEd	$	297	$	204	$	61	$	26	$	6	$	—
PECO	67		31		24		8		4		—
BGE	373		140		112		62		46		13

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. On January 25, 2016, the U.S. Supreme Court reversed the D.C. Circuit Court decision and remanded the matter to the D.C. Circuit Court. While we cannot predict exactly how the D.C. Circuit Court will handle the matter on remand, we do not expect there will be any significant change in how demand response resources have or will participate in and be paid by wholesale energy markets. Thus, we do not anticipate that there will be any impact to the Registrants' results of operations or cash flows based on these proceedings.

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 27, 2015, ISO-NE filed the results of its ninth capacity auction (covering the June 1, 2018 through May 31, 2019 delivery period). On June 18, 2015, the FERC accepted the results of the ninth capacity auction. On July 20, 2015, a union representing utility workers sought rehearing of that decision which the FERC denied on December 30, 2015. It is not clear whether the FERC’s order will be appealed.

On February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 31, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE filed the information on July 17, 2014, and the ISO-NE's filings became effective by operation of law pursuant to a notice issued by the secretary of FERC on September 16, 2014. Several parties sought rehearing of the secretary’s notice which was effectively denied in October 2014 and have since appealed the matter to the D.C. Circuit Court. On April 7, 2015 the D.C. Circuit Court issued an order referring the matter to a merits panel where issues raised by parties challenging the FERC decision will be heard as well as FERC's Motion to Dismiss the challenges. It is not clear whether the court will decide ultimately on the merits of the case or whether it will dismiss the case as FERC urges based on the fact that there is no action by the FERC to be considered. Nonetheless, while any change in the auction results is thought to be unlikely, Exelon and Generation cannot predict with certainty what further action the court may take concerning the results of that auction, but any court action could be material to Exelon’s and Generation's expected revenues from the capacity auction.

License Renewals (Exelon and Generation). Generation has 40-year operating licenses from the NRC for each of its nuclear units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion of the NRC’s review.

On May 29, 2013, Generation submitted applications to the NRC to extend the current operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. On November 19, 2015, the NRC approved Generation's request to extend the operating licenses of Byron Unit 1 and 2 by 20 years to 2044 and 2046, respectively. On January 27, 2016 the NRC approved Generation's request to extend the operating licenses of Braidwood Unit 1 and 2 by 20 years to 2046 and 2047, respectively.

On December 09, 2014, Generation submitted an application to the NRC to extend the current operating licenses of LaSalle Units 1 and 2, which were set to expire in 2022 and 2023, respectively.

On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Project (Muddy Run), respectively. On December 22, 2015, FERC issued a new 40-year license for Muddy Run. The license term expires on December 1, 2055. The financial impact associated with Muddy Run license commitments is estimated to be in the range of an incremental $25 million to $35 million, and includes both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects. At December 31, 2015, $22 million of direct costs associated with the licensing effort have been capitalized.

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, Generation 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. MDE indicated that it believed it did not have sufficient information to process Generation's application. As a result, Generation entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Generation has agreed to contribute up to $3.5 million to fund the additional study. Because states must act on applications under Section 401 of the CWA within one year and the sediment study would not be completed prior to January 31, 2015, Exelon withdrew its application for a water quality certification on December 4, 2014. FERC policy requires that an applicant resubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, on March 3, 2015, Generation refiled its application for a water quality certification. Exelon has agreed with MDE to withdraw and refile its application for a water quality certification as necessary pending completion of the sediment study. On August 7, 2015, US Fish and Wildlife Service (USFWS) submitted its modified fishway prescription to FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for an administrative hearing and proposed an alternative prescription to challenge USFWS’s preliminary prescription. Resolution of these issues relating to Conowingo may have a material effect on Exelon's and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

The FERC license for Conowingo expired on September 1, 2014. Under the Federal Power Act, FERC is required to issue an annual license for a facility until the new license is issued. On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does not issue a new license prior to the expiration of an annual license, the annual license will renew automatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Conowingo. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of December 31, 2015, $23 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 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 December 31, 2015 and 2014.



December 31, 2015	Exelon		ComEd		PECO		BGE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79
AMI programs	399		140		63		196
Under-recovered distribution service costs	189		189		—		—
Debt costs	47		46		1		8
Fair value of BGE long-term debt	162		—		—		—
Severance	9		—		—		9
Asset retirement obligations	108		67		22		19
MGP remediation costs	286		255		30		1
Under-recovered uncollectible accounts	52		52		—		—
Renewable energy	247		247		—		—
Energy and transmission programs	84		43		1		40
Deferred storm costs	2		—		—		2
Electric generation-related regulatory asset	20		—		—		20
Rate stabilization deferral	87		—		—		87
Energy efficiency and demand response programs	279		—		1		278
Merger integration costs	6		—		—		6
Conservation voltage reduction	3		—		—		3
Under-recovered revenue decoupling	30		—		—		30
CAP arrearage	7		—		7		—
Other	35		10		19		3
Total regulatory assets	6,824		1,113		1,617		781
Less: current portion	759		218		34		267
Total noncurrent regulatory assets	$	6,065	$	895	$	1,583	$	514



December 31, 2015	Exelon		ComEd		PECO		BGE
Regulatory liabilities
Other postretirement benefits	$	94	$	—	$	—	$	—
Nuclear decommissioning	2,577		2,172		405		—
Removal costs	1,527		1,332		—		195
Energy efficiency and demand response programs	92		52		40		—
DLC program costs	9		—		9		—
Electric distribution tax repairs	95		—		95		—
Gas distribution tax repairs	28		—		28		—
Energy and transmission programs	131		53		60		18
Over-recovered revenue decoupling	1		—		—		1
Other	16		5		2		8
Total regulatory liabilities	4,570		3,614		639		222
Less: current portion	369		155		112		38
Total noncurrent regulatory liabilities	$	4,201	$	3,459	$	527	$	184



December 31, 2014	Exelon		ComEd		PECO		BGE
Regulatory assets
Pension and other postretirement benefits	$	3,256	$	—	$	—	$	—
Deferred income taxes	1,542		64		1,400		78
AMI programs	296		91		77		128
Under-recovered distribution service costs	371		371		—		—
Debt costs	57		53		4		9
Fair value of BGE long-term debt	190		—		—		—
Severance	12		—		—		12
Asset retirement obligations	116		74		26		16
MGP remediation costs	257		219		37		1
Under-recovered uncollectible accounts	67		67		—		—
Renewable energy	207		207		—		—
Energy and transmission programs	48		33		—		15
Deferred storm costs	3		—		—		3
Electric generation-related regulatory asset	30		—		—		30
Rate stabilization deferral	160		—		—		160
Energy efficiency and demand response programs	248		—		—		248
Merger integration costs	8		—		—		8
Conservation voltage reduction	2		—		—		2
Under-recovered revenue decoupling	7		—		—		7
Other	46		22		14		7
Total regulatory assets	6,923		1,201		1,558		724
Less: current portion	847		349		29		214
Total noncurrent regulatory assets	$	6,076	$	852	$	1,529	$	510



December 31, 2014	Exelon		ComEd		PECO		BGE
Regulatory liabilities
Other postretirement benefits	$	88	$	—	$	—	$	—
Nuclear decommissioning	2,879		2,389		490		—
Removal costs	1,566		1,343		—		223
Energy efficiency and demand response programs	59		25		34		—
DLC program costs	10		—		10		—
Electric distribution tax repairs	102		—		102		—
Gas distribution tax repairs	49		—		49		—
Energy and transmission programs	84		19		58		7
Revenue subject to refund	3		3		—		—
Over-recovered revenue decoupling	12		—		—		12
Other	8		1		4		2
Total regulatory liabilities	4,860		3,780		747		244
Less: current portion	310		125		90		44
Total noncurrent regulatory liabilities	$	4,550	$	3,655	$	657	$	200

Pension and other postretirement benefits. As of December 31, 2015, Exelon had regulatory assets of $3,156 million and regulatory liabilities of $94 million related to ComEd’s and BGE’s portion of deferred costs associated with Exelon’s pension plans and ComEd’s, PECO’s and BGE’s portion of deferred costs associated with Exelon’s other postretirement benefit plans. PECO’s pension regulatory recovery is based on cash contributions and is not included in the regulatory asset (liability) balances. The regulatory asset (liability) is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses (gains) attributable to Exelon’s pension and other postretirement benefit plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE will recover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirement benefit regulatory asset balance includes a regulatory asset established at the date of the Constellation merger related to BGE’s portion of the deferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. The BGE-related regulatory asset is being amortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participants at the date of the Constellation merger. See Note 17 — Retirement Benefits for additional detail. No return is earned on Exelon’s regulatory asset.

Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded under GAAP. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects associated principally with accelerated depreciation accounted for in accordance with the ratemaking policies of the ICC, PAPUC and MDPSC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For BGE, this amount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costs pursuant to the March 2010 Health Care Reform Acts. For BGE, these additional income taxes are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. For PECO, this amount includes the impacts of electric and gas distribution repairs in the deductibility pursuant to PUC’s 2010 and 2015 rate case settlement agreements. See Note 15 — Income Taxes and Note 17 — Retirement Benefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates.

AMI programs. For ComEd, this amount represents meter costs associated with ComEd’s AMI pilot program approved in ComEd’s 2010 rate case. The recovery periods for the meter costs are through January 1, 2020. As of December 31, 2015 and December 31, 2014, ComEd had regulatory assets of $137 million and $88 million, respectively, related to accelerated depreciation costs resulting from the early retirements of non-AMI meters, which will be amortized over an average ten year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a return on the regulatory asset. For PECO, this amount represents accelerated depreciation and filing and implementation costs relating to the PAPUC-approved Smart Meter Procurement and Installation Plan as well as the return on the un-depreciated investment, taxes, and operating and maintenance expenses. The approved plan allows for recovery of filing and implementation costs incurred through December 31, 2012. In addition, the approved plan provides for recovery of program costs, which includes depreciation on new equipment placed in service, beginning in January 2011 on full and current basis, which includes interest income or expense on the under or over recovery. The approved plan also provides for recovery of accelerated depreciation on PECO’s non-AMI meter assets over a 10-year period ending December 31, 2020. Recovery of smart meter costs will be reflected in base rates effective January 1, 2016. For BGE, this amount represents smart grid pilot program costs as well as the incremental costs associated with implementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11 million were deferred in a regulatory asset, and, beginning with the MDPSC’s March 2011 rate order, is earning BGE’s most current authorized rate of return. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset for incremental costs incurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and an appropriate rate of return on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSC requires that BGE prove the cost-effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatory assets. As part of the 2015 electric and gas distribution rate case filed on November 6, 2015 and amended on January 5, 2016, BGE is seeking recovery of its smart grid initiative costs. Of BGE's requested $200 million, $140 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs by a ratio of 2.3 to 1.0, on a nominal basis. If approved by the MDPSC, the amortization of these deferred costs would begin in June 2016. BGE’s AMI regulatory asset excludes costs for non-AMI meters being replaced by AMI meters, as recovery of those costs commenced with the new rates approved and implemented with the MDPSC order in BGE's 2014 electric and gas distribution case.

Under-recovered distribution services costs. These amounts represent under (over) recoveries related to electric distribution services costs recoverable (refundable) through EIMA’s performance based formula rate tariff. Under (over) recoveries for the annual reconciliations are recoverable (refundable) over a one-year period and costs for certain one-time events, such as large storms, are recoverable over a five-year period. ComEd earns and pays a return on under and over-recovered costs, respectively. As of December 31, 2015, the regulatory asset was comprised of $142 million for the 2014 and 2015 annual reconciliations and $47 million related to significant one-time events, including $36 million in deferred storm costs and $11 million of Constellation merger and integration related costs. As of December 31, 2014, the regulatory asset was comprised of $286 million for the 2013 and 2014 annual reconciliations and $85 million related to significant one-time events, including $66 million in deferred storm costs and $19 million of Constellation merger and integration related costs. See Energy Infrastructure Modernization Act above for further details.

Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd’s, PECO’s and BGE’s recoverable losses on reacquired long-term debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding or the life of the original issuance retired. These debt costs are used in the determination of the weighted cost of capital applied to rate base in the rate-making process. ComEd and BGE are not earning a return on the recovery of these costs, while PECO is earning a return on the premium of the cost of the reacquired debt through base rates.

Fair value of BGE long-term debt. These amounts represent the regulatory asset recorded at Exelon for the difference in the fair value of the long-term debt of BGE as of the Constellation merger date based on the MDPSC practice to allow BGE to recover its debt costs through rates. Exelon is amortizing the regulatory asset and the associated fair value over the life of the underlying debt and is not earning a return on the recovery of these costs.

Severance. For BGE, these costs represent deferred severance costs associated with a 2010 workforce reduction that were deferred as a regulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. Additionally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance with the MDPSC’s orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return on the regulatory asset included in base rates.

Asset retirement obligations. These costs represent future legally required removal costs associated with existing asset retirement obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd and BGE will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have been performed. See Note 16 — Asset Retirement Obligations for additional information.

MGP remediation costs. ComEd is allowed recovery of these costs under ICC approved rates. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures. ComEd and PECO are not earning a return on the recovery of these costs. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. BGE is earning a return on this regulatory asset and these costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. The recovery period for the 10-year period that began January 2006 was extended for an additional 24 months, in accordance with the MDPSC approved 2014 electric and natural gas distribution rate case order. See Note 23 — Commitments and Contingencies for additional information.

Under recovered uncollectible accounts. These amounts represent the difference between ComEd’s annual uncollectible accounts expense and revenues collected in rates through an ICC-approved rider. The difference between net uncollectible account charge-offs and revenues collected through the rider each calendar year is recovered or refunded over a twelve-month period beginning in June of the following calendar year. ComEd does not earn a return on these under recoveries.

Renewable energy. In December 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy. Delivery under the contracts began in June 2012. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd’s cost to purchase energy at the market price and the contracted price.

Energy and transmission programs. These amounts represent under (over) recoveries related to energy and transmission costs recoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. Under (over) recoveries are recoverable (refundable) over a one-year period or less. ComEd earns a return or interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2015, ComEd's regulatory asset of $43 million included $5 million related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC-approved formula rate tariff, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2015, ComEd's regulatory liability of $53 million included $29 million related to over-recovered energy costs and $24 million associated with revenues received for renewable energy requirements. As of December 31, 2014, ComEd's regulatory asset of $33 million included $4 million related to under-recovered energy costs, $22 million associated with transmission costs recoverable through its FERC-approved formula rate tariff, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2014, ComEd's regulatory liability of $19 million included $3 million related to over-recovered energy costs and $16 million associated with revenues received for renewable energy requirements. See Transmission Formula Rate above for further details.

The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO’s GSA and PGC, respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas costs to customers. In addition, the DSP Program costs are presented on a net basis with PECO’s GSA under (over)-recovered energy costs. See additional discussion below. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2015, PECO had a regulatory liability that included $35 million related to the DSP program, $22 million related to over-recovered natural gas supply costs under the PGC and $3 million related to over-recovered electric transmission costs. As of December 31, 2014, PECO had a regulatory liability that included $39 million related to the DSP program, $3 million related the over-recovered electric transmission costs and $16 million related to over-recovered natural gas supply costs under the PGC.

DSP Program Costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO’s PAPUC-approved DSP programs for the procurement of electric supply. The filings and procurements of these DSP Programs are recoverable through the GSA over each respective term. The original DSP Program had a 29-month term that began January 1, 2011. DSP II and DSP III each have a 24-month term that began June 1, 2013 and June 1, 2015, respectively. The independent evaluator costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements. PECO is not earning a return on these costs. Certain costs included in PECO's original DSP program related to information technology improvements were recovered over a 5-year period that began January 1, 2011. PECO earns a return on the recovery of information technology costs. These costs are included within the energy and transmission programs line item.

The BGE energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to) customers under BGE’s market-based SOS program, MBR program, and FERC approved transmission rates, respectively. BGE does not earn or pay interest on under- or over-recovered costs to customers. As of December 31, 2015, BGE's regulatory asset of $40 million included $12 million associated with transmission costs recoverable through its FERC approved formula rate and $28 million related to under-recovered electric energy costs. As of December 31, 2015, BGE's regulatory liability of $18 million related to $5 million of over-recovered natural gas costs $14 million of over-recovered transmission costs, offset by $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE's regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of transmission costs recoverable through its FERC approved formula rate. As of December 31, 2014, BGE's regulatory liability of $7 million related to over-recovered natural gas supply costs.

Deferred storm costs. In the MDPSC’s March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February 2010. BGE earns a return on this regulatory asset and the recovery period was extended for an additional 25 months, in accordance with the MDPSC approved 2014 electric and natural gas distribution rate case order.

Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The portion of this regulatory asset that does not earn a regulated rate of return was $19 million as of December 31, 2015, and $28 million as of December 31, 2014. BGE will continue to amortize this amount through 2017.

Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 to January 1, 2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2015 and 2014, BGE recovered $73 million and $65 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007.

Energy efficiency and demand response programs. For ComEd, these amounts represent over recoveries related to ComEd’s ICC-approved Energy Efficiency and Demand Response Plan. ComEd refunds these over recoveries through a rider over a twelve-month period. ComEd earns a return on the capital investment incurred under the program, but does not earn or pay interest on under or over recoveries, respectively. For PECO, these amounts represent over recoveries of program costs related to both Phase I and Phase II of its PAPUC-approved EE&C Plan. PECO began recovering the costs of its Phase I and Phase II EE&C Plans through a surcharge in January 2010 and June 2013, respectively, based on projected spending under the programs. Phase I recovery continued over the life of the program, which expired on May 31, 2013 and excess funds collected began being refunded in June 2013. Phase II of the program began on June 1, 2013, and will continue over the life of the program, which will expire on May 31, 2016. Excess funds collected are required to be refunded beginning in June 2016. PECO earned a return on the capital investment incurred under Phase I of the program. PECO does not earn (pay) interest on under (over) collections. For BGE, these amounts represent under (over) recoveries related to BGE’s Smart Energy Savers Program®, which includes both MDPSC-approved demand response and energy efficiency programs. For the BGE Peak Rewards^SM demand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment. Also included in the demand response program are customer bill credits related to BGE’s Smart Energy Rewards program which began in July 2013 and are being recovered through the surcharge. Actual costs incurred in the energy efficiency program are being amortized over a 5-year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections.

Merger integration costs. These amounts represent integration costs to achieve distribution synergies related to the Constellation merger transaction. As a result of the MDPSC’s February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costs incurred during 2012 and the first quarter of 2013. Of these costs, $4 million was authorized to be amortized over a 5-year period that began in March 2013. The recovery of the remaining $4 million was deferred. In the MDPSC’s December 2013 rate order, BGE was authorized to recover the remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are being amortized over a 5-year period that began in December 2013. BGE is earning a return on this regulatory asset included in base rates.

Under (Over)-recovered electric and gas revenue decoupling. These amounts represent the electric and gas distribution costs recoverable from or (refundable) to customers under BGE’s decoupling mechanism, which does not earn a rate of return. As of December 31, 2015, BGE had a regulatory asset of $30 million related to under-recovered electric revenue decoupling and a regulatory liability of $1 million related to over-recovered natural gas revenue decoupling. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling.

CAP arrearage. These amounts represent the guaranteed recovery of previously incurred bad debt expense associated with the estimated eligible CAP accounts receivable balances under the IPAF Program as provided by the 2015 electric distribution rate case settlement. These costs are amortized as recovery is received through a combination of customer payments and rate recovery, including through future rate cases if necessary. PECO is not earning a return on this regulatory asset.

Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for the Regulatory Agreement Units that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will be sufficient to fund the associated future decommissioning costs at the time of decommissioning. Exelon is not accruing interest on these costs. See Note 16 — Asset Retirement Obligations for additional information.

Removal costs. These amounts represent funds ComEd and BGE have received from customers through depreciation rates to cover the future non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking purposes. This liability is reduced as costs are incurred.

DLC program costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement the DLC Program under PECO’s EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as a credit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaining useful life of the assets. PECO is not paying interest on these over-recovered costs.

Electric distribution tax repairs. PECO’s 2010 electric distribution rate case settlement required that the expected cash benefit from the application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year period. Credits began being reflected in customer bills on January 1, 2012. PECO's 2015 electric distribution rate case settlement requires PECO to pay interest on the unamortized balance of the tax-effected catch-up deduction beginning January 1, 2016.

Gas distribution tax repairs. PECO’s 2010 natural gas distribution rate case settlement required that the expected cash benefit from the application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits began being reflected in customer bills on January 1, 2013. No interest will be paid to customers.

Revenue subject to refund. These amounts represent refunds and associated interest ComEd owes to customers primarily related to the treatment of the post-test year accumulated depreciation issue in the 2007 Rate Case. As of December 31, 2015, and December 31, 2014, ComEd owed $0 million and $3 million, respectively.

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 is permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, and BGE do not record unbilled commodity receivables under their 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 December 31, 2015 and 2014.



As of December 31, 2015	Exelon			ComEd			PECO			BGE
Purchased receivables ^(a)	$	229		$	103		$	67		$	59
Allowance for uncollectible accounts ^(b)	(31		)	(16		)	(7		)	(8		)
Purchased receivables, net	$	198		$	87		$	60		$	51

As of December 31, 2014	Exelon			ComEd			PECO			BGE
Purchased receivables ^(a)	$	290		$	139		$	76		$	75
Allowance for uncollectible accounts ^(b)	(42		)	(21		)	(8		)	(13		)
Purchased receivables, net	$	248		$	118		$	68		$	62

_________________________

(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. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.

(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.

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

12 Months Ended

Dec. 31, 2015

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. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. Based on the outstanding shares of PHI’s common stock as of December 31, 2015, PHI shareholders would receive $6.9 billion in total cash. In addition, in connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $180 million of a class of nonvoting, nonconvertible and nontransferable preferred securities of PHI. The preferred securities are included in Other non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any.

On November 2, 2015, Exelon and PHI each filed a new Notification and Report Form with the DOJ under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act) due to the expiration of the original filing. The HSR Act waiting period expired on December 2, 2015, and the HSR Act no longer precludes completion of the merger.

To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU), the Delaware Public Service Commission (DPSC), the Maryland Public Service Commission (MDPSC) and the FERC have approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses.

On February 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregate value of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million. The March 6, 2015, order by the NJBPU approving the merger required that the consummation of the merger must take place no later than November 1, 2015 unless otherwise extended by the Board. On October 15, 2015, the NJBPU extended the November 1, 2015 date to June 30, 2016.

On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the DPSC to review the proposed merger. The settlement, which was amended on April 7, 2015, was signed and filed by Exelon, PHI, Delmarva Power & Light Company (DPL), the DPSC Staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environmental Control, the Delaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. As part of this settlement, Exelon and PHI proposed a package of benefits to DPL customers and the state of Delaware including the establishment of customer rate credits of $40 million for DPL customers in Delaware, $2 million of funding for energy efficiency programs for DPL low income customers, and $2 million of funding for workforce development. On June 2, 2015, the DPSC issued an order accepting the settlement and approving the merger between Exelon and PHI.

On March 17, 2015, Exelon and PHI announced that they had reached settlements with multiple parties in the Maryland proceeding to review the proposed merger after filing a Request for Adoption of Settlements with the MDPSC. The settlements were signed and filed by Exelon, PHI, Montgomery County, Prince George’s County, the National Consumer Law Center, National Housing Trust, the Maryland Affordable Housing Coalition, the Housing Association of Nonprofit Developers, and a consortium of recreational trail advocacy organizations led by the Mid-Atlantic Off-Road Enthusiasts. Exelon and PHI also announced a settlement with The Alliance for Solar Choice. On May 15, 2015, the MDPSC approved the merger after modifying a number of the conditions in the settlements, resulting in total rate credits of $66 million, funding for energy efficiency programs of $43.2 million, a Green Sustainability Fund of $14.4 million, 20 MWs of renewable generation development and increased penalties related to reliability commitments. On May 18, 2015, Exelon and PHI accepted and committed to fulfill the conditions.

On June 11, 2015, the Maryland Office of People’s Counsel (OPC), the Sierra Club, and the Chesapeake Climate Action Network filed Petitions for Judicial Review of the MDPSC’s approval of the merger with the Circuit Court for Queen Anne’s County. On June 23, 2015, Public Citizen, Inc. filed its Petition for Judicial Review with the Circuit Court for Queen Anne’s County. On July 10, 2015, Exelon and PHI filed a response in opposition to the Petitions for Review.

On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery and presentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 the Sierra Club and the Chesapeake Climate Action Network filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, Prince George’s County and Montgomery County filed responses opposing the motions to stay. The judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, the Chesapeake Climate Action Network (CCAN) and Public Citizen, Inc. On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special appeals, and on January 21, Sierra Club and CCAN filed a notice of appeal. In the ordinary course this appeal would be resolved no earlier than third quarter 2016.

On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of the merger, concluding that the merger as presented was not in the public interest. Exelon and PHI filed an Application for Reconsideration with the DCPSC on September 28, 2015. On October 6, 2015, Exelon, PHI, the District of Columbia Government, the Office of Peoples Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust - Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties) entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHI subsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of the Settlement Agreement and granting additional requested relief. The new package of benefits totals $78 million and includes commitments to provide relief of residential customer base rate increases of $26 million, one-time direct bill credits of $14 million, low-income energy assistance of $16 million, improved reliability, a cleaner and greener D.C. through funding energy efficiency programs and development of renewable energy, and investment in local jobs and the local economy through workforce development of $5 million. It also guarantees charitable contributions totaling $19 million over 10 years.

On October 28, 2015, the DCPSC agreed to reopen the approval application to allow for consideration of the Settlement Agreement. Since then, parties supporting and opposing the Settlement filed testimony, participated in formal hearings and, on December 23, 2015, submitted final briefs to the DCPSC. The parties now await a formal decision from the DCPSC. The Merger Agreement provides that either Exelon or PHI may terminate the Merger Agreement if the merger is not completed by October 28, 2015. Pursuant to a Letter Agreement related to the Settlement Agreement, Exelon and PHI have agreed, among other things, that they will not exercise their rights to terminate the Merger Agreement before March 4, 2016, except under limited circumstances. If the DCPSC does not approve the Settlement Agreement by March 4, 2016, either Exelon or PHI may terminate the Settlement Agreement.

The settlements reached and commission orders received to date in Delaware, Maryland and New Jersey include a “most favored nation” provision which, generally speaking, requires allocation of merger benefits proportionately across all the jurisdictions. When applying the most favored nation provision to the settlement terms and other conditions established in the merger approvals received to date, and as proposed in the Settlement Agreement filed with the DCPSC, Exelon and PHI currently estimate direct benefits of $430 million or more on a net present value basis (excluding charitable contributions and renewable generation commitments) will be provided, including rate credits, funding for energy efficiency programs and other required commitments. Exelon and PHI anticipate substantially all of such amounts will be charged to earnings at the time of merger close and will be paid by the end of 2017. An additional $53 million will be charged to earnings at the time of the merger close for charitable contributions, which are then required to be paid over a period of 10 years. Commitments to develop renewable generation, which are expected to be primarily capital in nature, will be recognized as incurred. Upon completion of the merger, the actual nature, amount, timing and financial reporting treatment for these commitments may be materially different from the current projection.

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 was also named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve all claims, which is subject to court approval. Final court approval of the proposed settlement is not anticipated until approximately 90 days after merger close. 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.

Including 2014 and through December 31, 2015, Exelon has incurred approximately $259 million of expense associated with the proposed merger. Of the total costs incurred, $121 million is primarily related to acquisition and integration costs and $138 million are for costs incurred to finance the transaction. The financing costs include $22 million of costs associated with the private exchange offer and redemption of certain Senior Unsecured Notes (see Note 14—Debt and Credit Agreements for further information on the exchange), as well as, a net loss of $64 million related to the settlement of forward-starting interest-rate swaps. These swaps were terminated in connection with the $4.2 billion issuance of debt; refer to Note 13—Derivative Financial Instruments for more information. The financing costs exclude costs to issue equity and the initial debt offering which we recorded to Exelon's Consolidated Balance Sheets.



	For the year ended,
Acquisition, Integration and Financing Costs ^(a)	2015		2014
Exelon	$	80	$	179
Generation	25		11
ComEd	10		4
PECO	5		2
BGE	5		2

___________

(a) The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statement of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense.

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 is terminated due to a failure to obtain a required regulatory approval, Exelon may be required to pay PHI a termination fee equal to $180 million through the redemption by PHI of the outstanding nonvoting preferred securities described above for no consideration other than the nominal par value of the stock, plus reimbursement of PHI's documented out-of-pocket expenses up to a maximum of $40 million.

Merger Financing

Exelon has raised cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments, through the issuance of $4.2 billion of debt (of which $3.3 billion remains after execution of the exchange offer, see Note 14—Debt and Credit Agreements for further information on the exchange), $1.15 billion of junior subordinated notes in the form of 23 million equity units, the issuance of $1.9 billion of common stock, cash proceeds of $1.8 billion from asset sales primarily at Generation (after-tax proceeds of approximately $1.4 billion) and the remaining balance from cash on hand and/or short-term borrowings available to Exelon. Exelon will have sufficient cash to fund the all-cash purchase price, acquisition and integration related costs, and merger commitments. See Note 14—Debt and Credit Agreements and Note 19—Shareholder's Equity for further information on the debt and equity issuances.

Acquisitions (Exelon and Generation)

Acquisition of Integrys Energy Services, Inc. (Exelon and Generation)

On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (IES) for a purchase price of $332 million, including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income tax purposes. The generation and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.

Consistent with the applicable accounting guidance, the fair value of the assets acquired and liabilities assumed was determined as of the acquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in the future cash flows; and future power and fuel market prices.

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



Total consideration transferred	$	332

Identifiable assets acquired and liabilities assumed
Working capital assets	$	390
Mark-to-market derivative assets	184
Unamortized energy contract assets	115
Customer relationships	50
Working capital liabilities	(196		)
Mark-to-market derivative liabilities	(57		)
Unamortized energy contract liabilities	(110		)
Deferred tax liability	(16		)
Total net identifiable assets, at fair value	$	360
Bargain purchase gain (after-tax)	$	28

The after-tax bargain purchase gain of $28 million is primarily the result of IES executing additional contract volumes between the date the acquisition agreement was signed and the closing of the transaction resulting in an increase in the fair value of the net assets acquired as of the acquisition date. The after-tax gain is included within Gain on consolidation and acquisition of businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

IES's operating revenues and net loss included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the period from November 1, 2014 to December 31, 2014 were $386 million and $(42) million, respectively. The net loss for the period from November 1, 2014 to December 31, 2014 includes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchase gain of $28 million. It is impracticable to determine the overall financial statement impact of IES for 2015 due to the integration of the business into ongoing operations. For the years ended December 31, 2015 and 2014, Exelon and Generation incurred $5 million and $7 million, respectively, of merger and integration related costs which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

Asset Divestitures (Exelon and Generation)

Including the Quail Run generating facility that was sold on January 21, 2015, Generation has sold certain generating assets with a total net book value of approximately $1.8 billion prior to consideration of asset impairments (See Note 8 — Impairment of Long-Lived Assets for further information), for total pre-tax proceeds of approximately $1.8 billion (after-tax proceeds of approximately $1.4 billion), which resulted in cumulative pre-tax gains on sale of approximately $412 million, which are included in Gain (loss) on sales of assets on Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2014. The proceeds are expected to be used primarily to finance a portion of the merger with PHI.



Station	Net Generation Capacity	Location	Operating Segment	Percent Owned
Fore River	726 MW	North Weymouth, MA	New England	100	%
West Valley	185 MW	Salt Lake City, UT	Other	100	%
Keystone	714 MW	Shelocta, PA	Mid-Atlantic	41.98	%
Conemaugh	532 MW	New Florence, PA	Mid-Atlantic	31.28	%
Safe Harbor	278 MW	Conestoga, PA	Mid-Atlantic	66.7	%
Quail Run	488 MW	Odessa, TX	ERCOT	100	%

At December 31, 2014, the assets and liabilities of the Quail Run generating facility were reported as Assets held for sale and within Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. The table below presents the major classes of assets and liabilities held for sale at December 31, 2014. Assets held for sale at December 31, 2015 are not material.



	December 31, 2014
Assets
Property, plant and equipment, net ^(a)	$	143
Inventory	4
Total assets held for sale	$	147
Liabilities
Accrued expenses	$	1
Asset retirement obligations	4
Total liabilities held for sale^(b)	$	5

_____________

(a) The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income for the year ended December 31, 2014. See Note 8 — Impairment of Long-Lived Assets for further information.

(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

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

12 Months Ended

Dec. 31, 2015

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

(Exelon and Generation)

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 26 — Related Party Transactions.

On April 1, 2014, Generation and subsidiaries of Generation 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 EDF’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 Long Island Power Authority, the Unit 2 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 or payable upon the maturity date of April 1, 2034. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDF. Unpaid principal and accrued interest on the loan was $300 million as of December 31, 2015.

Exelon, Generation, and subsidiaries of Generation, EDF and CENG 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 EDF also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF 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. Under limited circumstances, the period for exercise of the put option may be extended for 18 months. In order to exercise its option, EDF must give 60 days advance written notice to Generation stating that it is exercising its option. As of the date these financial statements were issued, EDF has not given notice to Generation that it is exercising its option.

On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity.

In addition, on April 1, 2014, Generation, EDF, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to Exelon or one of its affiliates and Exelon's assumption of the sponsorship of the employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their related trusts by Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the obligation related to pre-transfer service of employees, including 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. However, in the event that EDF exercises its rights under the Put Option, all payments not made as of the put closing date shall accelerate to be paid immediately prior to such closing date.

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 twelve months ended December 31, 2013, Generation recorded $9 million of equity in losses of unconsolidated affiliates related to its investment in CENG and $56 million 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 on April 1, 2014, there are several additional transactions included in Exelon’s and Generation’s Consolidated Financial Statements between CENG and Exelon's affiliates that are considered related party transactions to Generation. As further described in Note 26 — Related Party Transactions, EDF and Generation had a PPA with CENG under which they purchased 15% and 85%, respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs through December 31, 2014. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG not subject to other contractual agreements. Beginning April 1, 2014, CENG's sales to Generation have been eliminated in consolidation. For the years ended December 31, 2015 and 2014, Generation had sales to EDF of $488 million and $137 million, respectively. See discussion above and Note 2 — Variable Interest Entities for additional information regarding other transactions between CENG and EDF included within Exelon and Generation’s consolidated financial statements and for additional information about the Registrants VIE's.

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 noncontrolling 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 Generation's 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 were 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 could be modified for up to one year from April 1, 2014, as more information was obtained about the fair value of assets and liabilities. The principal items that have been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updated with inputs from a third party engineering firm with corresponding adjustments recorded in 2014 and the first quarter of 2015. See Note 16—Asset Retirement Obligations for discussion of the impacts of adjustments recorded during 2014 and 2015 related to updated estimates of the CENG asset retirement obligation liabilities. In the period of such revisions, these and any other material changes to the fair value assessments have resulted in adjustments to the amounts recorded upon consolidation. In addition, the asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation date have impacted 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, adjusted for the modifications discussed above:



Fair Values	Exelon and Generation
Current assets	$	499
Nuclear decommissioning trust fund	1,955
Property, plant and equipment	3,073
Nuclear fuel	482
Other assets	10
Total assets	6,019

Current liabilities	237
Asset retirement obligation	1,816
Pension and other employee benefit obligations	281
Unamortized energy contract liabilities	171
Other liabilities	114
Total liabilities	2,619
Total net assets	$	3,400

Generation also recorded the fair value of the noncontrolling interest on its Consolidated Balance Sheets of approximately $1.5 billion, net of the fair value of $152 million for certain specified additional distribution rights under the Operating Agreement. In addition, the noncontrolling interest was further reduced by the $400 million special cash distribution to EDF.

Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interest on the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’s net assets. For the years ended December 31, 2015 and 2014, Generation reduced by $18 million and $13 million, respectively, the amount of Net income attributable to noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $509 million and $218 million and CENG’s net income (loss), prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $(11) million and $407 million during the years ended December 31, 2015 and 2014, respectively.

Exelon and Generation incurred integration-related costs of $2 million and $26 million for the year ended December 31, 2015 and 2014, respectively. The costs incurred are classified primarily within Operating and maintenance expense in Exelon’s and Generation’s respective Consolidated Statements of Operations and Comprehensive Income.

Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Receivables [Abstract]

Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE)

(Exelon, Generation, ComEd, PECO and BGE)

Accounts receivable at December 31, 2015 and 2014 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:



2015	Exelon			Generation				ComEd			PECO				BGE
Unbilled customer revenues	$	1,203		$	732		^(a)	$	218		$	105			$	148
Allowance for uncollectible accounts ^(b)	(284		)	(77		)		(75		)	(83		)	^(c)	(49		)



2014	Exelon			Generation				ComEd			PECO				BGE
Unbilled customer revenues	$	1,381		$	823		^(a)	$	204		$	140			$	214
Allowance for uncollectible accounts ^(b)	(311		)	(60		)		(84		)	(100		)	^(c)	(67		)	^(d)

_________________________


(a)	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.


(b)	Includes the allowance for uncollectible accounts on customer and other accounts receivable.


(c)	Excludes the non-current allowance for uncollectible accounts of $8 million at both December 31, 2015 and 2014, related to PECO’s current installment plan receivables described below.

(d)

At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income.

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 $15 million at both December 31, 2015 and 2014. 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. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2015 and December 31, 2014 of $15 million consists of $1 million, $3 million and $11 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 December 31, 2015 and 2014 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.

Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-90	$	32,546	$	30,157
Electric—generation	1-56	25,615		22,911
Gas—transportation and distribution	5-90	3,864		3,505
Common—electric and gas	5-50	1,149		1,169
Nuclear fuel ^(a)	1-8	6,384		5,947
Construction work in progress	N/A	3,075		2,167
Other property, plant and equipment ^(b)	5-50	1,181		1,056
Total property, plant and equipment		73,814		66,912
Less: accumulated depreciation ^(c)		16,375		14,742
Property, plant and equipment, net		$	57,439	$	52,170

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $13 million and $15 million at December 31, 2015 and 2014, respectively. The original cost basis of the buildings was $52 million, and total accumulated amortization was $39 million and $37 million, as of December 31, 2015 and 2014, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at December 31, 2015 and 2014, of $7 million and $8 million, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $266 million and $242 million related to oil and gas production activities at Generation at December 31, 2015 and 2014, respectively. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $146 million and $83 million at December 31, 2015 and 2014, respectively.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively.

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



Average Service Life Percentage by Asset Category	2015		2014		2013
Electric—transmission and distribution	2.83	%	2.93	%	2.91	%
Electric—generation	3.47	%	3.50	%	3.35	%
Gas	2.17	%	2.13	%	2.06	%
Common—electric and gas	7.79	%	7.32	%	7.53	%

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015			2014
Asset Category
Electric—generation	1-56	$	25,615	19,004,000,000	$	22,911
Nuclear fuel ^(a)	1-8	6,384		4,815,000,000	5,947
Construction work in progress	N/A	2,017		1,352,000,000	1,404
Other property, plant and equipment ^(b)	5-31	466		374,000,000	378
Total property, plant and equipment		34,482			30,640
Less: accumulated depreciation ^(c)		8,639			7,612
Property, plant and equipment, net		$	25,843		$	23,028

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.

(b)

Includes buildings under capital lease with a net carrying value of $13 million and $15 million at December 31, 2015 and 2014, respectively. The original cost basis of the buildings was $52 million, and total accumulated amortization was $39 million and $37 million, as of December 31, 2015 and 2014, respectively. These balances also include capitalized acquisition, development and exploration costs of $266 million and $242 million related to oil and gas production activities at Generation at December 31, 2015 and 2014, respectively. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $146 million and $83 million at December 31, 2015 and 2014, respectively.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively.

The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.47%, 3.50% and 3.35% for the years ended December 31, 2015, 2014 and 2013, respectively.

License Renewals. Generation’s depreciation provisions are based on the estimated useful lives of its generating stations, which assume the renewal of the licenses for all nuclear generating stations (except for Oyster Creek) and the hydroelectric generating stations. As a result, the receipt of license renewals has no material impact on the Consolidated Statements of Operations and Comprehensive Income. See Note 3—Regulatory Matters for additional information regarding license renewals.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-80	$	20,576	$	18,884
Construction work in progress	N/A	572		276
Other property, plant and equipment ^{(a), (b)}	38-50	64		65
Total property, plant and equipment		21,212		19,225
Less: accumulated depreciation		3,710		3,432
Property, plant and equipment, net		$	17,502	$	15,793

_________________________


(a)	Includes buildings under capital lease with a net carrying value at December 31, 2015 and 2014 of $7 million and $8 million, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively.


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

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 3.03%, 3.05% and 2.97% for the years ended December 31, 2015, 2014 and 2013, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-65	$	7,230	$	6,886
Gas—transportation and distribution	5-70	2,206		2,039
Common—electric and gas	5-50	631		618
Construction work in progress	N/A	154		154
Other property, plant and equipment ^(a)	50	21		21
Total property, plant and equipment		10,242		9,718
Less: accumulated depreciation		3,101		2,917
Property, plant and equipment, net		$	7,141	$	6,801

_________________________


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

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



Average Service Life Percentage by Asset Category	2015		2014		2013
Electric—transmission and distribution	2.39	%	2.55	%	2.73	%
Gas	1.87	%	1.84	%	1.79	%
Common—electric and gas	5.16	%	5.16	%	6.65	%

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-90	$	6,663	$	6,339
Gas—distribution	5-90	1,951		1,761
Common—electric and gas	5-40	655		623
Construction work in progress	N/A	312		317
Other property, plant and equipment ^(a)	20	32		32
Total property, plant and equipment		9,613		9,072
Less: accumulated depreciation		3,016		2,868
Property, plant and equipment, net		$	6,597	$	6,204

_______________________


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



Average Service Life Percentage by Asset Category	2015		2014		2013
Electric—transmission and distribution	2.62	%	2.96	%	2.91	%
Gas	2.50	%	2.47	%	2.36	%
Common—electric and gas	10.35	%	9.49	%	8.45	%

See Note 1—Significant Accounting Policies for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 14—Debt and Credit Agreements for further information regarding Exelon’s, ComEd’s, and PECO’s property, plant and equipment subject to mortgage liens.

Impairment of Long-lived Assets (Exelon and Generation)

12 Months Ended

Dec. 31, 2015

Impairment or Disposal of Tangible Assets Disclosure [Abstract]

Impairment Of Long-Lived Assets (Exelon and Generation)

(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 each year, Generation updates the long-term fundamental energy prices, which includes a thorough evaluation of key assumptions including gas prices, load growth, environmental policy, plant retirements and renewable growth.

In 2015, the year over year change in fundamentals did not indicate any impairments. In 2014, the year over year change in fundamentals 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. 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 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

In 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects with market price exposure for either all or a portion of the life of the asset may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of $43 million, net of the impairment amount attributable to noncontrolling interests for certain of the projects, was recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

During 2015 and 2014, significant declines in oil and gas prices suggested that the carrying value of certain Upstream assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of various Upstream properties, primarily located in Oklahoma and Texas, were less than their respective carrying values at December 31, 2015 and 2014. As a result, pre-tax impairment charges of $5 million and $124 million were recorded for the years ended December 31, 2015 and 2014, respectively, within Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. After reflecting the impairment charges, Generation has $187 million of Upstream assets remaining on its Consolidated Balance Sheets at December 31, 2015. Further declines in commodity prices could potentially result in future impairments of the Upstream assets.

The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.

In 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon's and Generation's Consolidated Balance Sheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset's carrying value exceeds its estimated fair value less costs to sell. Long-lived assets with a carrying amount of approximately $1 billion were written down to their fair value of $556 million and a pre-tax impairment charge of $450 million was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4—Mergers, Acquisitions, and Dispositions for further information on asset sales.

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 during 2013 to cancel certain projects. 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. Additionally, the market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Exelon and Generation recorded a pre-tax charge to Operating and maintenance expense and Interest expense within their Statements of Operations and Comprehensive Income of approximately $111 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 15—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 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 down the net investment in the CPS long-term lease of $336 million in Investments in Exelon's Consolidated Balance Sheets in 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income in 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 quarters of 2015 and 2014, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other than temporary declines given increases in estimated long-term operating and maintenance costs in the 2015 annual review and reduced long-term energy and capacity price expectations in the 2014 annual review. As a result, Exelon recorded $24 million pre-tax impairment charges in both 2015 and 2014 for these stations. These impairment charges were recorded within Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the Consolidated Statements 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. Through December 31, 2015, no events have occurred that would require Exelon to review the estimated residual values of its direct financing lease investments subsequent to the review performed in the second quarter of 2015.

At December 31, 2015 and 2014, the components of the net investment in long-term leases were as follows:



	December 31, 2015		December 31, 2014
Estimated residual value of leased assets	$	639	$	685
Less: unearned income	287		324
Net investment in long-term leases	$	352	$	361

Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Public Utilities, Property, Plant and Equipment [Abstract]

Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)

(Exelon, Generation, PECO and BGE)

Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2015 and 2014 were as follows:



	Nuclear Generation												Fossil Fuel Generation			Transmission					Other
	Quad Cities			Peach Bottom			Salem ^(a)			Nine Mile Point Unit 2^(f)			Wyman			PA ^(b)		DE/NJ ^(c)			Other ^(d)
Operator	Generation			Generation			PSEG Nuclear			Generation			FP&L			First Energy		PSEG
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	5.89		%	Various		42.55		%	44.24		%
Exelon’s share at December 31, 2015:
Plant ^(e)	$	1,035		$	1,345		$	566		$	756		$	3		$	15	$	65		$	1
Accumulated depreciation ^(e)	309			368			167			42			3			7		35			1
Construction work in progress	11			18			40			56			—			—		—			—
Exelon’s share at December 31, 2014:
Plant ^(e)	$	995		$	1,095		$	531		$	676		$	3		$	14	$	64		$	2
Accumulated depreciation ^(e)	266			343			150			14			3			7		34			1
Construction work in progress	15			133			29			48			—			—		—			—

________________________


(a)	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2015 and 2014.


(b)	PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.


(c)	PECO owns a 42.55% share in 131 miles of 500kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.


(d)	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.


(e)	Excludes asset retirement costs.

(f)

On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet, and as of that date, CENG’s operations are consolidated into Generation’s financial statements. As of December 31, 2013, Generation’s ownership interest in CENG, including Nine Mile Point, was treated as an equity method investment, and thus did not represent an undivided Interest. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

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

Intangible Assets (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets (Exelon, Generation, ComEd, PECO and BGE)

(Exelon, Generation, ComEd and PECO)

Goodwill

Exelon’s, Generation's and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2015 and 2014 were as follows:



	ComEd						Generation				Exelon
	Gross Amount ^(a)		Accumulated Impairment Losses		Carrying Amount		Gross Amount		Carrying Amount		Gross Amount		Accumulated Impairment Losses		Carrying Amount
Balance, January 1, 2014	$	4,608	$	1,983	$	2,625	$	—	$	—	$	4,608	$	1,983	$	2,625
Goodwill from business combination	—		—		—		47		47		47		—		47
Balance, December 31, 2014	4,608		1,983		2,625		47		47		4,655		1,983		2,672
Impairment losses	—		—		—		—		—		—		—		—
Balance, December 31, 2015	$	4,608	$	1,983	$	2,625	$	47	$	47	$	4,655	$	1,983	$	2,672

_______________________


(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. Under the authoritative guidance for goodwill, a reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment for its combined business. There is no level below this operating segment for which operating results are regularly reviewed by segment management. Therefore, ComEd’s operating segment is considered its only reporting unit.

Entities assessing goodwill for impairment have the option of first performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step fair value based impairment test). If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step fair value based impairment test is required. Otherwise, no further testing is required.

If an entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount, a quantitative two-step, fair value based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Any goodwill impairment charge at ComEd will affect Exelon’s consolidated results of operations.

ComEd’s valuation approach is based on a market participant view, pursuant to authoritative guidance for fair value measurement, and utilizes a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or “best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd’s business and the fair value of debt. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon’s enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiple analysis.

2015 and 2014 Goodwill Impairment Assessment. Pursuant to authoritative guidance, ComEd is required to test its goodwill for impairment annually and more frequently if an event occurs or circumstances change that suggest an impairment is more likely than not. ComEd performs its assessment as of November 1, of each year. For its 2015 and 2014 annual goodwill impairment assessments, ComEd qualitatively determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform quantitative assessments. As part of its qualitative assessments, ComEd evaluated, among other things, management’s best estimate of projected operating and capital cash flows for ComEd’s business, as well as, changes in certain market conditions, including the discount rate and regulated utility peer company EBITDA multiples, while also considering the passing margin from its last quantitative assessment performed as of November 1, 2013.

Other Intangible Assets

Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2015:



	Weighted Average Amortization Years ^(k)										Estimated amortization expense
	Weighted Average Amortization Years ^(k)	Gross			Accumulated Amortization			Net			2016			2017			2018			2019			2020
Exelon
Software License Agreement ^(a)	10.0	$	95		$	(6	)	$	89		$	10		$	10		$	10		$	10		$	10
Generation
Unamortized Energy Contracts ^(b)
Exelon Wind ^(c)	18.0	224			(69		)	155			14			14			14			14			10
Antelope Valley^(d)	25.0	190			(20		)	170			8			8			8			8			8
Constellation ^(e)	1.5	1,499			(1,473		)	26			(33		)	(21		)	11			8			10
CENG ^(f)	1.7	(97		)	48			(49		)	(11		)	(15		)	(18		)	(15		)	(8		)
Integrys ^(g)	2.4	5			2			7			5			1			1			—			—
Customer Relationships ^(h)
Constellation ^(e)	12.4	214			(76		)	138			18			18			18			17			17
Integrys ^(g)	10.0	50			(6		)	44			5			5			5			5			5
Trade Names
Constellation ^(e)	10.0	243			(103		)	140			23			23			23			23			23
ComEd
Chicago settlement—1999 agreement ⁽ⁱ⁾	21.8	100			(83		)	17			3			3			3			4			4
Chicago settlement—2003 agreement ^(j)	17.9	62			(44		)	18			4			4			4			3			3
Total intangible assets		$	2,585		$	(1,830	)	$	755		$	46		$	50		$	79		$	77		$	82

_________________________


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

(b)

Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $44 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $3 million, $0 million, $2 million, $3 million and $4 million for 2016, 2017, 2018, 2019 and 2020, respectively.


(c)	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.


(d)	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 242 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.


(e)	On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.


(f)	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.


(g)	See Note 4—Mergers, Acquisitions, and Dispositions for additional information.


(h)	Excludes $12 million of other miscellaneous customer relationships that have been acquired. The estimated amortization for these miscellaneous customer relationships is $1 million in each of the years from 2016 to 2020.

(i)

In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.

(j)

In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago’s behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in Other deferred credits and other liabilities, and other long-term liabilities on Exelon's and ComEd's Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.


(k)	Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2015, 2014 and 2013:



For the Year Ended December 31,	Exelon ^(a)		Generation ^(a)		ComEd
2015	$	76	$	69	$	7
2014	179		179		7
2013	478		550		7

_________________________

(a) At Exelon, amortization of unamortized energy contracts totaling $22 million, $135 million and $430 million for the years ended December 31, 2015, 2014 and 2013, respectively, was recorded in Operating revenues or Purchase power and fuel expense within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $22 million, $135 million and $507 million for the years ended December 31, 2015, 2014 and 2013, respectively, was recorded in Operating revenues or Purchase power and fuel expense within Generation’s Consolidated Statement of Operations and Comprehensive Income

Acquired Intangible Assets

Accounting guidance for business combinations requires the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.

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

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

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

Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, ComEd and PECO).

Exelon’s, Generation’s, ComEd’s and PECO’s other intangible assets, included in Other current assets and Other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon, Generation and ComEd) and AECs (Exelon and PECO). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer. As of December 31, 2015, and 2014, PECO had current AECs of $2 million and $13 million, respectively. PECO had no noncurrent AECs as of December 31, 2015 and 2014. As of December 31, 2015, and 2014, Generation had current RECs of $251 million and $191 million, respectively, and $56 million and $44 million of noncurrent REC's, respectively. As of December 31, 2015 and 2014, ComEd had current RECs of $5 million and $4 million, respectively. ComEd had no noncurrent RECs as of December 31, 2015 and 2014. See Note 3—Regulatory Matters and Note 23—Commitments and Contingencies for additional information on RECs and AECs.

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

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

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

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

(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 December 31, 2015 and 2014:

Exelon



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	536	$	3	$	533	$	—	$	536	$	463	$	463
Long-term debt (including amounts due within one year) ^(a)	25,145		931		23,644		1,349		25,924		21,014		22,936
Long-term debt to financing trusts ^(b)	641		—		—		673		673		641		648
SNF obligation	1,021		—		818		—		818		1,021		833

Generation



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	29	$	—	$	29	$	—	$	29	$	36	$	36
Long-term debt (including amounts due within one year) ^(a)	8,959		—		7,767		1,349		9,116		8,196		8,822
SNF obligation	1,021		—		818		—		818		1,021		833

ComEd



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	294	$	—	$	294	$	—	$	294	$	304	$	304
Long-term debt (including amounts due within one year) ^(a)	6,509		—		7,069		—		7,069		5,925		6,788
Long-term debt to financing trusts ^(b)	205		—		—		213		213		205		213

PECO



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year) ^(a)	$	2,580	$	—	$	2,786	$	—	$	2,786	$	2,232	$	2,537
Long-term debt to financing trusts	184		—		—		195		195		184		199

BGE



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	213	$	3	$	210	$	—	$	213	$	123	$	123
Long-term debt (including amounts due within one year) ^(a)	1,858		—		2,044		—		2,044		1,932		2,178
Long-term debt to financing trusts ^(b)	252		—		—		264		264		252		236

_____________________


(a)	Includes unamortized debt issuance costs of $180 million, $70 million, $38 million, $15 million and $9 million for Exelon, Generation, ComEd, PECO and BGE, respectively, at December 31, 2015 and $150 million, $70 million, $33 million, $14 million and $10 million at December 31, 2014.


(b)	Includes unamortized debt issuance costs of $7 million, $1 million and $6 million for Exelon, ComEd and BGE, respectively, at both December 31, 2015 and 2014.

Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1), short-term borrowings (Level 2) and third party financing (Level 3). 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 Exelon's equity units (Level 1) are valued based on publicly traded securities issued by Exelon.

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

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 liquidate as of the reporting date.


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


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

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. 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 year ended December 31, 2015 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.

Generation and Exelon

The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2015 and 2014:



	Generation								Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents ^(a)	$	104	$	—	$	—	$	104	$	5,766	$	—	$	—	$	5,766
Nuclear decommissioning trust fund investments
Cash equivalents ^(b)	219		92		—		311		219		92		—		311



	Generation									Exelon
As of December 31, 2015	Level 1			Level 2		Level 3		Total		Level 1			Level 2			Level 3			Total
Equities	3,008			1,894		—		4,902		3,008			1,894			—			4,902
Fixed income
Corporate debt	—			1,824		242		2,066		—			1,824			242			2,066
U.S. Treasury and agencies	1,323			15		—		1,338		1,323			15			—			1,338
Foreign governments	—			61		—		61		—			61			—			61
State and municipal debt	—			326		—		326		—			326			—			326
Other ^(c)	—			537		—		537		—		—	537		—	—		—	537
Fixed income subtotal	1,323			2,763		242		4,328		1,323			2,763			242			4,328
Middle market lending	—			—		428		428		—			—			428			428
Private equity	—			—		125		125		—			—			125			125
Real estate	—			—		35		35		—		—	—		—	35			35
Other	—			216		—		216		—			216			—			216
Nuclear decommissioning trust fund investments subtotal ^(d)	4,550			4,965		830		10,345		4,550			4,965			830			10,345
Pledged assets for Zion Station decommissioning
Cash equivalents	—			17		—		17		—			17			—			17
Equities	1			5		—		6		1			5			—			6
Fixed income
U.S. Treasury and agencies	6			2		—		8		6			2			—			8
Corporate debt	—			46		—		46		—			46			—			46
Other	—			1		—		1		—			1			—			1
Fixed income subtotal	6			49		—		55		6			49			—			55
Middle market lending	—			—		127		127		—			—			127			127
Pledged assets for Zion Station decommissioning subtotal ^(e)	7			71		127		205		7			71			127			205
Rabbi trust investments in mutual funds ^(f)	17		—	—		—		17		48			—			—			48
Commodity derivative assets
Economic hedges	1,922			3,467		1,707		7,096		1,922			3,467			1,707			7,096
Proprietary trading	36			64		30		130		36			64			30			130
Effect of netting and allocation of collateral ^(g)	(1,964	)		(2,629	)	(564	)	(5,157	)	(1,964	)		(2,629	)		(564	)		(5,157	)
Commodity derivative assets subtotal	(6	)		902		1,173		2,069		(6	)		902			1,173			2,069
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—		—		—		—			25			—			25
Economic hedges	—			20		—		20		—			20			—			20
Proprietary trading	10			5		—		15		10			5			—			15
Effect of netting and allocation of collateral	(3	)		(3	)	—		(6	)	(3	)		(3	)		—			(6	)
Interest rate and foreign currency derivative assets subtotal	7			22		—		29		7			47			—			54
Other investments	—			—		33		33		—			—			33			33
Total assets	4,679			5,960		2,163		12,802		10,372			5,985			2,163			18,520
Liabilities
Commodity derivative liabilities
Economic hedges	(2,382	)		(3,348	)	(850	)	(6,580	)	(2,382	)		(3,348	)		(1,097	)		(6,827	)
Proprietary trading	(33	)		(57	)	(37	)	(127	)	(33	)		(57	)		(37	)		(127	)
Effect of netting and allocation of collateral ^(g)	2,440			3,186		765		6,391		2,440			3,186			765			6,391
Commodity derivative liabilities subtotal	25			(219	)	(122	)	(316	)	25			(219	)		(369	)		(563	)
Interest rate and foreign currency derivative liabilities								—											—
Derivatives designated as hedging instruments	—			(16	)	—		(16	)	—			(16	)		—			(16	)
Economic hedges	—			(3	)	—		(3	)	—			(3	)		—			(3	)
Proprietary trading	(12	)		—		—		(12	)	(12	)		—			—			(12	)
Effect of netting and allocation of collateral	12			3		—		15		12			3			—			15



	Generation											Exelon
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Interest rate and foreign currency derivative liabilities subtotal	—		(16		)	—			(16		)	—		(16		)	—			(16		)
Deferred compensation obligation	—		(30		)	—			(30		)	—		(99		)	—			(99		)
Total liabilities	25		(265		)	(122		)	(362		)	25		(334		)	(369		)	(678		)
Total net assets	$	4,704	$	5,695		$	2,041		$	12,440		$	10,397	$	5,651		$	1,794		$	17,842



	Generation												Exelon
As of December 31, 2014	Level 1			Level 2			Level 3			Total			Level 1				Level 2				Level 3				Total
Assets
Cash equivalents ^(a)	$	405		$	—		$	—		$	405		$	1,119			$	—			$	—			$	1,119
Nuclear decommissioning trust fund investments
Cash equivalents ^(b)	208			37			—			245			208				37				—				245
Equities	3,035			2,207			—			5,242			3,035				2,207				—				5,242
Fixed income
Corporate debt	—			2,023			239			2,262			—				2,023				239				2,262
U.S. Treasury and agencies	996			—			—			996			996				—				—				996
Foreign governments	—			95			—			95			—				95				—				95
State and municipal debt	—			438			—			438			—				438				—				438
Other	—			511			—			511			—				511				—				511
Fixed income subtotal	996			3,067			239			4,302			996				3,067				239				4,302
Middle market lending	—			—			366			366			—				—				366				366
Private equity	—			—			83			83			—				—				83				83
Real estate	—			—			3			3			—			—	—			—	3				3
Other ^(c)	—			301			—			301			—				301				—				301
Nuclear decommissioning trust fund investments subtotal ^(d)	4,239			5,612			691			10,542			4,239				5,612				691				10,542
Pledged assets for Zion Station decommissioning
Cash equivalents	—			15			—			15			—				15				—				15
Equities	6			1			—			7			6				1				—				7
Fixed income
U.S. Treasury and agencies	5			3			—			8			5				3				—				8
Corporate debt	—			89			—			89			—				89				—				89
State and municipal debt	—			10			—			10			—				10				—				10
Other	—			3			—			3			—			—	3			—	—			—	3
Fixed income subtotal	5			105			—			110			5				105				—				110
Middle market lending	—			—			184			184			—				—				184				184
Pledged assets for Zion Station decommissioning subtotal ^(e)	11			121			184			316			11				121				184				316
Rabbi trust investments ^(f)
Cash equivalents	—			—			—			—			1				—				—				1
Mutual funds	16			—			—			16			46				—				—				46
Rabbi trust investments subtotal	16			—			—			16			47				—				—				47
Commodity derivative assets										—															—
Economic hedges	1,667			3,465			1,681			6,813			1,667				3,465				1,681				6,813
Proprietary trading	201			284			27			512			201				284				27				512
Effect of netting and allocation of collateral ^(g)	(1,982		)	(2,757		)	(557		)	(5,296		)	(1,982		)		(2,757		)		(557		)		(5,296		)
Commodity derivative assets subtotal	(114		)	992			1,151			2,029			(114		)		992				1,151				2,029
Interest rate and foreign currency derivative assets										—															—
Derivatives designated as hedging instruments	—			8			—			8			—				31				—				31
Economic hedges	—			12			—			12			—				13				—				13



	Generation												Exelon
As of December 31, 2014	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Proprietary trading	18			9			—			27			18			9			—			27
Effect of netting and allocation of collateral	(17		)	(12		)	—			(29		)	(17		)	(31		)	—			(48		)
Interest rate and foreign currency derivative assets subtotal	1			17			—			18			1			22			—			23
Other investments	—			—			3			3			2			—			3			5
Total assets	4,558			6,742			2,029			13,329			5,305			6,747			2,029			14,081
Liabilities
Commodity derivative liabilities
Economic hedges	(2,241		)	(3,458		)	(788		)	(6,487		)	(2,241		)	(3,458		)	(995		)	(6,694		)
Proprietary trading	(195		)	(295		)	(42		)	(532		)	(195		)	(295		)	(42		)	(532		)
Effect of netting and allocation of collateral ^(g)	2,416			3,557			729			6,702			2,416			3,557			729			6,702
Commodity derivative liabilities subtotal	(20		)	(196		)	(101		)	(317		)	(20		)	(196		)	(308		)	(524		)
Interest rate and foreign currency derivative liabilities										—												—
Derivatives designated as hedging instruments	—			(12		)	—			(12		)	—			(41		)	—			(41		)
Economic hedges	—			(2		)	—			(2		)	—			(103		)	—			(103		)
Proprietary trading	(14		)	(9		)	—			(23		)	(14		)	(9		)	—			(23		)
Effect of netting and allocation of collateral	25			10			—			35			25			29			—			54
Interest rate and foreign currency derivative liabilities subtotal	11			(13		)	—			(2		)	11			(124		)	—			(113		)
Deferred compensation obligation	—			(31		)	—			(31		)	—			(107		)	—			(107		)
Total liabilities	(9		)	(240		)	(101		)	(350		)	(9		)	(427		)	(308		)	(744		)
Total net assets	$	4,549		$	6,502		$	1,928		$	12,979		$	5,296		$	6,320		$	1,721		$	13,337

_________________________


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


(b)	Includes $52 million and $43 million of cash received from outstanding repurchase agreements at December 31, 2015 and 2014, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $(8) million and $(10) million, which have a total notional amount of $1,236 million and $794 million at December 31, 2015 and 2014, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $(3) million and $(5) million at December 31, 2015 and 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.


(e)	Excludes net assets of $1 million and $3 million at December 31, 2015 and 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.


(f)	Excludes $36 million and $35 million of cash surrender value of life insurance investment at December 31, 2015 and 2014, respectively, at Exelon Consolidated. Excludes $13 million and $11 million of cash surrender value of life insurance investment at December 31, 2015 and 2014, respectively, at Generation.

(g)

Collateral posted to/(received from) counterparties totaled $476 million, $557 million and $201 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2015. Collateral posted to/(received from) counterparties totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014.

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value on the utility Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2015 and 2014:



	ComEd											PECO										BGE
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments in mutual funds ^(a)	—		—			—			—			8		—			—		8			4		—			—		4
Total assets	29		—			—			29			279		—			—		279			29		—			—		29
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(12		)	—		(12		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities ^(b)	—		—			(247		)	(247		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(247		)	(255		)	—		(12		)	—		(12		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	29	$	(8	)	$	(247	)	$	(226	)	$	279	$	(12	)	$	—	$	267		$	29	$	(4	)	$	—	$	25



	ComEd											PECO										BGE
As of December 31, 2014	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	25	$	—		$	—		$	25		$	12	$	—		$	—	$	12		$	103	$	—		$	—	$	103
Rabbi trust investments in mutual funds ^(a)	—		—			—			—			9		—			—		9			5		—			—		5
Total assets	25		—			—			25			21		—			—		21			108		—			—		108
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(15		)	—		(15		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities ^(b)	—		—			(207		)	(207		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(207		)	(215		)	—		(15		)	—		(15		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	25	$	(8	)	$	(207	)	$	(190	)	$	21	$	(15	)	$	—	$	6		$	108	$	(5	)	$	—	$	103

_________________________


(a)	At PECO, excludes $12 million and $14 million of the cash surrender value of life insurance investments at December 31, 2015 and 2014, respectively.


(b)	The Level 3 balance includes the current and noncurrent liability of $23 million and $224 million, respectively, at December 31, 2015, and $20 million and $187 million, respectively, at December 31, 2014, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2015 and 2014:



	Generation																ComEd						Exelon
For The Year Ended December 31, 2015	Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments			Total Generation			Mark-to-Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of January 1, 2015	$	691		$	184		$	1,050			$	3		$	1,928		$	(207	)	$	—		$	1,721
Total realized / unrealized gains (losses)
Included in net income	4			—			22			^(a)	1			27			—			—			27
Included in noncurrent payables to affiliates	23			—			—				—			23			—			(23		)	—
Included in payable for Zion Station decommissioning	—			(2		)	—				—			(2		)	—			—			(2		)
Included in regulatory assets/liabilities	—			—			—				—			—			(40		)	23			(17		)
Change in collateral	—			—			29				—			29			—			—			29
Purchases, sales, issuances and settlements
Purchases	226			20			144				30			420			—			—			420
Sales	(8		)	(75		)	(25		)		—			(108		)	—			—			(108		)
Settlements	(106		)	—			—				—			(106		)	—			—			(106		)
Transfers into Level 3	4			—			80				—			84			—			—			84
Transfers out of Level 3	(4		)	—			(249		)		(1		)	(254		)	—			—			(254		)
Balance as of December 31, 2015	$	830		$	127		$	1,051			$	33		$	2,041		$	(247	)	$	—		$	1,794
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2015	$	4		$	—		$	856			$	—		$	860		$	—		$	—		$	860



	Generation																ComEd						Exelon
For The Year Ended December 31, 2014	Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives ^(d)				Other Investments			Total Generation			Mark-to-Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of January 1, 2014	$	350		$	112		$	465			$	15		$	942		$	(193	)	$	—		$	749
Total realized / unrealized gains (losses)
Included in net income	6			—			526			^(a)	—			532			—			—			532
Included in other comprehensive income	—			—			—				—			—			—			—			—
Included in noncurrent payables to affiliates	14			—			—				—			14			—			(14		)	—
Included in payable for Zion Station decommissioning	—			2			—				—			2			—			—			2
Included in regulatory assets/liabilities	—			—			—				—			—			(14		)	14			—
Change in collateral	—			—			198				—			198			—			—			198
Purchases, sales, issuances and settlements
Purchases	400			120			76			^(c)	2			598			—			—			598
Sales	(15		)	(50		)	(7		)		(8		)	(80		)	—			—			(80		)
Settlements	(64		)	—			—				—			(64		)	—			—			(64		)
Transfers into Level 3	—			—			(7		)		—			(7		)	—			—			(7		)
Transfers out of Level 3	—			—			(201		)		(6		)	(207		)	—			—			(207		)
Balance as of December 31, 2014	$	691		$	184		$	1,050			$	3		$	1,928		$	(207	)	$	—		$	1,721
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2014	$	4		$	—		$	640			$	—		$	644		$	—		$	—		$	644

_________________________


(a)	Includes a reduction for the reclassification of $834 million and $114 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2015 and 2014, respectively.

(b)

Includes $55 million of decreases in fair value and an increase for realized losses due to settlements of $(15) million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2015. Includes $13 million of decreases in fair value and a reduction for realized gains due to settlements of $1 million for the year ended December 31, 2014.


(c)	Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition.

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2015 and 2014:



	Generation							Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net ^(a)		Operating Revenues		Purchased Power and Fuel			Other, net ^(a)
Total gains (losses) included in net income for the year ended December 31, 2015	$	67	$	(45	)	$	4	$	67	$	(45	)	$	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2015	$	858	$	(2	)	$	4	$	858	$	(2	)	$	4



	Generation							Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net ^(a)		Operating Revenues		Purchased Power and Fuel			Other, net ^(a)
Total gains (losses) included in net income for the year ended December 31, 2014	$	614	$	(88	)	$	6	$	614	$	(88	)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014	$	663	$	(23	)	$	4	$	663	$	(23	)	$	4

_________________________


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

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 and mutual funds, which are included in Equities, Fixed Income and Other. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

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

Equity, balanced and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the fund administrators value the funds using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the underlying securities. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions, and, as a result are categorized as Level 2.

Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2.

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in 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.

Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as,leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a practical expedient. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, private equity and real estate investments have been categorized as Level 3.

As of December 31, 2015, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $266 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2015. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2015, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 16—Asset Retirement Obligations for further discussion on the NDT fund investments.

Rabbi Trust Investments (Exelon, Generation, 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 Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of mutual funds and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, which is provided by a third party. The cash surrender value inputs are not observable.

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 13—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 underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

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 executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.

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

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.91 and $0.27 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 7A.—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 13—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 December 31,2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Generation) ^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11	-	$88	^(d)
					Forward gas price	$1.18	-	$8.95	^(d)
				Option Model	Volatility percentage	5%	-	152%
Mark-to-market derivatives—Proprietary trading (Generation) ^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13	-	$78	^(d)
Mark-to-market derivatives (ComEd)	$	(247	)	Discounted Cash Flow	Forward heat rate ^(b)	9x	-	10x
					Marketability reserve	3.5%	-	7%
					Renewable factor	87%	-	128%

_________________________


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


(b)	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.


(c)	The fair values do not include cash collateral posted on level three positions of $201 million as of December 31, 2015.


(d)	Unlike the previous year, the New England region was not a significant driver for the upper end of the ranges for power and gas as of December 31, 2015.



Type of trade	Fair Value at December 31, 2014			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Generation) ^(a)(c)	$	893		Discounted Cash Flow	Forward power price	$15	-	$120	^(d)
					Forward gas price	$1.52	-	$14.02	^(d)
				Option Model	Volatility percentage	8%	-	257%
Mark-to-market derivatives— Proprietary trading (Generation) ^(a)(c)	$	(15	)	Discounted Cash Flow	Forward power price	$15	-	$117	^(d)
Mark-to-market derivatives (ComEd)	$	(207	)	Discounted Cash Flow	Forward heat rate ^(b)	8x	-	9x
					Marketability reserve	3.5%	-	8%
					Renewable factor	86%	-	126%

__________________________


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


(b)	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.


(c)	The fair values do not include cash collateral posted on level three positions of $172 million as of December 31, 2014


(d)	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 $97 and $8.14, respectively and would be approximately $76 for power proprietary trading.

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, real estate 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.

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

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

12 Months Ended

Dec. 31, 2015

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

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

The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange rate 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 Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and 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, 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 Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivative economic hedges related to 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 23—Commitments and Contingencies. 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 December 31, 2015, the proportion of expected generation hedged for the major reportable segments was 90%-93%, 60%-63% and 28%-31% for 2016, 2017, and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. 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 reductions 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 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 3—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 2015 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 2015 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 7,310 GWh, 10,571 GWh and 8,762 GWh for the years ended December 31, 2015, 2014 and 2013, 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 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 December 31, 2015, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $738 million of notional amounts of floating-to-fixed hedges outstanding. 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 an approximately $6 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2015. 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 exchange hedge balances as of December 31, 2015:



	Generation															Other								Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments		Economic Hedges		Collateral and Netting^(b)		Subtotal		Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	10		$	(5	)	$	15		$	—	$	—	$	—	$	—	$	15
Mark-to-market derivative assets (noncurrent assets)	—			10			5			(1		)	14			25		—		—		25		39
Total mark-to-market derivative assets	—			20			15			(6		)	29			25		—		—		25		54
Mark-to-market derivative liabilities (current liabilities)	(8		)	(2		)	(9		)	11			(8		)	—		—		—		—		(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(8		)	(1		)	(3		)	4			(8		)	—		—		—		—		(8		)
Total mark-to-market derivative liabilities	(16		)	(3		)	(12		)	15			(16		)	—		—		—		—		(16		)
Total mark-to-market derivative net assets (liabilities)	$	(16	)	$	17		$	3		$	9		$	13		$	25	$	—	$	—	$	25	$	38

_________________________

(a)

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.

(b)

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 accrued interest, 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.

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 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			Economic Hedges			Collateral and Netting^(b)			Subtotal			Total
Mark-to-market derivative assets (current assets)	$	7		$	7		$	20		$	(22	)	$	12		$	3		$	—		$	—		$	3		$	15
Mark-to-market derivative assets (noncurrent assets)	1			5			7			(7		)	6			20			1			(19		)	$	2		$	8
Total mark-to-market derivative assets	8			12			27			(29		)	18			23			1			(19		)	5			23
Mark-to-market derivative liabilities (current liabilities)	(8		)	(2		)	(14		)	25			1			—			—			—			—			1
Mark-to-market derivative liabilities (noncurrent liabilities)	(4		)	—			(9		)	10			(3		)	(29		)	(101		)	19			(111		)	(114		)
Total mark-to-market derivative liabilities	(12		)	(2		)	(23		)	35			(2		)	(29		)	(101		)	19			(111		)	(113		)
Total mark-to-market derivative net assets (liabilities)	$	(4	)	$	10		$	4		$	6		$	16		$	(6	)	$	(100	)	$	—		$	(106	)	$	(90	)

_________________________

(a)

(b)

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:



		Year Ended December 31,
	Income Statement Location	2015			2014			2013			2015			2014		2013
	Income Statement Location	Gain (Loss) on Swaps									Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(1	)	$	(16	)	$	(15	)	$	—		$	2	$	(6	)
Exelon	Interest expense	$	2		$	3		$	(24	)	$	(9	)	$	15	$	(3	)

______________________


(a)	For the years ended December 31, 2015 and 2014, the loss on Generation swaps included $(1) million and $(17) million realized in earnings, respectively, with an immaterial amount and $4 million excluded from hedge effectiveness testing, respectively.

At December 31, 2015, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $25 million. At December 31, 2014, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. During the years ended December 31, 2015 and 2014, the impact on the results of operations, as a result of the ineffectiveness from fair value hedges, was a $17 million gain and $18 million gain, respectively.

Cash Flow Hedges. During 2014, Exelon entered into $400 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated refinancing of existing debt. The swaps are designated as cash flow hedges. In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated these swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.

During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $500 million as of December 31, 2015 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2015, the subsidiary had a $12 million derivative liability related to the swap.

During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $189 million as of December 31, 2015 and expire in 2020. The swaps are designated as cash flow hedges. At December 31, 2015, the subsidiary had a $2 million derivative liability related to the swaps.

During the years ended December 31, 2015 and 2014, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships were immaterial.

Economic Hedges. During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and Credit Agreements for additional information regarding the financing. The swaps have a total notional amount of $25 million as of December 31, 2015 and expire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. During the first quarter of 2015, the swaps were de-designated as the forecasted transaction was no longer probable of occurring. All future changes in fair value are reflected in Interest expense. At December 31, 2015, the subsidiary had a $2 million derivative liability related to these swaps, which included an immaterial amount that was amortized to Interest expense after de-designation.

During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and Credit Agreements for additional information regarding the financing. The swap has a notional amount of $24 million as of December 31, 2015, and expires in 2030. This swap was designated as a cash flow hedge. During the first quarter of 2015, the swaps were de-designated as the forecasted transaction was no longer probable of occurring. All future changes in fair value are reflected in Interest expense. At December 31, 2015, the derivative asset related to the swap was immaterial.

During the second quarter 2015, upon the issuance of debt, Exelon terminated $2,400 million of floating-to-fixed forward starting interest rate swaps. As a result of the termination of the swaps, Exelon realized a $64 million loss during the second quarter of 2015.

At December 31, 2015, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $30 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. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral including initial margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2015 and 2014, $3 million and $8 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, 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 December 31, 2015:



	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting ^(a)			Subtotal ^(b)			Economic Hedges ^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,236		$	108		$	(3,994	)	$	1,350		$	—		$	1,350
Mark-to-market derivative assets (noncurrent assets)	1,860			22			(1,163		)	719			—			719
Total mark-to-market derivative assets	7,096			130			(5,157		)	2,069			—			2,069
Mark-to-market derivative liabilities (current liabilities)	(4,907		)	(94		)	4,827			(174		)	(23		)	(197		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,673		)	(33		)	1,564			(142		)	(224		)	(366		)
Total mark-to-market derivative liabilities	(6,580		)	(127		)	6,391			(316		)	(247		)	(563		)
Total mark-to-market derivative net assets (liabilities)	$	516		$	3		$	1,234		$	1,753		$	(247	)	$	1,506

______________________

(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 $352 million and $180 million, respectively, and current and noncurrent liabilities are shown net of collateral of $480 million and $222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,234 million at December 31, 2015.


(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, 2014:



	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	4,992		$	456		$	(4,184	)	$	1,264		$	—		$	1,264
Mark-to-market derivative assets (noncurrent assets)	1,821			56			(1,112		)	765			—			765
Total mark-to-market derivative assets	6,813			512			(5,296		)	2,029			—			2,029
Mark-to-market derivative liabilities (current liabilities)	(4,947		)	(468		)	5,200			(215		)	(20		)	(235		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,540		)	(64		)	1,502			(102		)	(187		)	(289		)
Total mark-to-market derivative liabilities	(6,487		)	(532		)	6,702			(317		)	(207		)	(524		)
Total mark-to-market derivative net assets (liabilities)	$	326		$	(20	)	$	1,406		$	1,712		$	(207	)	$	1,505

______________________

(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 $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.


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

Cash Flow Hedges (Exelon, Generation and ComEd). As discussed previously, effective prior to the Constellation merger, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably probable, 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. As of December 31, 2015, no unrealized balance remains in accumulated OCI to be reclassified by Generation.

The tables below provide the activity of Accumulated OCI related to cash flow hedges for the years ended December 31, 2015 and 2014, 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 hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.



	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
		Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative gain at January 1, 2014		$	114			$	120
Effective portion of changes in fair value		(15		)		(31		)
Reclassifications from accumulated OCI to net income	Operating revenues	(117		)	^(a)	(117		)	^(a)
Accumulated OCI derivative gain at December 31, 2014		(18		)		(28		)
Effective portion of changes in fair value		(8		)		(12		)
Reclassifications from accumulated OCI to net income	Other, net	—				16			^(b)
Reclassifications from accumulated OCI to net income	Interest expense	7			^(c)	7			^(c)
Reclassifications from accumulated OCI to net income	Operating revenues	(2		)		(2		)
Accumulated OCI derivative gain at December 31, 2015		$	(21	)		$	(19	)

_______________________


(a)	Amount is net of related income tax expense of $78 million for the year ended December 31, 2014.


(b)	Amount is net of related income tax benefit of $10 million for the year ended December 31, 2015.


(c)	Amount is net of related income tax expense of $4 million for the year ended December 31, 2015.

During the years ended December 31, 2015, 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 $2 million, $195 million and $683 million pre-tax gain, respectively. In addition, the effect of Exelon's former energy-related cash flow hedge activity impact on pre-tax earnings based on the reclassification adjustment from Accumulated OCI to earnings was a $2 million, $195 million and $464 million pre-tax gain for the years ended December 31, 2015, 2014 and 2013, 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, neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods relating to energy-related hedge positions as all 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 PHI merger. For the years ended December 31, 2015, 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, or Interest 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		Exelon Corporate			Exelon
Year Ended December 31, 2015	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			Operating Revenues ^(a)		Interest Expense			Total
Change in fair value of commodity positions	$	759		$	(355	)	$	—		$	404		$	—	$	—		$	404
Reclassification to realized at settlement of commodity positions	(563		)	409			—			(154		)	—		—			(154		)
Net commodity mark-to-market gains (losses)	196			54			—			250			—		—			250
Change in fair value of treasury positions	13			—			—			13			—		36			49
Reclassification to realized at settlement of treasury positions	(6		)	—			—			(6		)	—		64			58
Net treasury mark-to market gains (losses)	7			—			—			7			—		100			107
Net mark-to market gains (losses)	$	203		$	54		$	—		$	257		$	—	$	100		$	357
	Generation												Intercompany Eliminations		Exelon Corporate			Exelon
Year Ended December 31, 2014	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			Operating Revenues (a)		Interest Expense			Total
Change in fair value of commodity positions	$	(413	)	$	(194	)	$	—		$	(607	)	$	—	$	—		$	(607	)
Reclassification to realized at settlement of commodity positions	231			(223		)	—			8			—		—			8
Net commodity mark-to-market gains (losses)	(182		)	(417		)	—			(599		)	—		—			(599		)
Change in fair value of treasury positions	10			—			(2		)	8			—		(100		)	(92		)
Reclassification to realized at settlement of treasury positions	(2		)	—			—			(2		)	—		—			(2		)
Net treasury mark-to market gains (losses)	8			—			(2		)	6			—		(100		)	(94		)
Net mark-to market gains (losses)	$	(174	)	$	(417	)	$	(2	)	$	(593	)	$	—	$	(100	)	$	(693	)



	Generation											Intercompany Eliminations			Exelon Corporate		Exelon
Year Ended December 31, 2013	Operating Revenues			Purchased Power and Fuel		Interest Expense			Total			Operating Revenues ^(a)			Interest Expense		Total
Change in fair value of commodity positions	$	286		$	180	$	—		$	466		$	(6	)	$	—	$	460
Reclassification to realized at settlement of commodity positions	(64		)	104		—			40			13			—		53
Net commodity mark-to-market gains (losses)	222			284		—			506			7			—		513
Change in fair value of treasury positions	(1		)	—		(4		)	(5		)	—			—		(5		)
Reclassification to realized at settlement of treasury positions	(1		)	—		—			(1		)	—			—		(1		)
Net treasury mark-to market gains (losses)	(2		)	—		(4		)	(6		)	—			—		(6		)
Net mark-to market gains (losses)	$	220		$	284	$	(4	)	$	500		$	7		$	—	$	507

________________________


(a)	Prior to the Constellation 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 years ended December 31, 2015, 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.



	Location on Income Statement	For the Years Ended December 31,
	Location on Income Statement	2015			2014			2013
Change in fair value of commodity positions	Operating Revenues	$	8		$	(1	)	$	(22	)
Reclassification to realized at settlement of commodity positions	Operating Revenues	(14		)	(29		)	(15		)
Net commodity mark-to-market gains (losses)	Operating Revenues	(6		)	(30		)	(37		)
Change in fair value of treasury positions	Operating Revenues	8			1			1
Reclassification to realized at settlement of treasury positions	Operating Revenues	(10		)	3			(3		)
Net treasury mark-to market gains (losses)	Operating Revenues	(2		)	4			(2		)
Net mark-to market gains (losses)	Operating Revenues	$	(8	)	$	(26	)	$	(39	)

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 December 31, 2015. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 7A.—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 $15 million, $36 million and $31 million, respectively.



Rating as of December 31, 2015	Total Exposure Before Credit Collateral		Credit Collateral ^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,397	$	50	$	1,347	1	$	432
Non-investment grade	67		25		42		—	—
No external ratings
Internally rated—investment grade	521		—		521		—	—
Internally rated—non-investment grade	77		7		70		—	—
Total	$	2,062	$	82	$	1,980	1	$	432



Net Credit Exposure by Type of Counterparty	December 31, 2015
Financial institutions	$	187
Investor-owned utilities, marketers, power producers	886
Energy cooperatives and municipalities	872
Other	35
Total	$	1,980

______________________


(a)	As of December 31, 2015, credit collateral held from counterparties where Generation had credit exposure included $13 million of cash and $69 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 December 31, 2015, ComEd’s net credit exposure to suppliers was immaterial.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters 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 December 31, 2015, PECO had no net credit exposure to 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 3—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 December 31, 2015, PECO's credit exposure under its natural gas supply and asset management agreements with investment grade suppliers was immaterial.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters 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 December 31, 2015, BGE had no net credit exposure 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 December 31, 2015, BGE had credit exposure of $4 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:



	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2015			2014
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(932	)	$	(1,433	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	684			1,140
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(248	)	$	(293	)

__________________________


(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.


(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.


(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Generation had cash collateral posted of $1,267 million and letters of credit posted of $497 million, and cash collateral held of $21 million and letters of credit held of $78 million as of December 31, 2015 for external counterparties with derivative positions. Generation had cash collateral posted of $1,497 million and letters of credit posted of $672 million and cash collateral held of $77 million and letters of credit held of $24 million at December 31, 2014 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P or Ba1 by Moody's), Generation would have been required to post additional collateral of $2.0 billion and $2.4 billion as of December 31, 2015 and 2014, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.

Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2015, Generation’s and Exelon’s swaps were in an asset position, with a fair value of $13 million and $38 million, respectively.

See Note 25 — Segment Information 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 December 31, 2015, ComEd held no 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 December 31, 2015, 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 for additional information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2015, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2015, PECO could have been required to post approximately $25 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 December 31, 2015, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2015, BGE could have been required to post approximately $35 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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Reference 15: http://www.xbrl.org/2003/role/presentationRef
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
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-Topic 815
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-Section 50
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Reference 17: http://www.xbrl.org/2003/role/presentationRef
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-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Section 50
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Reference 19: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Section S99
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Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE)

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

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

(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.

Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2015 and 2014:



	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer	2015 (a)(b)		2014 (a)(b)		2015		2014		2015		2014
Exelon Corporate	$	500	$	500	$	—	$	—	n.a.		n.a.
Generation	5,450		5,600		—		—		0.49	%	0.32	%
ComEd	1,000		1,000		294		304		0.53	%	0.33	%
PECO	600		600		—		—		n.a.		n.a.
BGE	600		600		210		120		0.48	%	0.29	%
Total	$	8,150	$	8,300	$	504	$	424

_____________________


(a)	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generation as of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effective program size.

(b)

Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

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

At December 31, 2015, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:



							Available Capacity at December 31, 2015
Borrower	Aggregate Bank Commitment ^(a)		Facility Draws		Outstanding Letters of Credit^(c)		Actual		To Support Additional Commercial Paper ^(b)
Exelon Corporate	$	500	$	—	$	26	$	474	$	474
Generation	5,725		—		1,449		4,276		4,174
ComEd	1,000		—		2		998		704
PECO	600		—		1		599		599
BGE	600		—		—		600		390
Total	$	8,425	$	—	$	1,478	$	6,947	$	6,341

_______________________

(a)


(b)	Excludes $275 million bilateral credit facilities that do not back Generation’s commercial paper program.


(c)	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.

As of December 31, 2015, there were no borrowings under the Registrants’ credit facilities.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2015, 2014 and 2013. PECO did not have any short-term borrowings during 2015, 2014 or 2013.

Exelon



	2015			2014			2013
Average borrowings	$	499		$	571		$	254
Maximum borrowings outstanding	739			1,164			682
Average interest rates, computed on a daily basis	0.53		%	0.32		%	0.37		%
Average interest rates, at December 31	0.88		%	0.53		%	0.35		%
Generation
	2015			2014			2013
Average borrowings	$	1		$	93		$	42
Maximum borrowings outstanding	50			552			291
Average interest rates, computed on a daily basis	0.49		%	0.32		%	0.32		%
Average interest rates, at December 31	n.a.			n.a.			n.a.



ComEd
	2015			2014			2013
Average borrowings	$	461		$	415		$	203
Maximum borrowings outstanding	684			597			446
Average interest rates, computed on a daily basis	0.53		%	0.33		%	0.40		%
Average interest rates, at December 31	0.89		%	0.50		%	0.37		%
BGE
	2015			2014			2013
Average borrowings	$	37		$	64		$	35
Maximum borrowings outstanding	210			180			135
Average interest rates, computed on a daily basis	0.48		%	0.29		%	0.31		%
Average interest rates, computed at December 31	0.87		%	0.61		%	0.31		%

Credit Agreements

On October 23, 2015, the credit agreement for CENG's $100 million bilateral credit facility was amended and extended for an additional two years. This facility has been utilized by CENG to fund working capital and capital projects. This facility does not back Generation's commercial paper program.

On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility, scheduled to mature in January of 2019. This facility does not back Generation's commercial paper program.

Borrowings under Exelon Corporate’s, Generation’s, ComEd’s, PECO’s and BGE’s revolving credit facilities 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. The fee varies depending upon the respective credit ratings of the borrower.

An event of default under any of the Registrants' credit agreements would not constitute an event of default under any of the other Registrants' credit agreements, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its credit agreement would constitute an event of default under the Exelon Corporation credit agreement.

Each credit agreement requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2015:



	Exelon	Generation	ComEd	PECO	BGE
Credit agreement threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1	2.00 to 1

At December 31, 2015, the interest coverage ratios at the Registrants were as follows:



	Exelon	Generation	ComEd	PECO	BGE
Interest coverage ratio	9.77	12.31	7.25	8.94	10.66

Long-Term Debt

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2015 and 2014:

Exelon



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Rate stabilization bonds	5.72	%	-	5.82	%	2017	$	120		$	195
First mortgage bonds ^(a)	1.20	%	-	6.45	%	2016 - 2045	9,019			8,079
Senior unsecured notes	1.55	%	-	7.60	%	2017 - 2045	9,803			7,071
Unsecured bonds	2.80	%	-	6.35	%	2016 - 2036	1,750			1,750
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			—
Nuclear fuel procurement contracts	3.15	%	-	3.35	%	2018 - 2020	127			70
Notes payable and other ^(b)(c)	1.43	%	-	7.83	%	2016 - 2053	314			174
Junior subordinated notes				6.50	%	2024	1,150			1,150
Contract payment - junior subordinated notes				2.50	%	2017	64			108
Long-term software licensing agreement				3.95	%	2024	111			—
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,162			1,166
Variable rates	2.42	%	-	5.00	%	2017 - 2030	1,058			1,101
Total long-term debt							25,113			20,864
Unamortized debt discount and premium, net							(63		)	(37		)
Unamortized debt issuance costs ^(d)							(180		)	(150		)
Fair value adjustment							275			333
Fair value hedge carrying value adjustment, net							—			4
Long-term debt due within one year							(1,500		)	(1,802		)
Long-term debt							$	23,645		$	19,212
Long-term debt to financing trusts ^(e)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Subordinated debentures to PECO Trust III				7.38	%	2028	81			81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103			103
Subordinated debentures to BGE Trust				6.20	%	2043	258			258
Total long-term debt to financing trusts							648			648
Unamortized debt issuance costs ^(d)							(7		)	(7		)
Long-term debt to financing trusts							$	641		$	641

____________________


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


(b)	Includes capital lease obligations of $29 million and $32 million at December 31, 2015 and 2014, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $4 million, and $8 million will be made in 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.


(c)	Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2 - Variable Interest Entities for additional information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.


(d)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

Generation



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Senior unsecured notes	2.00	%	-	7.60	%	2017 - 2042	$	5,971		$	5,771
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			—
Nuclear fuel procurement contracts	3.15	%	-	3.35	%	2018 - 2020	127			70
Notes payable and other ^(a)(b)	1.43	%		7.83	%	2016 - 2035	166			26
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,162			1,166
Variable rates	2.42	%	-	5.00	%	2017 - 2030	1,058			1,101
Total long-term debt							8,919			8,134
Fair value adjustment							127			146
Unamortized debt discount and premium, net							(17		)	(14		)
Unamortized debt issuance costs ^(c)							(70		)	(70		)
Long-term debt due within one year							(90		)	(614		)
Long-term debt							$	8,869		$	7,582

______________________


(a)	Includes Generation’s capital lease obligations of $21 million and $24 million at December 31, 2015 and 2014, respectively. Generation will make lease payments of $4 million, $4 million, $4 million, $5 million and $4 million in 2016, 2017, 2018, 2019, 2020, respectively. The capital lease matures in 2020.


(b)	Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2 - Variable Interest Entities for additional information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.


(c)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.

ComEd



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
First mortgage bonds ^(a)	1.95	%	-	6.45	%	2016 - 2045	$	6,419		$	5,829
Notes payable and other^(b)	6.95	%	-	7.49	%	2016 - 2053	148			148
Total long-term debt							6,567			5,977
Unamortized debt discount and premium, net							(20		)	(19		)
Unamortized debt issuance costs ^(c)							(38		)	(33		)
Long-term debt due within one year							(665		)	(260		)
Long-term debt							$	5,844		$	5,665
Long-term debt to financing trust ^(d)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Total long-term debt to financing trusts							206			206
Unamortized debt issuance costs ^(c)							(1		)	(1		)
Long-term debt to financing trusts							$	205		$	205

______________________


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


(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2015 and 2014, respectively. Lease payments of less than $1 million will be made from 2016 through expiration at 2053.


(c)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

PECO



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
First mortgage bonds ^(a)	1.20	%	-	5.95	%	2016 - 2044	$	2,600		$	2,250
Total long-term debt							2,600			2,250
Unamortized debt discount and premium, net							(5		)	(4		)
Unamortized debt issuance costs ^(b)							(15		)	(14		)
Long-term debt due within one year							(300		)	—
Long-term debt							$	2,280		$	2,232
Long-term debt to financing trusts ^(c)
Subordinated debentures to PECO Trust III				7.38	%	2028	$	81		$	81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103			103
Long-term debt to financing trusts							$	184		$	184

_____________________


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


(b)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

BGE



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Rate stabilization bonds	5.72	%	-	5.82	%	2017	$	120		$	195
Senior unsecured notes	2.80	%	-	6.35	%	2016 - 2036	1,750			1,750
Total long-term debt							1,870			1,945
Unamortized debt discount and premium, net							(3		)	(3		)
Unamortized debt issuance costs ^(a)							(9		)	(10		)
Long-term debt due within one year							(378		)	(75		)
Long-term debt							$	1,480		$	1,857
Long-term debt to financing trusts ^(b)
Subordinated debentures to BGE Capital Trust II				6.20	%	2043	$	258		$	258
Total long-term debt to financing trusts							258			258
Unamortized debt issuance costs ^(a)							(6		)	(6		)
Long-term debt to financing trusts							$	252		$	252

___________________


(a)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2016 through 2020 and thereafter are as follows:



Year	Exelon			Generation		ComEd			PECO			BGE
2016	$	1,487		$	90	$	665		$	300		$	378
2017	1,841			805		425			—			42
2018	1,393			53		840			500			—
2019	973			673		300			—			—
2020	3,311			1,911		500			—			—
Thereafter	16,756		^(a)	5,387		4,043		^(b)	1,984		^(c)	1,708		^(d)
Total	$	25,761		$	8,919	$	6,773		$	2,784		$	2,128

____________________


(a)	Includes $648 million due to ComEd, PECO and BGE financing trusts.


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


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


(d)	Includes $258 million due to BGE financing trust.

PHI Merger Financing

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. In June 2015, the remaining $3.2 billion bridge credit facility was terminated as a result of Exelon's issuance of $4.2 billion of long-term debt to fund a portion of the purchase price and related costs and expenses for the pending PHI merger and for general corporate purposes.

In connection with the $4.2 billion issuance of Senior Unsecured Notes in 2015, the tranches due in 2025, 2035, and 2045 had to be redeemed at the principal amount plus a 1% premium of principal on December 31, 2015, if the PHI merger was not consummated or terminated prior to such date ("Special Mandatory Redemption"). Exelon also had the option to redeem those notes earlier at a 1% premium of principal, if Exelon determined that the merger would not be completed before December 31, 2015.

On October 29, 2015, Exelon commenced a private exchange offer (Exchange Offer) to certain eligible holders whereby, for those that took part, the outstanding Senior Unsecured Notes in the 2025, 2035 and 2045 tranches were exchanged for new Senior Unsecured Notes. The new Senior Unsecured Notes have substantially the same terms as the outstanding Senior Unsecured Notes, except the outside date with regard to the special redemption provisions is June 30, 2016, (or the date the PHI merger is terminated if earlier), rather than December 31, 2015, and under certain circumstances, can be further extended to August 31, 2016.

On December 2, 2015, Exelon exchanged $1.9 billion of the Senior Unsecured Notes and paid a consent fee of approximately $5 million, which has been deferred on Exelon's Consolidated Balance Sheet and $4 million of third-party debt issuance costs, which were charged to earnings within Other, net on Exelon's Consolidated Statement of Operations and Comprehensive Income. On December 2, 2015, Exelon also redeemed $0.9 billion of Senior Unsecured Notes not exchanged in the Exchange Offer resulting in the payment of $9 million of redemption premium and the acceleration of the unamortized original issuance discount and deferred financing costs associated with the redeemed debt of $9 million, which were charged to earnings within Other, net on Exelon's Consolidated Statement of Operations and Comprehensive Income.

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Net 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 merger and related costs and expenses for the pending PHI merger and for general corporate purposes. Each equity unit represents an undivided beneficial ownership interest in Exelon's 2.50% 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.

At the time of issuance, Exelon determined that the forward equity purchase contract had no value and therefore the entire $1.15 billion of junior subordinated notes were allocated to debt and 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 ("Contract Payment Obligation") 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 is accreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income. During 2015, contract payments of $44 million related to the Contract Payment Obligation were included within Retirements of long-term debt in Exelon's Consolidated Statements of Cash Flows. During 2014, the Contract Payment Obligation was 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.

Nonrecourse Debt

Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.4 billion of generating assets and $0.2 billion of Upstream gas properties have been pledged as collateral at December 31, 2015. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.

Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project in Denver, Colorado. The agreement is scheduled to mature on June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2015, $7 million was outstanding.

CEU Upstream. In July 2011, Generation entered into a 5-year asset-based lending agreement associated with certain Upstream gas properties that it owns. The borrowing base committed under the facility is $85 million as of December 31, 2015. The commitment level can be decreased if the assets no longer support the current borrowing base, which would result in repayment of a portion or all of the outstanding balance. The commitment can be increased up to $500 million if the assets support a higher borrowing base and Generation is able to obtain additional commitments from lenders. Calculations of the borrowing base are impacted by projected production and commodity prices. The facility was amended and extended through January 2019. The agreement bears interest at a variable rate equal to LIBOR plus 2.50% and is payable monthly. As of December 31, 2015, $68 million was outstanding under the facility.

Sacramento PV Energy. In July 2011, a subsidiary of Generation entered into a 19-year, $41 million nonrecourse note to finance a 30MW solar facility in Sacramento, California. The note is scheduled to mature on December 31, 2030. The note bears interest at a variable rate equal to LIBOR plus 2.25% and is payable quarterly. As of December 31, 2015, $33 million was outstanding. The subsidiary also executed interest rate swaps with an initial notional value of $30 million at an interest rate of 3.57% in order to convert the variable interest payments to fixed payments on 75% of the $41 million facility amount, as required by the debt covenants. See Note 13 — Derivative Financial Instruments for additional information regarding interest rate swaps.

Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solar construction project in Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2015, $10 million was outstanding.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in the first half of 2014. The loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended interest rate of 2.82%. As of December 31, 2015, $574 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2015, Generation had $69 million in letters of credit outstanding related to the project.

Constellation Solar Horizons. In September 2012, a subsidiary of Generation entered into an 18-year $38 million nonrecourse note to recover capital used to build a 16MW solar facility in Emmitsburg, Maryland. The note is scheduled to mature on September 7, 2030. The note bears interest at a variable rate equal to LIBOR plus 2.25% with interest payable quarterly. As of December 31, 2015, $32 million was outstanding. The subsidiary also executed interest rate swaps for an initial notional amount of $29 million at an interest rate of 2.03% in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount, as required by the debt covenants. See Note 13 — Derivative Financial Instruments for additional information regarding interest rate swaps.

Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2015, $572 million was outstanding.

In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2015, the Continental Wind letter of credit facility had $99 million in letters of credit outstanding related to the project.

ExGen Renewables I. In February 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal amount pursuant to a nonrecourse senior secured loan. The proceeds were distributed to Generation for its general business purposes. The loan is scheduled to mature on February 6, 2021. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% LIBOR floor with interest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2015, $258 million was outstanding. In addition to the financing, EGR entered into interest rate swaps with an initial notional amount of $240 million at an interest rate of 2.03% to manage a portion of the interest rate exposure in connection with the financing. See Note 13 — Derivative Financial Instruments for additional information regarding interest rate swaps.

ExGen Texas Power. In September 2014, ExGen Texas Power, LLC (EGTP), an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2015, $666 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 13 — Derivative Financial Instruments for additional information regarding interest rate swaps.

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

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

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

(Exelon, Generation, ComEd, PECO and BGE)

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



For the Year Ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	407		$	546		$	(80	)	$	64		$	25
Deferred	566			16			310			69			126
Investment tax credit amortization	(22		)	(19		)	(2		)	—			(1		)
State
Current	(86		)	(90		)	7			(10		)	—
Deferred	208			49			45			20			39
Total	$	1,073		$	502		$	280		$	143		$	189
For the Year Ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	121		$	360		$	(171	)	$	28		$	24
Deferred	576			(35		)	395			87			90
Investment tax credit amortization	(20		)	(16		)	(2		)	—			(1		)
State
Current	42			35			7			(2		)	—
Deferred	(53		)	(137		)	39			1			27
Total	$	666		$	207		$	268		$	114		$	140
For the Year Ended December 31, 2013	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	744		$	250		$	160		$	126		$	9
Deferred	140			360			(27		)	23			100
Investment tax credit amortization	(15		)	(11		)	(2		)	(1		)	(1		)
State
Current	181			50			50			16			—
Deferred	(6		)	(34		)	(29		)	(2		)	26
Total	$	1,044		$	615		$	152		$	162		$	134

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



For the Year Ended December 31, 2015	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	3.7		1.0		4.9		1.0		5.3
Qualified nuclear decommissioning trust fund loss	(0.4	)	(0.8	)	—		—		—
Domestic production activities deduction	(0.7	)	(1.3	)	—		—		—
Health care reform legislation	—		—		—		—		0.1
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9	)	(1.5	)	(0.3	)	(0.1	)	(0.1	)
Plant basis differences	(1.5	)	—		(0.1	)	(8.7	)	(0.7	)
Production tax credits and other credits	(1.9	)	(3.4	)	—		—		—
Non-controlling interest	0.3		0.5		—		—		—
Statute of limitations expiration	(1.4	)	(2.4	)	—		—		—
Other	—		—		0.2		0.2		—
Effective income tax rate	32.2	%	27.1	%	39.7	%	27.4	%	39.6	%
For the Year Ended December 31, 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	1.3		(1.9	)	4.5		(0.1	)	5.0
Qualified nuclear decommissioning trust fund income	2.4		4.8		—		—		—
Domestic production activities deduction	(2.0	)	(4.1	)	—		—		—
Health care reform legislation	0.1		—		0.2		—		0.2
Amortization of investment tax credit, including deferred taxes on basis difference	(1.1	)	(2.0	)	(0.3	)	(0.1	)	(0.3	)
Plant basis differences	(1.9	)	—		(0.1	)	(10.4	)	0.2
Production tax credits and other credits	(2.4	)	(4.8	)	—		—		—
Non-controlling interest	(1.8	)	(3.7	)
Statute of limitations expiration	(2.6	)	(5.3	)	—		—		—
Other	(0.2	)	(1.1	)	0.3		0.1		(0.2	)
Effective income tax rate	26.8	%	16.9	%	39.6	%	24.5	%	39.9	%
For the Year Ended December 31, 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	4.8		1.8		3.4		1.6		4.9
Qualified nuclear decommissioning trust fund income	3.7		6.1		—		—		—
Domestic production activities deduction	—		—		—		—		—
Health care reform legislation	0.1		—		0.7		—		0.2
Amortization of investment tax credit, including deferred taxes on basis difference	(1.9	)	(3.0	)	(0.6	)	(0.1	)	—
Plant basis differences	(1.6	)	—		(0.8	)	(7.1	)	(0.2	)
Production tax credits and other credits	(2.1	)	(3.4	)	(0.1	)	—		—
Statute of limitations expiration	(0.1	)	(0.2	)	—		—		—
Other	(0.3	)	0.4		0.3		(0.3	)	(0.9	)
Effective income tax rate	37.6	%	36.7	%	37.9	%	29.1	%	39.0	%

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2015 and 2014 are presented below:



For the Year Ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(13,393	)	$	(4,269	)	$	(4,424	)	$	(2,901	)	$	(1,821	)
Accrual based contracts	(136		)	(136		)	—			—			—
Derivatives and other financial instruments	(203		)	(181		)	(4		)	—			—
Deferred pension and postretirement obligation	1,801			(371		)	(505		)	(9		)	(47		)
Nuclear decommissioning activities	(592		)	(592		)	—			—			—
Deferred debt refinancing costs	133			48			(15		)	(1		)	(4		)
Regulatory assets and liabilities	(1,706		)	—			(219		)	16			(264		)
Tax loss carryforward	103			56			—			—			33
Tax credit carryforward	327			374			—			—			—
Investment in CENG	(595		)	(595		)	—			—			—
Other, net	1,112			425			270			105			27
Deferred income tax liabilities (net)	$	(13,149	)	$	(5,241	)	$	(4,897	)	$	(2,790	)	$	(2,076	)
Unamortized investment tax credits	(622		)	(598		)	(17		)	(2		)	(5		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(13,771	)	$	(5,839	)	$	(4,914	)	$	(2,792	)	$	(2,081	)
For the Year Ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(12,143	)	$	(3,834	)	$	(3,945	)	$	(2,749	)	$	(1,660	)
Accrual based contracts	(178		)	(178		)	—			—			—
Derivatives and other financial instruments	(46		)	(79		)	(4		)	—			—
Deferred pension and postretirement obligation	1,914			(390		)	(543		)	2			(53		)
Nuclear decommissioning activities	(726		)	(726		)	—			—			—
Deferred debt refinancing costs	112			57			(18		)	(2		)	(4		)
Regulatory assets and liabilities	(1,824		)	—			(286		)	27			(258		)
Tax loss carryforward	111			48			—			11			39
Tax credit carryforward	97			143			—			—			—
Investment in CENG	(563		)	(563		)	—			—			—
Other, net	1,029			346			255			111			30
Deferred income tax liabilities (net)	$	(12,217	)	$	(5,176	)	$	(4,541	)	$	(2,600	)	$	(1,906	)
Unamortized investment tax credits	(555		)	(528		)	(20		)	(2		)	(5		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(12,772	)	$	(5,704	)	$	(4,561	)	$	(2,602	)	$	(1,911	)

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2015.



	Exelon		Generation		ComEd	PECO	BGE
Federal
Federal general business credits carryforward	416	^(a)	415		—	—	—
State
State net operating losses and other credit carryforwards	2,086	^(b)	1,259	^(b)	—	—	618	^(c)
Deferred taxes on state tax attributes (net)	117		66		—	—	34
Valuation allowance on state tax attributes	13		11		—	—	1

_____________________


(a)	Exelon’s federal general business credit carryforwards will expire beginning in 2032.


(b)	Exelon’s and Generation's state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2016.


(c)	BGE’s state net operating losses will expire beginning in 2026.

Tabular reconciliation of unrecognized tax benefits

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2015, 2014 and 2013:



	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2015	$	1,829		$	1,357		$	149		$	44		$	—
Increases based on tax positions related to 2015	108			—			—			—			106
Change to positions that only affect timing	(705		)	(659		)	(7		)	(44		)	—
Increases based on tax positions prior to 2015	79			65			—			—			14
Decreases based on tax positions prior to 2015	(116		)	(112		)	—			—			—
Decrease from settlements with taxing authorities	(31		)	(31		)	—			—			—
Decreases from expiration of statute of limitations	(86		)	(86		)	—			—			—
Unrecognized tax benefits at December 31, 2015	$	1,078		$	534		$	142		$	—		$	120
	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2014	$	2,175		$	1,415		$	324		$	44		$	—
Increases based on tax positions related to 2014	15			15			—			—			—
Change to positions that only affect timing	(255		)	33			(175		)	—			—
Increases based on tax positions prior to 2014	18			18			—			—			—
Decreases based on tax positions prior to 2014	(1		)	(2		)	—			—			—
Decrease from settlements with taxing authorities	(35		)	(34		)	—			—			—
Decreases from expiration of statute of limitations	(88		)	(88		)	—			—			—
Unrecognized tax benefits at December 31, 2014	$	1,829		$	1,357		$	149		$	44		$	—



	Exelon			Generation			ComEd		PECO		BGE
Unrecognized tax benefits at January 1, 2013	$	1,024		$	876		$	67	$	44	$	—
Increases based on tax positions related to 2013	19			19			—		—		—
Change to positions that only affect timing	649			36			257		—		—
Increases based on tax positions prior to 2013	493			493			—		—		—
Decreases based on tax positions prior to 2013	(6		)	(5		)	—		—		—
Decreases from expiration of statute of limitations	(4		)	(4		)	—		—		—
Unrecognized tax benefits at December 31, 2013	$	2,175		$	1,415		$	324	$	44	$	—

Included in Exelon’s unrecognized tax benefits balance at December 31, 2015 and 2014 are approximately $540 million and $1,129 million, respectively, of tax positions for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.

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 disallowed AmerGen's claims. In early 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. 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. On March 11, 2015, the Federal Circuit affirmed the lower court’s decision to deny AmerGen’s claims for refund. Exelon will not be pursuing further appeals with respect to this issue and, as a result, reduced Generation and PECO's unrecognized tax benefits by a total of $661 million and $43 million, respectively, in the first quarter of 2015. This change in unrecognized tax benefits had no impact on Exelon, Generation, or PECO's effective tax rate.

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

Exelon and Generation have $538 million and $509 million, respectively, of unrecognized tax benefits at December 31, 2015 that, if recognized, would decrease the effective tax rate. BGE has $120 million of unrecognized tax benefits at December 31, 2015 that, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate. Exelon and Generation had $701 million and $672 million, respectively, of unrecognized tax benefits at December 31, 2014 that, if recognized, would decrease the effective tax rate. In 2015, the unrecognized tax benefits decreased at Exelon and Generation due to settlements with state tax authorities and the expiration of statues of limitations for certain state jurisdictions.

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

Like-Kind Exchange

As of December 31, 2015, Exelon and ComEd have approximately $397 million and $142 million of unrecognized tax benefits that could significantly decrease within the 12 months after the reporting date as a result of a decision in the like-kind exchange litigation described below. Exelon and ComEd have unrecognized tax benefits that, if recognized, would decrease Exelon's effective tax rate by $69 million and increase ComEd's effective tax rate by $11 million.

Settlement of Income Tax Audits and Litigation

As of December 31, 2015, Exelon, Generation, and BGE have approximately $174 million, $54 million, and $120 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, and expected statute of limitation expirations. Of the above unrecognized tax benefits, Exelon and Generation have $54 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to BGE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Total amounts of interest and penalties recognized

The following table represents the net interest receivable (payable), including interest related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.



Net interest receivable (payable) as of	Exelon			Generation		ComEd			PECO		BGE
December 31, 2015	$	(288	)	$	80	$	(210	)	$	3	$	(1	)
December 31, 2014	(310		)	40		(203		)	3		(1		)

The following table sets forth the net interest expense, including interest related to tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have not accrued any material penalties with respect to uncertain tax positions.



Net interest expense (income) for the years ended	Exelon			Generation			ComEd		PECO			BGE
December 31, 2015	$	(13	)	$	(31	)	$	7	$	—		$	—
December 31, 2014	(36		)	(50		)	6		—			1
December 31, 2013	391			17			281		(1		)	—

Description of tax years that remain open to assessment by major jurisdiction



Taxpayer	Open Years
Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns	1999, 2001-2014
Exelon and subsidiaries Illinois unitary income tax returns	2007-2014
Constellation combined New York corporate income tax returns	2010-March 2012
Various separate company Pennsylvania corporate net income tax returns	2010-2014
BGE Maryland corporate net income tax returns	2011-2014
Various Exelon Maryland corporate net income tax returns	2012-2014
Various Constellation (Non-BGE) Maryland corporate net income tax returns	2011-2014

Other Tax Matters

Like-Kind Exchange

Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. 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 Exelon's 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 $90 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 $172 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 IRS 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 and the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. While the Tax Court could reach its decision as early as 2016, the litigation could take three to five years if an appeal is necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision in Consolidated Edison.

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. In connection with the termination, Exelon deposited $65 million with the IRS, including $35 million by ComEd. The deposit can be redesignated to any tax year, if necessary, and may be used to satisfy any amounts owed as a result of the litigation.

In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, the potential tax and after-tax interest, net of the deposit discussed above and exclusive of penalties, that could become currently payable as of December 31, 2015 may be as much as $760 million, of which approximately $280 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. Interest will continue to accrue until such time as payment is made. An appeal of an adverse decision in the Tax Court would necessitate either the posting of a bond or the payment of the tax and interest for the tax years before the court. A final appellate decision could take several years.

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 changed its method of accounting for deducting repairs in accordance with this guidance beginning in the 2014 tax year. The adoption of the new method resulted in Generation recording a cash tax detriment of approximately $120 million in 2014.

Long-Term State Tax Apportionment (Exelon and Generation)

The long-term state tax apportionment was revised in the fourth quarter of 2015 pursuant to Exelon's long-term state tax apportionment policy, resulting in the recording of a deferred state tax expense for Exelon and Generation of $41 million (net of Federal taxes) and $11 million (net of Federal taxes), respectively. In 2014, in accordance with the policy, Exelon and Generation recorded a deferred state tax benefit of $28 million (net of Federal taxes) and $40 million (net of Federal taxes), respectively. The amounts recorded for 2013 in accordance with the policy were immaterial.

Allocation of Tax Benefits (Exelon, Generation, ComEd, PECO and BGE)

Generation, ComEd, PECO and BGE are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2015, Generation, PECO, and BGE recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $57 million, $16 million, and $7 million respectively. ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.

During 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $55 million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of tax net operating losses.

During 2013, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $26 million and $27 million, respectively. During 2013, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.

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

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

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

(Exelon, Generation, ComEd, PECO and BGE)

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 January 1, 2014 to December 31, 2015:



	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2014	$	4,855
Consolidation of CENG ^(a)	1,760
Accretion expense	334
Net increase due to changes in, and timing of, estimated future cash flows	19
Costs incurred to decommission retired plants	(7		)
Nuclear decommissioning ARO at December 31, 2014^(b)	6,961
Accretion expense	387
Net increase due to changes in, and timing of, estimated future cash flows	901
Costs incurred to decommission retired plants	(3		)
Nuclear decommissioning ARO at December 31, 2015 ^(b)	$	8,246

_________________________


(a)	Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.


(b)	Includes $7 million and $8 million as the current portion of the ARO at December 31, 2015 and 2014, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During 2015, Generation’s total nuclear ARO increased by approximately $1.3 billion, reflecting impacts of ARO updates completed during 2015 to reflect changes in amounts and timing of estimated decommissioning cash flows and impacts of year-to-date accretion of the ARO liability due to the passage of time.

The increase in the ARO during 2015 was primarily driven by an increase of approximately $630 million for costs expected to be incurred for required site security during the decommissioning periods in which SNF remains on-site and until major reactor components and buildings have been dismantled and removed. This projected increase is based on emerging industry experience at nuclear sites in the planning or early stage of decommissioning indicating greater than originally expected numbers of security personnel required to be on site during these decommissioning periods. Generation will continue to monitor emerging security cost trends, including potential strategies to limit such costs by, for example, optimizing the transfer of SNF when DOE starts taking possession of SNF or increasing the use of dry SNF storage, and will adjust the ARO liability accordingly. The 2015 increase in the ARO includes an increase of approximately $285 million for the impacts of a change implemented in the 2015 annual assessment of Generation’s SNF storage and disposal cost estimation methodology to better align the projected timing of SNF transfers to the DOE with assumed plant shutdown dates as well as higher assumed probabilities of early retirements of certain economically challenged nuclear plants (See Note 9 - Implications of Potential Early Plant Retirements for additional information) and further accretion of the obligation. These increases were partially offset by reductions in estimated cost escalation rates, primarily for labor and energy costs.

The financial statement impact related to the increase in the ARO due to the changes in, and timing of, estimated cash flows primarily resulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $8 million of the 2015 adjustment resulted in a credit to income, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

During 2014, Generation’s ARO increased by approximately $2.1 billion. The increase is largely driven by the recording of an ARO on Exelon’s and Generation’s Consolidated Balance Sheets at fair value, including subsequent purchase accounting adjustments, upon consolidation of CENG (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC ). The change in the ARO was also driven by an increase for accretion of the obligation and an increase in the estimated costs to decommission Byron, Braidwood, and LaSalle nuclear units resulting from the completion of updated decommissioning costs studies received during 2014 as part of the annual assessment. These increases in the ARO were partially offset by decreases in the ARO due to a reduction in estimated escalation rates, primarily for labor and energy costs. The increase in the ARO due to the changes in, and timing of, estimated cash flows was offset within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets, aside from an approximate $16 million credit to income, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

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 Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 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. Aside from the former PECO units, Generation does not currently collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from utility 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 compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to 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 December 31, 2015, and 2014, Exelon and Generation had NDT fund investments totaling $10,342 million and $10,537 million, respectively. For additional information related to the NDT fund investments, refer to Note 12—Fair Value of Financial Assets and Liabilities.

The following table provides unrealized gains on NDT funds for 2015, 2014 and 2013:



	Exelon and Generation
	For the Years Ended December 31,
	2015			2014		2013
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	(282	)	$	180	$	406
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units ^(b)(c)	(197		)	134		146

_______________________


(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 $7 million, $29 million and $7 million of net unrealized gains related to the Zion Station pledged assets in 2015, 2014 and 2013, respectively. Net unrealized gains 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.

Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds are expected to exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations and financial position could be material. As of December 31, 2015, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.

Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the former PECO units, regardless of whether the funds held in the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s results of operations and financial position could be material.

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

Refer to Note 3 — Regulatory Matters and Note 26 — Related Party Transactions 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. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF and decommission the SNF dry storage facility, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. During 2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another Company. Generation reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, 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 and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $84 million, which is included within the nuclear decommissioning ARO at December 31, 2015. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2015 and 2014:



	Exelon and Generation
	2015		2014
Carrying value of Zion Station pledged assets	$	206	$	319
Payable to Zion Solutions ^(a)	189		292
Current portion of payable to Zion Solutions ^(b)	99		137
Cumulative withdrawals by Zion Solutions to pay decommissioning costs ^(c)	786		666

___________________


(a)	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.


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


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

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

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2015 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2015 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended license life (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.1% to 6.3% (as compared to a historical 5-year annual average pre-tax return of approximately 7%).

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

On March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for reactors that have been shut down except for Zion Station which is included on a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee that had been established in 2013. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance was in place for all reactors owned by Generation. During 2014, the operating license for Limerick Unit 1 was extended by 20 years. As a result of this extension, and the subsequent funding assurance calculation performed by the NRC, it was found that the parent company guarantee was no longer required and thus the parent guarantee for Limerick Unit 1 has been cancelled effective March 13, 2015. See Note 3 — Regulatory Matters for additional information regarding the operating license extension for Limerick Unit 1.

Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, Braidwood Unit 1, Braidwood Unit 2, and Byron Unit 2 did not meet the NRC's minimum funding assurance criteria as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017. On February 4, 2016, Generation submitted an updated decommissioning funding status report with the NRC for Braidwood Units 1 and 2, and Byron Unit 2. This report reflected the recently approved license renewals for these units, and showed that they have adequate decommissioning funding assurance, and that the shortfall identified in the March 31, 2015 report has now been resolved. The increased security costs discussed above will be taken into consideration, as appropriate and in accordance with the regulatory requirements, in Generation's future decommissioning funding status reports submitted to the NRC. Generation does not expect the increased costs to change Generation's NRC minimum funding assurance status.

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

Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)

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

The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2014 to December 31, 2015:



	Exelon			Generation			ComEd			PECO			BGE
Non-nuclear AROs at January 1, 2014	$	351		$	201		$	101		$	30		$	19
Net increase (decrease) due to changes in, and timing of, estimated future cash flows ^(a)	(1		)	(2		)	2			—			(1		)
Development projects ^(b)	11			11			—			—			—
Accretion expense ^(c)	15			11			3			1			—
Liabilities held for sale ^(d)	(4		)	(4		)	—			—			—
Sale of generating assets ^(e)	(20		)	(20		)	—			—			—
Payments	(6		)	(3		)	(2		)	(1		)	—
Non-nuclear AROs at December 31, 2014 ^(f)	346			194			104			30			18
Net increase (decrease) due to changes in, and timing of, estimated future cash flows ^(a)	(10		)	(12		)	6			(4		)	—
Development projects ^(b)	10			10			—			—			—
Accretion expense ^(c)	16			10			5			1			—
Sale of generating assets ^(e)	(2		)	(2		)	—			—			—
Payments	(5		)	(3		)	(2		)	—			—
Non-nuclear AROs at December 31, 2015 ^(f)	$	355		$	197		$	113		$	27		$	18

________________________

(a)

During the year ended December 31, 2015, Generation recorded a decrease of $(2) million in Operating and maintenance expense. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2015. During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014.


(b)	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.


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


(d)	Represents AROs related to generating stations classified as held for sale. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.


(e)	Reflects a reduction to the ARO resulting primarily from the sales of Schuylkill generating station in 2015 and Keystone and Conemaugh generating stations in 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.

(f)

Excludes $5 million, $2 million, $0 million and $1 million as the current portion of the ARO at December 31, 2015 for Generation, ComEd, PECO and BGE, respectively. Excludes $1 million, $1 million, $1 million and $1 million as the current portion of the ARO at December 31, 2014 for Generation, ComEd, PECO and BGE, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.

Implications of Potential Early Plant Retirements Implications of Potential Early Plant Retirements (Exelon, Generation)

12 Months Ended

Dec. 31, 2015

Implications of Potential Early Plant Retirements [Abstract]

Implications Of Potential Early Retirement Disclosure [Text Block]

9. Implications of Potential Early Plant Retirements (Exelon and Generation)

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative solutions in New York and Illinois such as the proposed Low Carbon Portfolio Standard (LCPS) legislation, the impact of final rules from the EPA requiring reduction of carbon and other emissions and the efforts of the states to implement those final rules, and the outcome of the Ginna RSSA hearing and settlement procedures and the resulting contractual terms and conditions. On September 10, 2015, after considering the results of the recent PJM capacity auctions, Exelon and Generation decided to defer decisions about the future operations of its Quad Cities and Byron nuclear plants and will offer both plants in the 2019/2020 auction in May 2016. As a result of clearing the other PJM capacity auction in September 2015 for the 2017/2018 transitional capacity auction, Exelon and Generation will continue to operate its Quad Cities nuclear power plant through at least May 2018. The Byron plant is already obligated to operate through May 2019. On October 29, 2015, Exelon and Generation announced the deferral of any decision about the future operations of its Clinton nuclear plant and plans to bid the plant into the MISO capacity auction for the 2016-2017 planning year in April 2016. This decision was driven by MISO’s acknowledgment of the need for market design changes to ensure long-term power system reliability in southern Illinois, the desire to provide Illinois policy makers with additional time to consider needed reforms as well as the potential long-term impact of EPA’s Clean Power Plan. Exelon and Generation previously committed to cease operation of the Oyster Creek nuclear plant by the end of 2019. Exelon and Generation have not made any decisions regarding potential nuclear plant closures at other sites at this time.

As a result of a decision to early retire one or more other nuclear plants, certain changes in accounting treatment would be triggered and Exelon’s and Generation’s results of operations and cash flows could be materially affected by a number of items including, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.), accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioning trust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown. While there are a number of Generation’s nuclear plants that are at risk of early retirement, the following table provides the balance sheet amounts as of December 31, 2015 for significant assets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement due to their current economic valuations and other factors:



(in millions)	Quad Cities			Clinton				Ginna			Total
Asset Balances
Materials and supplies inventory	$	50		$	57			$	29		$	136
Nuclear fuel inventory, net	218			107				60			385
Completed plant, net	1,030			579				127			1,736
Construction work in progress	11			9				11			31

Liability Balances
Asset retirement obligation	(698		)	(401		)		(644		)	(1,743		)

NRC License Renewal Term	2032			2046			^(a)	2029

________


(a)	Assumes Clinton seeks and receives a 20-year operating license renewal extension.

In the event a decision is made to retire early one or more nuclear plants, the precise timing of the retirement date, and resulting financial statement impact, is uncertain and would be influenced by a number of factors such as the results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity obligations and just prior to its next scheduled nuclear refueling outage date in that year.

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

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

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

(Exelon, Generation, ComEd, PECO and BGE)

As of December 31, 2015, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2015.



	Operating Company^(d)
Name of Plan:	Generation	ComEd	PECO	BGE	BSC
Qualified Pension Plans:
Exelon Corporation Retirement Program^(a)	X	X	X	X	X
Exelon Corporation Cash Balance Pension Plan^(a)	X	X	X	X	X
Exelon Corporation Pension Plan for Bargaining Unit Employees^(a)	X	X			X
Exelon New England Union Employees Pension Plan^(a)	X
Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek^(a)	X	X	X		X
Pension Plan of Constellation Energy Group, Inc.^(b)	X	X	X	X	X
Pension Plan of Constellation Energy Nuclear Group, LLC^(c)	X			X	X
Nine Mile Point Pension Plan^(c)	X				X
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B^(b)	X
Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan^(a)	X	X	X		X
Exelon Corporation Supplemental Management Retirement Plan^(a)	X	X	X	X	X
Constellation Energy Group, Inc. Senior Executive Supplemental Plan^(b)	X			X	X
Constellation Energy Group, Inc. Supplemental Pension Plan^(b)	X			X	X
Constellation Energy Group, Inc. Benefits Restoration Plan^(b)	X	X		X	X
Constellation Nuclear Plan, LLC Executive Retirement Plan^(c)	X				X
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan^(c)	X				X
Baltimore Gas & Electric Company Executive Benefit Plan^(b)	X			X	X
Baltimore Gas & Electric Company Manager Benefit Plan^(b)	X	X		X	X



	Operating Company^(d)
Name of Plan:	Generation	ComEd	PECO	BGE	BSC
Other Postretirement Benefit Plans:
PECO Energy Company Retiree Medical Plan^(a)	X	X	X	X	X
Exelon Corporation Health Care Program^(a)	X	X	X	X	X
Exelon Corporation Employees’ Life Insurance Plan^(a)	X	X	X	X	X
Constellation Energy Group, Inc. Retiree Medical Plan^(b)	X	X	X	X	X
Constellation Energy Group, Inc. Retiree Dental Plan^(b)	X			X	X
Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan^(b)	X	X	X	X	X
Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan^(b)	X
Exelon New England Union Post-Employment Medical Savings Account Plan^(a)	X
Retiree Medical Plan of Constellation Energy Nuclear Group LLC^(c)	X			X	X
Retiree Dental Plan of Constellation Energy Nuclear Group LLC^(c)	X			X	X
Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees^(c)	X				X

______________________


(a)	These plans are collectively referred to as the Legacy Exelon plans.


(b)	These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans.


(c)	These plans are collectively referred to as the Legacy CENG plans.


(d)	Employees generally remain in their legacy benefit plans when transferring between operating companies.

Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Exelon has elected that the trusts underlying these plans be treated under the IRC as qualified trusts. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.

Benefit Obligations, Plan Assets and Funded Status

Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated OCI and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31.

During the first quarter of 2015, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2015. This valuation resulted in an increase to the pension obligation of $45 million and an increase to the other postretirement benefit obligation of $57 million. Additionally, Accumulated other comprehensive loss (AOCL) increased by approximately $27 million (after tax), regulatory assets increased by approximately $48 million, and regulatory liabilities decreased by approximately $11 million.

The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:



	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Change in benefit obligation:
Net benefit obligation at beginning of year	$	18,256		$	15,459		$	4,197		$	4,451
Service cost	326			293			119			117
Interest cost	710			749			167			186
Plan participants’ contributions	—			—			42			42
Actuarial (gain) loss	(582		)	2,095			(341		)	502
Plan amendments	—			—			(23		)	(1,012		)
Acquisitions/divestitures^(a)	—			594			—			142
Curtailments	—			(8		)	—			—
Settlements	(34		)	(30		)	—			—
Gross benefits paid	(923		)	(896		)	(223		)	(231		)
Net benefit obligation at end of year	$	17,753		$	18,256		$	3,938		$	4,197



	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Change in plan assets:
Fair value of net plan assets at beginning of year	$	14,874		$	13,571		$	2,430		$	2,238
Actual return on plan assets	(32		)	1,443			4			90
Employer contributions	462			332			40			291
Plan participants’ contributions	—			—			42			42
Gross benefits paid	(923		)	(896		)	(223		)	(231		)
Acquisitions/divestitures^(a)	—			454			—			—
Settlements	(34		)	(30		)	—			—
Fair value of net plan assets at end of year	$	14,347		$	14,874		$	2,293		$	2,430

_______________________


(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:



	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015		2014
Other current liabilities	$	21	$	16	$	27	$	25
Pension obligations	3,385		3,366		—		—
Non-pension postretirement benefit obligations	—		—		1,618		1,742
Unfunded status (net benefit obligation less net plan assets)	$	3,406	$	3,382	$	1,645	$	1,767

The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.

The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.



	PBO in excess of plan assets
	2015		2014
Projected benefit obligation	$	17,753	$	18,256
Fair value of net plan assets	14,347		14,874



	ABO in excess of plan assets
	2015		2014
Projected benefit obligation	$	17,753	$	18,256
Accumulated benefit obligation	16,792		17,191
Fair value of net plan assets	14,347		14,874

On a PBO basis, the plans were funded at 81% at December 31, 2015 compared to 81% at December 31, 2014. On an ABO basis, the plans were funded at 85% at December 31, 2015 compared to 87% at December 31, 2014. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.

Components of Net Periodic Benefit Costs

The majority of the 2015 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.94%. The majority of the 2015 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 3.92%. A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant's Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2015, 2014 and 2013.



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Components of net periodic benefit cost:
Service cost	$	326		$	293		$	317		$	119		$	117		$	162
Interest cost	710			749			650			167			186			194
Expected return on assets	(1,026		)	(994		)	(1,015		)	(151		)	(154		)	(132		)
Amortization of:
Prior service cost (credit)	13			14			14			(174		)	(122		)	(19		)
Actuarial loss	571			420			562			80			50			83
Settlement charges	2			2			9			—			—			—
Net periodic benefit cost	$	596		$	484		$	537		$	41		$	77		$	288

Components of AOCI and Regulatory Assets

Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2015, 2014 and 2013 for all plans combined.



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial loss (gain)	$	476		$	1,639		$	(1,169	)	$	(194	)	$	561		$	(628	)
Amortization of actuarial loss	(571		)	(420		)	(562		)	(80		)	(50		)	(83		)
Current year prior service (credit) cost	—			—			—			(23		)	(1,012		)	15
Amortization of prior service (cost) credit	(13		)	(14		)	(14		)	174			122			19
Settlements	(2		)	(2		)	(8		)	—			—			—
Total recognized in AOCI and regulatory assets (liabilities)^(a)	$	(110	)	$	1,203		$	(1,753	)	$	(123	)	$	(379	)	$	(677	)

______________________

(a)

Of the $110 million gain related to pension benefits, $64 million and $46 million were recognized in AOCI and regulatory assets, respectively, during 2015. Of the $123 million gain related to other postretirement benefits, $63 million and $60 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2015. Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets, respectively, during 2013.

The following table provides the components of Exelon’s gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as components of periodic benefit cost at December 31, 2015 and 2014, respectively, for all plans combined:



	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015			2014
Prior service cost (credit)	$	36	$	49	$	(812	)	$	(963	)
Actuarial loss	7,310		7,407		711			985
Total ^(a)	$	7,346	$	7,456	$	(101	)	$	22

_______________________

(a)

Of the $7,346 million related to pension benefits, $4,246 million and $3,100 million are included in AOCI and regulatory assets, respectively, at December 31, 2015. Of the $(101) million related to other postretirement benefits, $(63) million and $(38) million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2015. Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. The $22 million related to other postretirement benefits is included in regulatory assets (liabilities) at December 31, 2014.

The following table provides the components of Exelon’s AOCI and regulatory assets(liabilities) at December 31, 2015 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2016. These estimates are subject to the completion of an actuarial valuation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2016 and actual claims activity as of December 31, 2015. The valuation is expected to be completed in the first quarter of 2016 for the majority of the benefit plans.



	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	13	$	(175	)
Actuarial loss	501		50
Total ^(a)	$	514	$	(125	)

___________________


(a)	Of the $514 million related to pension benefits at December 31, 2015, $290 million and $224 million are expected to be amortized from AOCI and regulatory assets in 2016, respectively. Of the $(125) million related to other postretirement benefits at December 31, 2015, $(64) million and $(61) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2016, respectively.

Assumptions

The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term EROA, Exelon’s expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among other factors.

Expected Rate of Return. In selecting the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.

Mortality. For the December 31, 2014 actuarial valuation, Exelon changed its assumption of mortality to reflect more recent expectations of future improvements in life expectancy. The change was supported through completion of an experience study and supplemental analyses performed by its actuaries. The change in assumption resulted in increases of $361 million and $117 million in the pension and other postretirement benefits obligations as of December 31, 2014, respectively. There were no changes to the mortality assumption in 2015.

The following assumptions were used to determine the benefit obligations for the plans at December 31, 2015, 2014 and 2013. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate	4.29	%		3.94	%		4.80	%		4.29	%		3.92	%		4.90	%
Rate of compensation increase			^(a)			^(a)			^(b)			^(a)			^(a)			^(b)
Mortality table	RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements
Health care cost trend on covered charges	N/A			N/A			N/A			5.50% decreasing to ultimate trend of 5.00% in 2017			6.00% decreasing to ultimate trend of 5.00% in 2017			6.00% decreasing to ultimate trend of 5.00% in 2017

_____________________________


(a)	3.25% through 2019 and 3.75% thereafter.


(b)	3.25% through 2018 and 3.75% thereafter.

The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2015, 2014 and 2013:



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate	3.94	%	^(a)	4.80	%	^(b)	3.92	%	^(c)	3.92	%	^(a)	4.90	%	^(b)	4.00	%	^(c)
Expected return on plan assets	7.00	%	^(d)	7.00	%	^(d)	7.50	%	^(d)	6.50	%	^(d)	6.59	%	^(d)	6.45	%	^(d)
Rate of compensation increase			^(e)			^(f)			^(g)			^(e)			^(f)			^(g)
Mortality table	RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements
Health care cost trend on covered charges	N/A			N/A			N/A			6.00% decreasing to ultimate trend of 5.00% in 2017			6.00% decreasing to ultimate trend of 5.00% in 2017			6.50% decreasing to ultimate trend of 5.00% in 2017

___________________________


(a)	The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2015. Discount rates for CENG's legacy pension and OPEB plans ranged from 3.68%-4.14% and 4.32%-4.43%, respectively.

(b)

The discount rates above represent the initial discount rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2014. 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 of the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.

(c)

The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these remeasurements.


(d)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.


(e)	3.25% through 2019 and 3.75% thereafter.


(f)	3.25% through 2018 and 3.75% thereafter.


(g)	3.25% through 2017 and 3.75% thereafter.

Assumed health care cost trend rates impact the other postretirement benefit plan costs reported for Exelon's participant populations with plan designs that do not have a cap on cost growth. A one percentage point change in assumed health care cost trend rates would have the following effects:



Effect of a one percentage point increase in assumed health care cost trend:
on 2015 total service and interest cost components	$	12
on postretirement benefit obligation at December 31, 2015	100
Effect of a one percentage point decrease in assumed health care cost trend:
on 2015 total service and interest cost components	(9		)
on postretirement benefit obligation at December 31, 2015	(89		)

Health Care Reform Legislation

In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisions that impact retiree health care plans provided by employers, including a provision that imposes an excise tax on certain high-cost plans whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Additional legislation was passed in December 2015 that made some changes to the law, including moving the implementation date of the excise tax from 2018 to 2020. Although the excise tax does not go into effect until 2020, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required to estimate the impact of the excise tax on Exelon’s other postretirement benefit obligation, including projected inflation rates (based on the CPI). Exelon reflected its best estimate of the expected impact in its annual actuarial valuation.

Contributions

The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans:



	Pension Benefits						Other Postretirement Benefits
	2015^(a)		2014^(a)		2013		2015		2014		2013
Generation	$	231	$	173	$	119	$	14	$	124	$	30
ComEd	143		122		118		7		125		4
PECO	40		11		11		—		5		20
BGE	1		—		—		16		17		24
BSC^(b)	47		26		91		3		20		5
Exelon	$	462	$	332	$	339	$	40	$	291	$	83

_________________________


(a)	Exelon's and Generation's pension contributions include $36 million and $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2015 and 2014, respectively.


(b)	Includes $5 million, $9 million, and $72 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2015, 2014, and 2013, respectively.

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 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Additionally, the projected contribution reflects a funding strategy of contributing the greater of $250 million until the qualified plans are fully funded on an ABO basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level funding strategy helps minimize volatility of future period required pension contributions.

Exelon plans to contribute $250 million to its qualified pension plans in 2016, of which Generation, ComEd, PECO, and BGE will contribute $134 million, $30 million, $28 million, and $31 million, respectively. Exelon's and Generation's expected qualified pension plan contributions above include $25 million related to the legacy CENG plans that will be funded by CENG as provided in an EMA between Exelon and CENG.

Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon plans to make non-qualified pension plan benefit payments of $21 million in 2016, of which Generation, ComEd, PECO, and BGE will make payments of $9 million, $2 million, $1 million and $1 million, respectively.

Unlike the qualified pension plans, other postretirement plans are not subject to statutory minimum contribution requirements. Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). In 2016, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $35 million in 2016, of which Generation, ComEd, PECO, and BGE expect to contribute $13 million, $3 million, $1 million, and $18 million, respectively.

Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2015 were:



	Pension Benefits		Other Postretirement Benefits
2016	$	1,153	$	217
2017	997		223
2018	1,009		228
2019	1,036		235
2020	1,071		244
2021 through 2025	5,923		1,341
Total estimated future benefit payments through 2025	$	11,189	$	2,488

Allocation to Exelon Subsidiaries

Generation, ComEd, PECO, and BGE account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee participation in each participating unit. Pension and other postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon began allocating costs related to its legacy Exelon pension and other postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are allocated based on accounting cost. The impact of this allocation methodology change is not material to any Registrant. For legacy CEG and legacy CENG plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be, allocated to the subsidiaries based on employee participation (both active and retired).

The amounts below were included in capital expenditures and Operating and maintenance expense for the years ended December 31, 2015, 2014 and 2013, respectively, for Generation’s, ComEd’s, PECO’s, BSC’s and BGE’s allocated portion of the pension and other postretirement benefit plan costs. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:



For the Year Ended December 31,	Generation		ComEd		PECO		BSC^(a)		BGE		Exelon
2015	$	269	$	206	$	39	$	57	$	66	637
2014	250		162		36		46		67		561
2013	347		309		43		71		55		825

_____________________


(a)	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.

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.

Exelon used an EROA of 7.00% and 6.71% to estimate its 2016 pension and other postretirement benefit costs, respectively.

Exelon’s pension and other postretirement benefit plan target asset allocations at December 31, 2015 and 2014 asset allocations were as follows:

Pension Plans



			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2015		2014
Equity securities	32	%	35	%	33	%
Fixed income securities	37	%	34		37
Alternative investments^(a)	31	%	31		30
Total			100	%	100	%

Other Postretirement Benefit Plans



			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2015		2014
Equity securities	39	%	43	%	42	%
Fixed income securities	26	%	27		34
Alternative investments^(a)	35	%	30		24
Total			100	%	100	%

___________________


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

Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2015. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2015, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.

Fair Value Measurements

The following table presents Exelon’s pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2015 and 2014:



At December 31, 2015^(a)	Level 1		Level 2		Level 3		Total
Pension plan assets
Cash equivalents	$	210	$	—	$	—	$	210
Equities^(b)	3,571		1,462		2		5,035
Fixed income:
U.S. Treasury and agencies	1,001		79		—		1,080
State and municipal debt	—		61		—		61
Corporate debt	—		2,901		165		3,066
Other^(b)	—		395		203		598
Fixed income subtotal	1,001		3,436		368		4,805
Private equity	—		—		924		924
Hedge funds	—		1,129		795		1,924
Real estate	—		—		725		725
Private credit	—		—		699		699
Pension plan assets subtotal	4,782		6,027		3,513		14,322



At December 31, 2015^(a)	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents	15		—		—		15
Equities	510		482		—		992
Fixed income:
U.S. Treasury and agencies	11		53		—		64
State and municipal debt	—		131		—		131
Corporate debt	—		44		—		44
Other	155		205		—		360
Fixed income subtotal	166		433		—		599
Hedge funds	—		312		139		451
Real estate	—		—		131		131
Private credit	—		—		103		103
Other postretirement benefit plan assets subtotal	691		1,227		373		2,291
Total pension and other postretirement benefit plan assets^(c)	$	5,473	$	7,254	$	3,886	$	16,613



At December 31, 2014^(a)	Level 1		Level 2		Level 3		Total
Pension plan assets
Cash equivalents	$	1	$	—	$	—	$	1
Equities^(b)	3,261		1,449		2		4,712
Fixed income:
U.S. Treasury and agencies	1,051		88		—		1,139
State and municipal debt	—		80		—		80
Corporate debt	—		3,125		120		3,245
Other^(b)	—		930		152		1,082
Fixed income subtotal	1,051		4,223		272		5,546
Private equity	—		—		900		900
Hedge funds	—		1,355		785		2,140
Real estate	243		—		685		928
Private credit	—		—		607		607
Pension plan assets subtotal	4,556		7,027		3,251		14,834



At December 31, 2014^(a)	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents	11		—		—		11
Equities	480		525		—		1,005
Fixed income:
U.S. Treasury and agencies	15		59		—		74
State and municipal debt	—		197		—		197
Corporate debt	—		42		—		42
Other	253		272		—		525
Fixed income subtotal	268		570		—		838
Hedge funds	—		339		—		339
Real estate	8		—		116		124
Private credit	—		—		110		110
Other postretirement benefit plan assets subtotal	767		1,434		226		2,427
Total pension and other postretirement benefit plan assets^(c)	$	5,323	$	8,461	$	3,477	$	17,261

__________________________


(a)	See Note 12—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)

Includes derivative instruments of $5 million and $(3) million, which have a total notional amount of $1,774 million and $1,491 million at December 31, 2015 and 2014, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.


(c)	Excludes net assets of $27 million and $42 million at December 31, 2015 and 2014, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.

The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2015 and 2014:



	Hedge funds			Private equity			Real estate			Fixed income			Equities		Private Credit			Total
Pension Assets
Balance as of January 1, 2015	$	785		$	900		$	685		$	272		$	2	$	607		$	3,251
Actual return on plan assets:
Relating to assets still held at the reporting date	(39		)	60			76			(14		)	—		(19		)	64
Relating to assets sold during the period	4			—			9			—			—		—			13
Purchases, sales and settlements:
Purchases	104			186			116			125			—		200			731
Sales	(57		)	—			(54		)	(7		)	—		(5		)	(123		)
Settlements^(a)	(2		)	(222		)	(107		)	(8		)	—		(84		)	(423		)
Balance as of December 31, 2015	$	795		$	924		$	725		$	368		$	2	$	699		$	3,513
Other Postretirement Benefits
Balance as of January 1, 2015	$	—		$	—		$	116		$	—		$	—	$	110		$	226
Actual return on plan assets:
Relating to assets still held at the reporting date	1			—			15			—			—		(7		)	9
Purchases, sales and settlements:
Purchases	138			—			62			—			—		—			200
Settlements^(a)	—			—			(62		)	—			—		—			(62		)
Balance as of December 31, 2015	$	139		$	—		$	131		$	—		$	—	$	103		$	373



	Hedge funds			Private equity			Real estate			Fixed income			Equities		Private credit			Total
Pension Assets
Balance as of January 1, 2014	$	706		$	806		$	544		$	41		$	2	$	371		$	2,470
Actual return on plan assets:
Relating to assets still held at the reporting date	59			112			81			7			—		20			279
Relating to assets sold during the period	2			—			—			—			—		1			3
Purchases, sales and settlements:
Purchases	74			169			112			227			—		265			847
Sales	(25		)	—			(19		)	(3		)	—		(13		)	(60		)
Settlements^(a)	(1		)	(203		)	(60		)	—			—		(37		)	(301		)
Transfers into (out of) Level 3^(b)(c)	(30		)	16			27			—			—		—			13
Balance as of December 31, 2014	$	785		$	900		$	685		$	272		$	2	$	607		$	3,251
Other Postretirement Benefits
Balance as of January 1, 2014	$	—		$	2		$	109		$	—		$	—	$	4		$	115
Actual return on plan assets:
Relating to assets still held at the reporting date	—			—			13			—			—		1			14
Purchases, sales and settlements:
Purchases	—			1			1			—			—		109			111
Sales	—			(2		)	(7		)	—			—		(4		)	(13		)
Settlements^(a)	—			(1		)	—			—			—		—			(1		)
Balance as of December 31, 2014	$	—		$	—		$	116		$	—		$	—	$	110		$	226

________________________


(a)	Represents cash settlements only.


(b)	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.

(c)

As of January 1, 2015 and January 1, 2014, hedge fund investments that contained redemption restrictions limiting Exelon’s ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2014, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $43 million in 2014.

There were no transfers between Level 1 and Level 2 during the twelve months ended December 31, 2015 for the pension and other postretirement benefit plan assets.

Valuation Techniques Used to Determine Fair Value

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

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

Equity commingled funds and mutual funds are maintained by investment companies that hold certain investments in accordance with a stated set of fund objectives, which are consistent with the plans’ overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Certain fixed income commingled funds are valued using the NAV per fund share, which is based on the valuation of the underlying investments and include significant unobservable inputs. These funds have been categorized as Level 3.

Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highly observable, private equity investments have been categorized as Level 3.

Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or ownership interest of the investments. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate. For Exelon’s investments that have terms that allow redemption within a reasonable period of time from the measurement date, the hedge fund investments are categorized as Level 2. For investments that have restrictions that may limit Exelon’s ability to redeem the investments at the measurement date or within a reasonable period of time, the hedge fund investments are categorized as Level 3.

Real estate. Real estate funds are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, these real estate funds have been categorized as Level 3.

Private credit. Private credit investments primarily consist of limited partnerships that invest in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator and include unobservable inputs such as cost, operating results, and discounted cash flows. Since the valuation inputs are not highly observable, private credit investments have been categorized as Level 3.

Defined Contribution Savings Plan (Exelon, Generation, ComEd, PECO and BGE)

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2015, 2014 and 2013:



For the Year Ended December 31,	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		BSC^(b)
2015	$	148	$	80	$	32	$	11	$	14	$	11
2014	103		51		26		8		8		10
2013	85		40		22		8		8		7

_________________________


(a)	Includes $9 million and $5 million related to CENG for the year ended December 31, 2015, and for the period from April 1, 2014 to December 31, 2014, respectively.


(b)	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 (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Restructuring and Related Activities [Abstract]

Severance (Exelon, Generation, ComEd and PECO)

(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.

Ongoing Severance Plans

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

For the years ended December 31, 2015, 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:

Severance Benefits ^(a)

Severance Charges-2015

Severance Charges-2014

Severance Charges-2013

________________________


(a)	The amounts above for Generation include $1 million, $1 million, and $2 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2015, December 31, 2014, and December 31, 2013, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material.

The severance liability balances associated with these ongoing severance benefits as of December 31, 2015 and 2014 are not material.

Shareholder Equity (Exelon, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

19. Shareholder's Equity (Exelon, ComEd, PECO and BGE)

The following table presents common stock authorized and outstanding as of December 31, 2015 and 2014:



				December 31,
				2015	2014
	Par Value		Shares Authorized	Shares Outstanding
Common Stock
Exelon	no par value		2,000,000,000	919,924,742	859,833,343
ComEd	$	12.50	250,000,000	127,016,973	127,016,947
PECO	no par value		500,000,000	170,478,507	170,478,507
BGE	no par value		175,000,000	1,000	1,000

ComEd had 73,434 and 73,533 warrants outstanding to purchase ComEd common stock at December 31, 2015 and 2014, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2015 and 2014, 24,478 and 24,511 shares of common stock, respectively, were reserved for the conversion of warrants.

Equity Securities Offering

In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreement by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. Use of net proceeds will be to fund the pending merger with PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS using the treasury stock method.

Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. See Note 14 — Debt and Credit Agreements for further information on the equity units.

Share Repurchases

Share Repurchase Programs. There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the previous share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2015. During 2015, 2014 and 2013, Exelon had no common stock repurchases.

Preferred and Preference Securities of Subsidiaries

At December 31, 2015 and 2014, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.

At December 31, 2015 and 2014, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding.

At December 31, 2015 and 2014, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized of which 1,900,000 are outstanding as set forth in the table below. Shares of BGE preference stock have no voting power except for the following:

•

The preference stock has one vote per share on any charter amendment that i) with regards to either dividends or distribution of assets, would create or authorize any shares of stock ranking prior to or on a parity with the preference stock or ii) substantially adversely affect the contract rights, as expressly set forth in BGE’s charter, of the preference stock. Each such amendment would require the affirmative vote of two-thirds of all the shares of preference stock outstanding; and

•

Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.



			December 31,
	Redemption Price ^(a)		2015	2014	2015		2014
	Redemption Price ^(a)		Shares Outstanding		Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.00	400,000	400,000	$	40	$	40
6.97%, 1993 Series	100.00		500,000	500,000	50		50
6.70%, 1993 Series	100.00		400,000	400,000	40		40
6.99%, 1995 Series	100.00		600,000	600,000	60		60
Total preference stock			1,900,000	1,900,000	$	190	$	190

______________________


(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
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Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

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

12 Months Ended

Dec. 31, 2015

Stock-Based Compensation Plans

(Exelon, Generation, ComEd, PECO and BGE)

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2015, there were approximately 16 million shares authorized for issuance under the LTIP. For the years ended December 31, 2015, 2014 and 2013, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

The Compensation Committee of Exelon’s Board of Directors changed the mix of awards granted under the LTIP in 2013 by eliminating stock options in favor of the use of full value shares, consisting of 67% performance shares and 33% restricted stock units. The performance share awards granted in 2013 will cliff vest at the end of a three-year performance period. The performance share awards granted in 2012 and earlier had a one-year performance period and vested ratably over three years. To address the reduction in annual award opportunity resulting from the transition to a three-year cliff vesting performance period, the Compensation Committee also approved a one-time grant of performance share transition awards in 2013, which vested one-third after one year, with the remaining balance vesting over a two-year performance period. These one-time 2013 performance share transition awards will be settled 50% in common stock and 50% in cash, except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain Exelon stock ownership requirements are satisfied. In addition to this change, in 2013 ComEd and in 2014 PECO and BGE transitioned from Exelon stock-based awards to cash award programs with payouts based on the performance of each respective utility. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable accounting guidance.

The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
Components of Stock-Based Compensation Expense	2015			2014			2013
Performance share awards	$	41		$	59		$	48
Restricted stock units	71			61			61
Stock options	1			2			3
Other stock-based awards	6			5			6
Total stock-based compensation expense included in operating and maintenance expense	119			127			118
Income tax benefit	(46		)	(47		)	(44		)
Total after-tax stock-based compensation expense	$	73		$	80		$	74

The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
Subsidiaries	2015		2014		2013
Generation	$	64	$	52	$	48
ComEd	6		7		9
PECO	3		3		5
BGE	3		5		6
BSC ^(a)	43		60		50
Total	$	119	$	127	$	118

________________________


(a)	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 years ended December 31, 2015, 2014 and 2013.

Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The following table presents information regarding Exelon’s tax benefits for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Realized tax benefit when exercised/distributed:
Restricted stock units	$	30	$	17	$	11
Performance share awards	18		11		11
Stock deferral plan	—		—		1

Stock Options

Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were no stock options granted in 2013, 2014 or 2015. For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant.

The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.

The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the year ended 2012:



	Year ended December 31, 2012
Dividend yield	5.28	%
Expected volatility	23.20	%
Risk-free interest rate	1.30	%
Expected life (years)	6.25
Weighted average grant date fair value (per share)	4.18

The assumptions above relate to Exelon stock options granted in 2012 and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended 2012.

The dividend yield is based on several factors, including Exelon’s most recent dividend payment at the grant date and the average stock price over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following table presents information with respect to stock option activity for the year ended December 31, 2015:



	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2014	18,830,967		$	46.85
Options exercised	(7,133	)	21.25
Options forfeited	(5,250	)	39.81
Options expired	(3,245,827	)	47.75
Balance of shares outstanding at December 31, 2015	15,572,757		$	46.68	3.85	$	9
Exercisable at December 31, 2015 (a)	15,490,507		$	46.72	3.84	$	9

____________________


(a)	Includes stock options issued to retirement eligible employees.

The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Intrinsic value^(a)	$	—	$	3	$	4
Cash received for exercise price	—		7		19

______________________


(a)	The difference between the market value on the date of exercise and the option exercise price.

The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2015:



	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2014 (a)	432,035		$	39.91
Vested	(344,535	)	39.93
Forfeited	(5,250	)	39.81
Nonvested at December 31, 2015 (a)	82,250		$	39.81

_____________________


(a)	Excludes 279,000 and 746,140 of stock options issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.

At December 31, 2015, $0.1 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of less than a year.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2015:



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2014 (a)	3,758,218		$	31.27
Granted	2,132,856		36.55
Vested	(1,597,255	)	32.88
Forfeited	(76,232	)	33.06
Undistributed vested awards^(b)	(654,333	)	35.35
Nonvested at December 31, 2015 (a)	3,563,254		$	32.92

_______________________


(a)	Excludes 1,097,630 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.


(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2015.

The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2015, 2014 and 2013 was $36.55, $28.71 and $31.06, respectively. At December 31, 2015 and 2014, Exelon had obligations related to outstanding restricted stock units not yet settled of $97 million and $85 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2015, 2014 and 2013, Exelon settled restricted stock units with fair value totaling $75 million, $43 million and $28 million, respectively. At December 31, 2015, $56 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2 years.

Performance Share Awards

Performance share awards are granted under the LTIP. The 2015 and 2014 performance share awards are being settled 50% in common stock and 50% in cash at the end of the three-year performance period except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period.

The common stock portion of the performance share and one-time 2013 performance share transition awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.

For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant.

The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2015:



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2014 (a)	2,696,097		$	30.62
Granted	1,556,273		35.88
Change in performance	(118,398	)	35.88
Vested	(704,141	)	32.80
Forfeited	(52,167	)	32.25
Undistributed vested awards ^(b)	(820,505	)	33.95
Nonvested at December 31, 2015 (a)	2,557,159		$	31.88

_______________________


(a)	Excludes 1,817,883 and 1,535,791 of performance share awards issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.


(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2015.

The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2015, 2014 and 2013 was $35.88, $28.75, and $31.55, respectively. During the years ended December 31, 2015, 2014 and 2013, Exelon settled performance shares with a fair value totaling $46 million, $27 million and $26 million, respectively, of which $29 million, $13 million and $12 million was paid in cash, respectively. As of December 31, 2015, $27 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.4 years.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:



	December 31,
	2015		2014
Current liabilities^(a)	$	28	$	28
Deferred credits and other liabilities ^(b)	32		36
Common stock	35		33
Total	$	95	$	97

__________________________


(a)	Represents the current liability related to performance share awards expected to be settled in cash.


(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share and Equity (Exelon)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Earnings Per Share and Equity (Exelon)

(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, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of the stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:



	Year Ended December 31,
	2015		2014		2013
Net income attributable to common shareholders	$	2,269	$	1,623	$	1,719
Weighted average common shares outstanding—basic	890		860		856
Assumed exercise and/or distributions of stock-based awards	3		4		4
Weighted average common shares outstanding—diluted	893		864		860

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 16 million in 2015, 17 million in 2014, and 20 million in 2013. The number of equity units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was 3 million for the year ended December 2015 and less than 1 million for the year ended December 31, 2014. Additionally, there were no forward units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the years ended December 31, 2015 and 2014. Refer to Note 19 — Shareholder's Equity for further information regarding the equity units and equity forward units.

Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31, 2015. In 2008, Exelon management decided to defer indefinitely any share repurchases.

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

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

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

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

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2015 and 2014:



For the Year Ended December 31, 2015	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	$	(28	)	$	3	$	(2,640	)	$	(19	)	$	—		$	(2,684	)
OCI before reclassifications	(12		)	—		(100		)	(21		)	(3		)	(136		)
Amounts reclassified from AOCI ^(b)	21			—		175			—			—			196
Net current-period OCI	9			—		75			(21		)	(3		)	60
Ending balance	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)
Generation ^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—		$	(36	)
OCI before reclassifications	(8		)	—		—			(21		)	(3		)	(32		)
Amounts reclassified from AOCI ^(b)	5			—		—			—			—			5
Net current-period OCI	(3		)	—		—			(21		)	(3		)	(27		)
Ending balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
PECO ^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI ^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1



For the Year Ended December 31, 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	(31		)	(1		)	(498		)	(9		)	11			(528		)
Amounts reclassified from AOCI ^(b)	(117		)	2			118			—			(119		)	(116		)
Net current-period OCI	(148		)	1			(380		)	(9		)	(108		)	(644		)
Ending balance	$	(28	)	$	3		$	(2,640	)	$	(19	)	$	—		$	(2,684	)
Generation ^(a)
Beginning balance	$	114		$	2		$	—		$	(10	)	$	108		214
OCI before reclassifications	(15		)	(1		)	—			(9		)	11			(14		)
Amounts reclassified from AOCI ^(b)	(117		)	—			—			—			(119		)	(236		)
Net current-period OCI	(132		)	(1		)	—			(9		)	(108		)	(250		)
Ending balance	$	(18	)	$	1		$	—		$	(19	)	$	—		$	(36	)
PECO ^(a)
Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1
OCI before reclassifications	—			—			—			—			—			—
Amounts reclassified from AOCI ^(b)	—			—			—			—			—			—
Net current-period OCI	—			—			—			—			—			—
Ending balance	$	—		$	1		$	—		$	—		$	—		$	1

_______________________


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


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

ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2015 and 2014. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2015 and 2014:

For the Year Ended December 31, 2015



Details about AOCI components	Items reclassified out of AOCI ^(a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Terminated interest rate swaps	$	(26	)	$	—		Other, net
Energy related hedges	2			2			Operating revenues
Other cash flow hedges	(11		)	(11		)	Interest expense
Total before tax	(35		)	(9		)
Tax benefit	14			4
Net of tax	$	(21	)	$	(5	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	74		$	—
Actuarial losses^(b)	(361		)	—
Total before tax	(287		)	—
Tax benefit	112			—
Net of tax	$	(175	)	$	—

Total Reclassifications	$	(196	)	$	(5	)	Comprehensive income

For the Year Ended December 31, 2014



Details about AOCI components	Items reclassified out of AOCI ^(a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Energy related hedges	$	195		$	195		Operating revenues
Total before tax	195			195
Tax expense	(78		)	(78		)
Net of tax	$	117		$	117		Comprehensive income

Gains and (losses) on available for sale securities
Other available securities for sale	$	(2	)	$	—		Other Income and Deductions
Total before tax	(2		)	—
Net of tax	$	(2	)	$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	46		$	—
Actuarial losses^(b)	(239		)	—
Total before tax	(193		)	—
Tax benefit	75			—
Net of tax	$	(118	)	$	—		Comprehensive income

Equity investments
Sale of equity method investment	$	5		$	5		Equity in losses of unconsolidated affiliates
Reversal of CENG equity method AOCI	193			193			Gain on Consolidation of CENG
Total before tax	198			198
Tax expense	(79		)	(79		)
Net of tax	$	119		$	119

Total Reclassifications	$	116		$	236		Comprehensive income

_____________________


(a)	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 17 — Retirement Benefits for additional details).


(c)	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2015 and 2014:



	For the Years Ended December 31,
	2015			2014			2013
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	30		$	19		$	—
Actuarial loss reclassified to periodic cost	(140		)	(93		)	(133		)
Pension and non-pension postretirement benefit plan valuation adjustment	62			317			(430		)
Change in unrealized (gain) loss on cash flow hedges	(6		)	96			166
Change in unrealized (gain) loss on equity investments	1			73			(71		)
Total	$	(53	)	$	412		$	(468	)

Generation
Change in unrealized loss on cash flow hedges	$	2		$	84		$	262
Change in unrealized (gain) loss on equity investments	1			73			(72		)
Total	$	3		$	157		$	190

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

12 Months Ended

Dec. 31, 2015

Commitments and Contingencies Disclosure [Abstract]

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

(Exelon, Generation, ComEd, PECO and BGE)

Commitments

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.

The direct investment commitment also includes $500 million to $600 million relating to Exelon and Generation’s development or assistance in the development of 275 - 300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years. Exelon and Generation have incurred $393 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date. 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 or certain specified provisions are elected, 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. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation now believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. While this $44 million loss contingency represents Generation’s best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant.

Equity Investment Commitments

As part of Generation's recent investments in technology development, Generation enters into equity purchase agreements that include commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated companies. The commitment includes approximately $20 million of in-kind services and 100% of 2015 ESA Investco, LLC’s equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 2 - Variable Interest Entities for additional details). As of December 31, 2015, Generation’s estimated commitment relating to its equity purchase agreements, including in-kind services contributions, is anticipated to be as follows:



	Total
2016 (a)	$	299
2017	21
2018	7
2019	—
Total	$	327

___________________________


(a)	The noncontrolling interest holder of 2015 ESA Investco, LLC will contribute up to $172 million in support of a portion of this equity commitment.

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	1,583	$	1,565	$	5	$	—	$	—	$	13	$	—
Surety bonds^(b)	809		733		49		3		2		16		6
Financing trust guarantees ^(c)	628		—		—		—		—		—		628
Energy marketing contract guarantees ^(d)	3,126		3,126		—		—		—		—		—
Nuclear insurance premiums ^(e)	3,060		—		—		—		—		—		3,060
Total commercial commitments	$	9,206	$	5,424	$	54	$	3	$	2	$	29	$	3,694

___________________________


(a)	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.

(d)

Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.1 billion of guarantees issued by Exelon and Generation on behalf of its Constellation businesses to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.5 billion at December 31, 2015, which represents the total amount Exelon could be required to fund based on December 31, 2015 market prices.

(e)

Nuclear insurance premiums—Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site 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.

Generation’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	1,503	$	1,485	$	5	$	—	$	—	$	13	$	—
Surety bonds	737		692		45		—		—		—		—
Energy marketing contract guarantees ^(b)	1,532		1,532		—		—		—		—		—
Nuclear insurance premiums ^(c)	3,060		—		—		—		—		—		3,060
Total commercial commitments	$	6,832	$	3,709	$	50	$	—	$	—	$	13	$	3,060

________________________


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

(b)

Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.5 billion of guarantees issued by Generation on behalf of its Constellation businesses to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.3 billion at December 31, 2015, which represents the total amount Generation could be required to fund based on December 31, 2015 market prices.

(c)

Nuclear insurance premiums — 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.

ComEd’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	16	$	16	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	8		6		—		2		—		—		—
Financing trust guarantees ^(c)	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	22	$	—	$	2	$	—	$	—	$	200

_________________________


(a)	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.

PECO’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	9		9		—		—		—		—		—
Financing trust guarantees ^(c)	178		—		—		—		—		—		178
Total commercial commitments	$	209	$	31	$	—	$	—	$	—	$	—	$	178

________________________


(a)	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

BGE’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	10		10		—		—		—		—		—
Financing trust guarantees ^(c)	250		—		—		—		—		—		250
Total commercial commitments	$	262	$	12	$	—	$	—	$	—	$	—	$	250

________________________


(a)	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.

Leases

Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2015 were:



	Exelon ^(a)		Generation^(a)(b)		ComEd ^(c)		PECO ^(c)		BGE ^(c)(d)
2016	$	133	$	86	$	14	$	3	$	12
2017	109		69		9		3		10
2018	86		57		5		2		9
2019	74		45		5		2		8
2020	70		44		3		2		7
Remaining years	702		655		1		—		19
Total minimum future lease payments	$	1,174	$	956	$	37	$	12	$	65

______________________


(a)	Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.

(b)

The Generation column above includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2015. Generation’s total commitments under the lease agreement are $4 million, $10 million, $11 million, $13 million, $14 million, and $271 million related to years 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.

(c)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, and BGE’s annual obligation for these arrangements, included in each of the years 2016—2020, was $2 million, $3 million, and $1 million respectively.


(d)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2015, 2014 and 2013:



For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE
2015	$	922	$	851	$	12	$	9	$	32
2014	865		806		15		14		12
2013	806		744		15		21		11

__________________________

(a)

Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $798 million, $755 million and $694 million during 2015, 2014 and 2013, respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.

For information regarding capital lease obligations, see Note 14—Debt and Credit Agreements.

Nuclear Insurance

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 mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2015, the current liability limit per incident is $13.5 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 December 31, 2015, 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 103 reactors) resulting in an additional $13.1 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 $13.5 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG.

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

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the distribution declared by NEIL is estimated to be $20.7 million for 2015, and was $18.3 million for 2014 and $18.5 million for 2013. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). NEIL has never exercised this assessment since its formation in 1973, and while Generation cannot predict the level of future assessments, or if they will be imposed at all, as of December 31, 2015, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $365 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

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

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

Spent Nuclear Fuel Obligation

Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the year ended December 31, 2015, Generation did not incur any expense in SNF disposal fees. For the year ended December 31, 2014 and 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). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively 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 has been, and is expected to be, delayed significantly.

The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama administration devised a new strategy for long-term SNF management. A Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s spent nuclear fuel and high-level radioactive waste.

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that is planned to be operational in 2025.

Generation uses the 2025 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear decommissioning asset retirement obligations.

In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Settlement agreements pertaining to Calvert Cliffs and Ginna were executed during 2011, and Nine Mile Point during 2012, (the “DOE Settlement Agreements”), as amended in 2014 for Calvert Cliffs and Nine Mile Point, under which the government has agreed to reimburse the costs associated with SNF storage expended or to be expended through 2016 as a result of the DOE delays. The DOE Settlement Agreement is expected to be amended for Ginna in a similar manner as needed. Generation, including CENG, submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.

Under the settlement agreement, Generation has received cumulative cash reimbursements for costs incurred as follows:

_____________________________


(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.


(b)	Includes $53 million and $49 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.

As of December 31, 2015, and 2014, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:

_____________________________


(a)	Recorded in Accounts receivable, other.


(b)	Recorded in Deferred debits and other assets, other


(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2015, the unfunded SNF liability for the one-time fee with interest was $1,021 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2015, was 0.112%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 12 — Fair Value of Financial Assets and Liabilities for additional information.

Environmental Matters

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, there are additional PRPs that may share responsibility for the ultimate remediation of each location.


•	ComEd has identified 42 sites, 17 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 25 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 2020.


•	PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites 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 2021.

•

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. An investigation of an additional gas purification site was completed during the first quarter of 2015 at the direction of the MDE. For more information, see the discussion of the Riverside site below.

ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. See Note 3 — Regulatory Matters for additional information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of the 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.

As of December 31, 2015 and 2014, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:



December 31, 2015	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation ^(a)
Exelon	$	369	$	301
Generation	63		—
ComEd	266		264
PECO	37		35
BGE ^(a)	3		2



December 31, 2014	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	347	$	277
Generation	63		—
ComEd	238		235
PECO	45		42
BGE	1		—

_____________________________


(a)	For BGE, includes reserve for Riverside, a gas purification site. See discussion below for additional information.

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

During the third quarter of 2015, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. For ComEd, the results of the study resulted in a $50 million increase to ComEd's environmental liabilities and related regulatory assets. The increase at ComEd was primarily driven by refined assumptions and scopes based on further experience and analysis, including one site where a new option is being considered for a facility under which contamination exists and certain sites where another PRP leads the remediation efforts and ComEd shares responsibility. For PECO, the results of the study resulted in a $1 million decrease to PECO's environmental liabilities and related regulatory assets.

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

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 December 31, 2015 and 2014, Generation’s remaining groundwater contamination reserve was $12 million and $13 million respectively.

Air Quality

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. A settlement was reached in January 2015, to resolve the claims related to the coal rail car lease for approximately $14 million and Exelon recorded a gain upon receipt of the funds, within Operating and maintenance expense in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income. No further action is expected related to the rail car lease.

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.

Generation increased its reserve for asbestos-related bodily injury claims pertaining to Midwest Generations’ share of liability as a result of the rejection of the asbestos cost sharing agreement in the bankruptcy proceedings. Exelon and Generation may be entitled to damages associated with the rejection of the agreement and a claim has been filed by Exelon for such damages. These amounts are considered to be contingent gains and would not be recognized until realized.

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 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 December 31, 2015. 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.

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. 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. Since, June 2012, the U.S. EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study, that are now scheduled to be completed in mid-2016 to enable the EPA to propose a remedy for public comment by the end of 2016. 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. The U.S. EPA is also reviewing a partial excavation remedy; however, until the current sampling is concluded there is no basis to determine the likelihood and estimate of a partial excavation remedy. The current estimated cost of the landfill cover remediation for the site is approximately $60 million, which will be allocated among all PRPs. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is underway. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability.

During December 2015, the U.S. EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation of a non-combustible interim surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. The second action involved EPA’s public statement that it will require the PRPs to construct a barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, EPA has not provided sufficient details related to the basis for and the requirements and design of a barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that it will be making a contribution claim against Cotter for costs that it has incurred to prevent the subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Generation and Exelon do not possess sufficient information to assess this claim and are therefore unable to determine the impact on their future results of operations and cash flows.

On February 2, 2015, the U.S. Senate passed a bill to transfer remediation authority over the West Lake landfill from the U.S. EPA to the U.S. Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). Such legislation would become final upon passage in the U.S. House of Representatives and the signature of the President, and be subject to annual funding appropriations in the U.S. Budget. Remediation under FUSRAP would not alter the liability of the PRPs, but could delay the determination of a final remedy and its implementation.

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 2016 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.

Commencing in February 2012, 37 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, and Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to Cotter's 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. 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. The court has dismissed the lawsuits filed by 30 of the plaintiffs. Pre-trial motions and discovery are proceeding in the remaining cases and a proposed pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd 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 PRPs 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), a wholly-owned subsidiary of Generation. 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 $9 million, which has been fully reserved as of December 31, 2015.

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 PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRPs 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.

Riverside. In 2013, the Maryland Department of the Environment (MDE), at the request of U.S. EPA, conducted a site inspection and limited environmental sampling of certain portions of the 170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an investigation of three specific areas of the site, and a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time. Upon completion of the investigation the MDE will determine if the site requires further action and/or remediation. Based upon the investigation to date, BGE has established what it believes is an appropriate reserve. As the investigation and potential remediation proceed, it is possible that additional reserves could be established, in amounts that could be material to BGE.

Litigation and Regulatory Matters

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 December 31, 2015 and 2014, Generation had reserved approximately $95 million and $100 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2015, approximately $21 million of this amount related to 228 open claims presented to Generation, while the remaining $74 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.

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

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

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material 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 454 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. As of December 31, 2015 and 2014, ComEd did not have any material liabilities recorded for these storm events.

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 alleged that ComEd violated the Telephone Consumer Protection Act (TCPA) by sending text messages to customers without first obtaining their consent to receive such messages. The complaint sought certification of a class along with statutory damages, attorneys’ fees, and an order prohibiting ComEd from sending additional text messages. ComEd and the plaintiff agreed in principle to settle the suit for $5 million, with payments to the class commencing in the fourth quarter 2015.

Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO and BGE)

Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.

The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.

Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.

PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. On May 1, 2013, PECO redeemed all outstanding preferred securities. As a result, the above ratio calculation is no longer applicable. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.

BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid.

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 15 — 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)

12 Months Ended

Dec. 31, 2015

Supplemental Financial Information [Abstract]

Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)

24. 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 years ended December 31, 2015, 2014 and 2013.



For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	474	$	105	$	236	$	133	$	85
Property	407		250		27		11		119
Payroll	201		118		28		14		16
Other	118		16		5		2		4
Total taxes other than income	$	1,200	$	489	296		$	160	$	224



For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	456	$	89	$	238	$	128	$	86
Property	396		240		25		15		114
Payroll	200		118		28		14		18
Other	102		18		2		2		3
Total taxes other than income	$	1,154	$	465	$	293	$	159	$	221



For the year ended December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	449	$	79	$	241	$	129	$	82
Property	302		205		24		14		112
Payroll	159		89		27		13		15
Other	185		16		7		2		4
Total taxes other than income	$	1,095	$	389	$	299	$	158	$	213

_____________________

(a)

Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.



For the year ended December 31, 2015	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	232		$	232		$	—	$	—		$	—
Non-regulatory agreement units	156			156			—		—			—
Net unrealized losses on decommissioning trust funds—
Regulatory agreement units	(282		)	(282		)	—		—			—
Non-regulatory agreement units	(197		)	(197		)	—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	7			7			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)	21			21			—		—			—
Total decommissioning-related activities	(63		)	(63		)	—		—			—
Investment income (loss)	8			3			—		(2		)	4		^(c)
Long-term lease income	15			—			—		—			—
Interest income related to uncertain income tax positions	1			1			—		—			—
AFUDC—Equity	24			—			5		5			14
Terminated interest rate swaps ^(d)	(26		)	—			—		—			—
PHI merger related debt exchange ^(e)	(22		)	—			—		—			—
Other	17			(1		)	16		2			—
Other, net	$	(46	)	$	(60	)	$	21	$	5		$	18



For the year ended December 31, 2014	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	216		$	216		$	—	$	—		$	—
Non-regulatory agreement units	159			159			—		—			—
Net unrealized gains on decommissioning trust funds—
Regulatory agreement units	180			180			—		—			—
Non-regulatory agreement units	134			134			—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	29			29			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)	(358		)	(358		)	—
Total decommissioning-related activities	360			360			—		—			—
Investment income	1			1			—		(1		)	7			^(c)
Long-term lease income	24			—			—		—			—
Interest income related to uncertain income tax positions	40			54			—		—			—
AFUDC—Equity	21			—			3		6			12
Other	9			(9		)	14		2			(1		)
Other, net	$	455		$	406		$	17	$	7		$	18



For the year ended December 31, 2013	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	256		$	256		$	—	$	—		$	—
Non-regulatory agreement units	77			77			—		—			—
Net unrealized gains on decommissioning trust funds—
Regulatory agreement units	406			406			—		—			—
Non-regulatory agreement units	146			146			—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	7			7			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)	(546		)	(546		)	—					—
Total decommissioning-related activities	346			346			—		—			—
Investment income	8			(1		)	—		(1		)	9		^(c)
Long-term lease income	28			—			—		—			—
Interest income related to uncertain income tax positions	24			4			—		—			—
AFUDC—Equity	22			—			11		4			7
Other	32			6			15		3			1
Other, net	$	460		$	355		$	26	$	6		$	17

_________________________


(a)	Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning 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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.

(d)

In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.


(e)	See Note 14—Debt and Credit Agreements and 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013.



For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	2,227	$	1,007	$	635	$	240	$	289
Regulatory assets	170		—		72		20		77
Amortization of intangible assets, net	54		47		—		—		—
Amortization of energy contract assets and liabilities^(a)	22		22		—		—		—
Nuclear fuel^(b)	1,116		1,116		—		—		—
ARO accretion^(c)	398		397		—		—		—
Total depreciation, amortization, accretion and depletion	$	3,987	$	2,589	$	707	$	260	$	366



For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	2,080	$	922	$	588	$	227	$	288
Regulatory assets	191		—		99		9		83
Amortization of intangible assets, net	44		44		—		—		—
Amortization of energy contract assets and liabilities^(a)	135		135		—		—		—
Nuclear fuel^(b)	1,073		1,073		—		—		—
ARO accretion^(c)	345		345		—		—		—
Total depreciation, amortization, accretion and depletion	$	3,868	$	2,519	$	687	$	236	$	371



For the year ended December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,893	$	813	$	545	$	219	$	264
Regulatory assets	212		—		119		9		84
Amortization of intangible assets, net	48		43		5		—		—
Amortization of energy contract assets and liabilities^(a)	430		507		—		—		—
Nuclear fuel^(b)	921		921		—		—		—
ARO accretion^(c)	275		275		—		—		—
Total depreciation, amortization and accretion	$	3,779	$	2,559	$	669	$	228	$	348

________________________


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


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


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



For the year ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	930		$	348		$	308		$	94		$	120
Income taxes (net of refunds)	342			476			(265		)	64			73
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	637		$	269		$	206		$	39		$	65
Loss from equity method investments	7			8			—			—			—
Provision for uncollectible accounts	120			22			53			30			15
Provision for excess and obsolete inventory	10			9			1			—			—
Stock-based compensation costs	97			—			—			—			—
Other decommissioning-related activity^(a)	(82		)	(82		)	—			—			—
Energy-related options^(b)	21			21			—			—			—
Amortization of regulatory asset related to debt costs	7			—			5			2			—
Amortization of rate stabilization deferral	73			—			—			—			73
Amortization of debt fair value adjustment	(17		)	(17		)	—			—			—
Amortization of debt costs	58			15			4			2			2
Discrete impacts from EIMA^(c)	144			—			144			—			—
Lower of cost or market inventory adjustment	23			23			—			—			—
Other	11			—			3			(3		)	(18		)
Total other non-cash operating activities	$	1,109		$	268		$	416		$	70		$	137
Non-cash investing and financing activities:
Change in PPE related to ARO update	$	885		$	885		$	—		$	—		$	—
Change in capital expenditures not paid	96			82			34			(13		)	(9		)
Non-cash financing of capital projects	77			77			—			—			—
Nuclear fuel procurement ^(d)	57			57			—			—			—
Indemnification of like-kind exchange position ^(e)	—			—			7			—			—
Long-term software licensing agreement ^(f)	95			—			—			—			—

____________________________


(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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


(c)	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 3 — Regulatory Matters for more information.


(d)	Relates to the nuclear fuel procurement contract for the purchase of fixed quantities of converted uranium, which was delivered to Generation in 2015. Generation is required to make payments starting September 28, 2018, with the final payment being due no later than September 30, 2020.


(e)	See Note 15 — Income Taxes for discussion of the like-kind exchange tax position.


(f)	Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note 14 — Debt and Credit Agreements for additional information.



For the year ended December 31, 2014	Exelon			Generation				ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	940		$	322			$	292		$	94		$	111
Income taxes (net of refunds)	314			227				(6		)	85			(21		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	560		$	249			$	162		$	36		$	64
Loss from equity method investments	22			20				—			—			—
Provision for uncollectible accounts	156			14				26			52			64
Provision for excess and obsolete inventory	5			5				—			—			—
Stock-based compensation costs	91			—				—			—			—
Other decommissioning-related activity ^(a)	(132		)	(132		)		—			—			—
Energy-related options ^(b)	122			122				—			—			—
Amortization of regulatory asset related to debt costs	11			—				8			3			—
Amortization of rate stabilization deferral	65			—				—			—			65
Amortization of debt fair value adjustment	(23		)	(23		)		—			—			—
Merger-related commitments	44			44				—			—			—
Amortization of debt costs	53			12				4			2			2
Discrete impacts from EIMA ^(c)	53			—				53			—			—
Lower of cost or market inventory adjustment	29			29				—			—			—
Other	(2		)	6				2			(1		)	(15		)
Total other non-cash operating activities	$	1,054		$	346			$	255		$	92		$	180
Non-cash investing and financing activities:
Change in PPE related to ARO update	$	72		$	72			$	—		$	—		$	—
Change in capital expenditures not paid	220			(61		)	^(d)	78			—			25
Fair value of net assets recorded upon CENG consolidation ^(e)	3,400			3,400				—			—			—
Issuance of equity units ^(f)	131			—				—			—			—
Nuclear fuel procurement ^(g)	70			70				—			—			—
Indemnification of like-kind exchange position ^(h)	—			—				5			—			—

______________________


(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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


(c)	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 3 — Regulatory Matters for more information.


(d)	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.


(e)	See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.


(f)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 20 — Stock-Based Compensation Plans for additional information.


(g)	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation in 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.


(h)	See Note 15 — Income Taxes for discussion of the like-kind exchange tax position.



For the year ended December 31, 2013	Exelon			Generation				ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	866		$	291			$	283		$	95		$	130
Income taxes (net of refunds)	112			(18		)		33			70			42
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	825		$	345			$	308		$	43		$	56
Gain from equity method investments	(10		)	(10		)		—			—			—
Provision for uncollectible accounts	101			10				(15		)	61			44
Provision for excess and obsolete inventory	9			9				—			—			—
Stock-based compensation costs	120			—				—			—			—
Other decommissioning-related activity ^(a)	(169		)	(169		)		—			—			—
Energy-related options ^(b)	104			104				—			—			—
Amortization of regulatory asset related to debt costs	12			—				9			3			—
Amortization of rate stabilization deferral	66			—				—			—			66
Amortization of debt fair value adjustment	(34		)	(34		)		—			—			—
Discrete impacts from EIMA ^(c)	(271		)	—				(271		)	—			—
Amortization of debt costs	18			10				1			2			2
Other	(53		)	5				(4		)	(1		)	(15		)
Total other non-cash operating activities	$	718		$	270			$	28		$	108		$	153
Non-cash investing and financing activities:
Change in PPE related to ARO update	$	(128	)	$	(128	)		$	—		$	—		$	4
Change in capital expenditures not paid	(38		)	(107		)	^(d)	(8		)	13			(48		)
Consolidated VIE dividend to noncontrolling interest	63			63				—			—			—
Indemnification of like-kind exchange position ^(e)	—			—				176			—			—

_________________________


(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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters.


(d)	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.


(e)	See Note 15 — Income Taxes for discussion of the like-kind exchanged tax position.

DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 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 $5 million related to PECO’s DOE SGIG programs. For the year ended December 31, 2015, PECO had no capital expenditures or reimbursements, as the DOE SGIG program was completed during 2014. For the year ended December 31, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $74 million, $27 million and $47 million, and reimbursements of $95 million, $37 million and $58 million, related to PECO’s and BGE’s DOE SGIG programs. See Note 3 — Regulatory Matters for additional information regarding the DOE SGIG.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2015 and 2014.



December 31, 2015	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8
Bloom	63		63		—		—		—
Net Power	23		23		—		—		—
Other equity method investments	4		3		—		—		—
Total equity method investments	112		89		6		8		8
Other investments:
Net investment in leases ^(b)	358		6		—		—		—
Employee benefit trusts and investments^(c)	85		31		—		20		4
Other cost method investments	55		55		—		—		—
Other available for sale investments	29		29		—		—		—
Total investments	$	639	$	210	$	6	$	28	$	12



December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8
Bloom	13		13		—		—		—
Net Power	9		9		—		—		—
Sunnyside	5		5		—		—		—
Other equity method investments	1		1		—		—		—
Total equity method investments	50		28		6		8		8
Other investments:
Net investment in leases ^(b)	367		7		—		—		—
Employee benefit trusts and investments^(c)	85		27		—		23		4
Other cost method investments	37		37		—		—		—
Other available for sale investments	5		5		—		—		—
Total investments	$	544	$	104	$	6	$	31	$	12

_________________________


(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.


(b)	Represents direct financing lease investments. See Note 8 —Impairment of Long-Lived Assets for additional information.


(c)	The Registrants’ investments in these marketable securities are recorded at fair market value.

The following tables provide additional information about liabilities of the Registrants at December 31, 2015 and 2014.



December 31, 2015	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)	$	1,014		$	547		$	183	$	66	$	57
Taxes accrued	293			186			63		4		23
Interest accrued	915			77			443		35		27
Severance accrued	21			11			3		—		1
Other accrued expenses	133			114			14		4		2
Total accrued expenses	$	2,376		$	935		$	706	$	109	$	110

December 31, 2014	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)	$	832		$	447		$	153	$	50	$	58
Taxes accrued	305			248			59		3		42
Interest accrued	240			66			102		33		29
Severance accrued	49			33			2		1		2
Other accrued expenses	113		^(b)	92		^(b)	15		4		—
Total accrued expenses	$	1,539		$	886		$	331	$	91	$	131

_______________________


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.


(b)	Includes $19 million for amounts accrued related to Antelope Valley as of December 31, 2014.

Segment Information (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

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, which include 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 power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO and BGE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO and BGE's CODMs evaluate the performance of and allocate resources to ComEd, PECO and BGE based on net income and return on equity.

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


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

•

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


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


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


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


•	Other Power Regions:

•

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


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


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

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2015, 2014, and 2013 is as follows:



	Generation ^(a)		ComEd		PECO		BGE		Other ^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2015
Competitive businesses electric revenues	$	15,944	$	—	$	—	$	—	$	—	$	(744	)	$	15,200
Competitive businesses natural gas revenues	2,433		—		—		—		—		—			2,433
Competitive businesses other revenues	758		—		—		—		—		(1		)	757
Rate-regulated electric revenues	—		4,905		2,486		2,490		—		(5		)	9,876
Rate-regulated natural gas revenues	—		—		546		645		—		(15		)	1,176
Shared service and other revenues	—		—		—		—		1,372		(1,367		)	5
2014
Competitive businesses electric revenues	$	14,533	$	—	$	—	$	—	$	—	$	(760	)	$	13,773



	Generation ^(a)			ComEd		PECO		BGE		Other ^(b)			Intersegment Eliminations			Exelon
Competitive businesses natural gas revenues	2,705			—		—		—		—			(1		)	2,704
Competitive businesses other revenues	155			—		—		—		—			(1		)	154
Rate-regulated electric revenues	—			4,564		2,448		2,460		—			(5		)	9,467
Rate-regulated natural gas revenues	—			—		646		705		—			(26		)	1,325
Shared service and other revenues	—			—		—		—		1,285			(1,279		)	6
2013
Competitive businesses electric revenues	$	13,862		$	—	$	—	$	—	$	—		$	(1,366	)	$	12,496
Competitive businesses natural gas revenues	1,721			—		—		—		—			—			1,721
Competitive businesses other revenues	47			—		—		—		—			(1		)	46
Rate-regulated electric revenues	—			4,464		2,500		2,405		—			(4		)	9,365
Rate-regulated natural gas revenues	—			—		600		660		—			(14		)	1,246
Shared service and other revenues	—			—		—		—		1,241			(1,227		)	14
Intersegment revenues^(d):
2015	$	745		$	4	$	2	$	14	$	1,367		$	(2,127	)	$	5
2014	762			4		2		25		1,280			(2,067		)	6
2013	1,367			3		1		13		1,237			(2,607		)	14
Depreciation and amortization
2015	$	1,054		$	707	$	260	$	366	$	63		$	—		$	2,450
2014	967			687		236		371		53			—			2,314
2013	856			669		228		348		52			—			2,153
Operating expenses ^(c):
2015	$	16,872		$	3,889	$	2,404	$	2,578	$	1,444		$	(2,131	)	$	25,056
2014	16,923			3,586		2,522		2,726		1,353			(2,071		)	25,039
2013	13,976			3,510		2,434		2,616		1,324			(2,618		)	21,242
Equity in earnings (losses) of unconsolidated affiliates
2015	$	(8	)	$	—	$	—	$	—	$	1		$	—		$	(7	)
2014	(20		)	—		—		—		—			—			(20		)
2013	10			—		—		—		—			—			10
Interest expense, net:
2015	$	365		$	332	$	114	$	99	$	123		$	—		$	1,033
2014	356			321		113		106		169			—			1,065
2013	357			579		115		122		183			—			1,356
Income (loss) before income taxes:
2015	$	1,850		$	706	$	521	$	477	$	(219	)	$	(5	)	$	3,330
2014	1,226			676		466		351		(227		)	(6		)	2,486
2013	1,675			401		557		344		(191		)	(13		)	2,773
Income taxes:
2015	$	502		$	280	$	143	$	189	$	(41	)	$	—		$	1,073



	Generation ^(a)		ComEd		PECO		BGE		Other ^(b)			Intersegment Eliminations			Exelon
2014	207		268		114		140		(63		)	—			666
2013	615		152		162		134		(20		)	1			1,044
Net income (loss):
2015	$	1,340	$	426	$	378	$	288	$	(177	)	$	(5	)	$	2,250
2014	1,019		408		352		211		(164		)	(6		)	1,820
2013	1,060		249		395		210		(171		)	(14		)	1,729
Capital expenditures:
2015	$	3,841	$	2,398	$	601	$	719	$	65		$	—		7,624
2014	3,012		1,689		661		620		95			—			6,077
2013	2,752		1,433		537		587		86			—			5,395
Total assets:
2015	$	46,529	$	26,532	$	10,367	$	8,295	$	15,389		$	(11,728	)	$	95,384
2014	44,951		25,358		9,860		8,056		9,711			(11,520		)	86,416

__________________________

(a)

Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended December 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $224 million and sales to BGE of $502 million in the Mid-Atlantic region, and sales to ComEd of $18 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 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)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.

(c)

For the years ended December 31, 2015, 2014 and 2013, utility taxes of $105 million, $89 million and $79 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $236 million, $238 million and $241 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $133 million, $128 million and $129 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $85 million, $86 million and $82 million are included in revenues and expenses for BGE, respectively.

(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:



	2015							2014							2013
	Revenues from external customers^(b)		Intersegment revenues			Total revenues		Revenues from external customers^(b)(d)		Intersegment revenues^(d)			Total revenues		Revenues from external customers^(b)(d)		Intersegment revenues^(d)			Total revenues
Mid-Atlantic^(a)	$	5,974	$	(74	)	$	5,900	$	5,414	$	(155	)	$	5,259	$	5,261	$	(57	)	$	5,204
Midwest	4,712		(2		)	4,710		4,488		(13		)	4,475		4,298		(28		)	4,270
New England	2,217		(5		)	2,212		1,468		(46		)	1,422		1,279		(42		)	1,237
New York	996		(11		)	985		846		(3		)	843		717		(3		)	714
ERCOT	863		(6		)	857		938		(3		)	935		1,223		(7		)	1,216
Other Power Regions	1,182		(80		)	1,102		1,379		(70		)	1,309		1,084		(116		)	968
Total Revenues for Reportable Segments	$	15,944	$	(178	)	$	15,766	$	14,533	$	(290	)	$	14,243	$	13,862	$	(253	)	$	13,609
Other ^(c)	3,191		178			3,369		2,860		290			3,150		1,768		253			2,021
Total Generation Consolidated Operating Revenues	$	19,135	$	—		$	19,135	$	17,393	$	—		$	17,393	$	15,630	$	—		$	15,630

_______________________


(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, beginning on April 1, 2014, CENG's revenues are included on a fully consolidated basis.


(b)	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $7 million increase to revenues, a $289 million decrease to revenues, and a $767 million decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2015, 2014, and 2013, respectively, unrealized mark-to-market gains of $203 million, losses of $174 million, and gains of $220 million for the years ended December 31, 2015, 2014, and 2013, respectively, and elimination of intersegment revenues.

(d)

Exelon corrected an error in the December 31, 2014 and December 31, 2013 balances within Intersegment revenues and Revenues from external customers for an overstatement of Intersegment revenues for Reportable Segments of $284 million and $252 million for the years ended December 31, 2014 and 2013, respectively, an understatement of Revenues from external customers for Reportable Segments of $284 million and $252 million for the years ended December 31, 2014 and 2013, respectively, an understatement of Intersegment revenues for Other of $284 million and $252 million for the years ended December 31, 2014 and 2013, respectively, and an overstatement of Revenues from external customers for Other of $284 million and $252 million for the years ended December 31, 2014 and 2013, respectively. The error is not considered material to any prior period, and there is no net impact to Total Revenues.

Generation total revenues net of purchased power and fuel expense:



	2015							2014									2013
	RNF from external customers^(b)		Intersegment RNF			Total RNF		RNF from external customers^(b)(d)			Intersegment RNF^d)			Total RNF			RNF from external customers^(b)(d)			Intersegment RNF^(d)			Total RNF
Mid-Atlantic^(a)	$	3,556	$	15		$	3,571	$	3,544		$	(113	)	$	3,431		$	3,287		$	(17	)	$	3,270
Midwest	2,912		(20		)	2,892		2,607			(8		)	2,599			2,606			(20		)	2,586
New England	519		(58		)	461		450			(99		)	351			299			(114		)	185
New York	584		50			634		439			44			483			(55		)	51			(4		)
ERCOT	425		(132		)	293		573			(256		)	317			627			(191		)	436
Other Power Regions	440		(190		)	250		517			(190		)	327			397			(196		)	201
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	8,436	$	(335	)	$	8,101	$	8,130		$	(622	)	$	7,508		$	7,161		$	(487	)	$	6,674
Other ^(c)	678		335			1,013		(662		)	622			(40		)	272			487			759
Total Generation Revenues net of purchased power and fuel expense	$	9,114	$	—		$	9,114	$	7,468		$	—		$	7,468		$	7,433		$	—		$	7,433

____________________________


(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, beginning on April 1, 2014, CENG's revenue net of purchased power and fuel expense are included on a fully consolidated basis.


(b)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $8 million increase in RNF, a $124 million decrease in RNF, and a $488 million decrease in RNF for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2015, 2014, and 2013, respectively, unrealized mark-to-market gains of $257 million, losses of $591 million, and gains of $504 million for the years ended December 31, 2015, 2014, and 2013, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

(d)

Exelon corrected an error in the December 31, 2014 and December 31, 2013 balances within Intersegment RNF and RNF from external customers for an understatement of $8 million and an overstatement of $134 million of Intersegment RNF for Reportable Segments for the years ended December 31, 2014 and 2013, respectively, an understatement of RNF from external customers for Reportable Segments of $11 million and $134 million for the years ended December 31, 2014 and 2013, respectively, an overstatement of $8 million and an understatement $134 million of Intersegment RNF for Other for the years ended December 31, 2014 and 2013, respectively, and an overstatement of RNF from external customers for Other of $11 million and $134 million for the years ended December 31, 2014 and 2013, respectively. This also included an understatement of total RNF for Reportable Segments and an overstatement of total RNF for Other of $19 million for the year ended December 31, 2014. The error is not considered material to any prior period, and there is no net impact to Generation Total RNF for 2013 or 2014.

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.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

(Exelon, Generation, ComEd, PECO and BGE)

Exelon

The financial statements of Exelon include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015			2014			2013
Operating revenues from affiliates:
PECO ^(a)	$	1		$	1		$	10
CENG ^(b)	—			17			56
BGE ^(a)	4			5			4
Other	4			—			—
Total operating revenues from affiliates	$	9		$	23		$	70
Purchase power and fuel from affiliates:
CENG^(c)	$	—		$	282		$	992
Keystone Fuels, LLC ^(d)	—			138			144
Conemaugh Fuels, LLC ^(d)	—			99			98
Safe Harbor Water Power Corp ^(d)	—			12			22
Total purchase power and fuel from affiliates	$	—		$	531		$	1,256
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13		$	13
PECO Trust III	6			6			6
PECO Trust IV	6			6			6
BGE Capital Trust II	16			16			16
Total interest expense to affiliates, net	$	41		$	41		$	41
Earnings (losses) in equity method investments:
CENG ^(e)	$	—		$	(19	)	$	9
Qualifying facilities and domestic power projects	(8		)	(1		)	1
Other	$	1		$	—		$	—
Total earnings (losses) in equity method investments	$	(7	)	$	(20	)	$	10



	December 31,
	2015		2014
Payables to affiliates (current):
ComEd Financing III	$	4	$	4
PECO Trust III	1		1
BGE Capital Trust II	3		3
Total payables to affiliates (current)	$	8	$	8
Long-term debt due to financing trusts:
ComEd Financing III	$	205	$	205
PECO Trust III	81		81
PECO Trust IV	103		103
BGE Capital Trust II	252		252
Total long-term debt due to financing trusts	$	641	$	641

____________________________

(a)

The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.

(b)

Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.

(c)

CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA) not sold to third parties. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.


(d)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.

(e)

Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.

Transactions involving Generation, ComEd, PECO and BGE are further described in the tables below.

Generation

The financial statements of Generation include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015			2014			2013
Operating revenues from affiliates:
ComEd ^(a)	$	18		$	176		$	506
PECO ^(b)	224			198			405
BGE ^(c)	502			387			455
CENG ^(d)	—			17			56
BSC	1			1			1
Other	4			—			—
Total operating revenues from affiliates	$	749		$	779		$	1,423
Purchase power and fuel from affiliates:
ComEd	$	—		$	1		$	1
BGE	14			25			13
CENG ^(e)	—			282			992
Keystone Fuels, LLC ⁽ⁱ⁾	—			138			144
Conemaugh Fuels, LLC ⁽ⁱ⁾	—			99			98
Safe Harbor Water Power Corporation⁽ⁱ⁾	—			12			22
Total purchase power and fuel from affiliates	$	14		$	557		$	1,270
Operating and maintenance from affiliates:
ComEd ^(f)	$	4		$	3		$	2
PECO ^(f)	2			2			1
BSC ^(g)	614			618			571
Total operating and maintenance from affiliates	$	620		$	623		$	574
Interest expense to affiliates, net:
Exelon Corporate ^(j)	$	43		$	53		$	59
Earnings (losses) in equity method investments
CENG^(h)	$	—		$	(19	)	$	9
Qualifying facilities and domestic power projects	(8		)	(1		)	1
Total earnings (losses) in equity method investments	$	(8	)	$	(20	)	$	10
Capitalized costs
BSC ^(g)	$	76		$	91		$	93
Cash distribution paid to member	$	2,474		$	645		$	625
Contribution from member	$	47		$	53		$	26



	December 31,
	2015		2014
Receivables from affiliates (current):
ComEd ^(a)	$	15	$	43
PECO ^(b)	36		29
BGE ^(c)	31		40
Other	1		1
Total receivables from affiliates (current)	$	83	$	113
Intercompany money pool (current):
Exelon Corporate	$	1,252	$	—
Long-term debt due to affiliates (current):
Exelon Corporate ^(l)	$	—	$	556
Payables to affiliates (current):
Exelon Corporate ^(j)	$	16	$	12
BSC ^(g)	78		83
ComEd	9		12
Other	1		—
Total payables to affiliates (current)	$	104	$	107
Long-term debt due to affiliates (noncurrent):
Exelon Corporate ^(l)	$	933	$	943
Payables to affiliates (noncurrent):
BSC ^(g)	$	—	$	1
ComEd ^(k)	2,172		2,389
PECO ^(k)	405		490
Total payables to affiliates (noncurrent)	$	2,577	$	2,880

_______________________


(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.


(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.


(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(d)

(e)


(f)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.


(g)	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(h)

Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.


(i)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.


(j)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.


(k)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 16—Asset Retirement Obligations.

(l)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.

ComEd

The financial statements of ComEd include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015		2014		2013
Operating revenues from affiliates
Generation	$	4	$	4	$	3
Purchased power from affiliate
Generation ^(a)	$	18	$	176	$	512
Operating and maintenance from affiliate
BSC ^(b)	$	195	$	166	$	157
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC ^(b)	$	103	$	77	$	69
Cash dividends paid to parent	$	299	$	307	$	220
Contribution from parent	$	202	$	273	$	—



	December 31,
	2015		2014
Prepaid voluntary employee beneficiary association trust ^(c)	$	11	$	13
Receivable from affiliates (current):
Voluntary employee beneficiary association trust	$	2	$	2
Generation	9		12
Exelon Corporate ^(e)	188		—
Total receivable from affiliates (current)	$	199	$	14
Receivable from affiliates (noncurrent):
Generation ^(d)	$	2,172	$	2,389
Exelon Corporate ^(e)	—		182
Total receivable from affiliates (noncurrent)	$	2,172	$	2,571
Payables to affiliates (current):
Generation ^(a)	$	15	$	43
BSC ^(b)	39		32
ComEd Financing III	4		4
PECO	2		2
Exelon Corporate	2		3
Total payables to affiliates (current)	$	62	$	84
Long-term debt to ComEd financing trust
ComEd Financing III	$	205	$	205

_______________________

(a)

ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments for additional information.


(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.


(d)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.


(e)	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.

PECO

The financial statements of PECO include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015		2014		2013
Operating revenues from affiliates:
Generation ^(a)	$	2	$	2	$	1
Purchased power from affiliate
Generation^(b)	$	220	$	194	$	392
Operating and maintenance from affiliates:
BSC ^(c)	$	107	$	96	$	98
Generation	3		3		3
Total operating and maintenance from affiliates	$	110	$	99	$	101
Interest expense to affiliates, net:
PECO Trust III	$	6	$	6	$	6
PECO Trust IV	6		6		6
Total interest expense to affiliates, net	$	12	$	12	$	12
Capitalized costs
BSC ^(c)	$	40	$	39	$	46
Cash dividends paid to parent	$	279	$	320	$	332
Contribution from parent	$	16	$	24	$	27



	December 31,
	2015		2014
Prepaid voluntary employee beneficiary association trust ^(d)	$	2	$	3
Receivable from affiliate (current):
ComEd	$	2	$	2
BGE	—		1
Total receivable from affiliates (current)	$	2	$	3
Receivable from affiliate (noncurrent):
Generation ^(e)	$	405	$	490
Payables to affiliates (current):
Generation^(b)	$	36	$	29
BSC^(c)	17		20
Exelon Corporate	1		2
PECO Trust III	1		1
Total payables to affiliates (current)	$	55	$	52
Long-term debt to financing trusts:
PECO Trust III	$	81	$	81
PECO Trust IV	103		103
Total long-term debt to financing trusts	$	184	$	184

________________________


(a)	PECO provides energy to Generation for Generation’s own use.


(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.


(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.


(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

BGE

The financial statements of BGE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015		2014		2013
Operating revenues from affiliates:
Generation ^(a)	$	14	$	25	$	13
Purchased power from affiliate
Generation ^(b)	$	498	$	382	$	452
Operating and maintenance from affiliates:
BSC ^(c)	$	118	$	103	$	83
Interest expense to affiliates, net:
BGE Capital Trust II	$	16	$	16	$	16
Capitalized costs
BSC ^(c)	$	28	$	19	$	15
Cash dividends paid to parent	$	158	$	—	$	—
Contribution from parent	$	7	$	—	$	—



	December 31,
	2015		2014
Prepaid voluntary employee beneficiary association trust ^(d)	$	—	$	1
Payables to affiliates (current):
Generation ^(b)	$	31	$	40
BSC ^(c)	17		17
Exelon Corporate	1		5
PECO	—		1
BGE Capital Trust II	3		3
Total payables to affiliates (current)	$	52	$	66
Long-term debt to BGE financing trust
BGE Capital Trust II	$	252	$	252

______________________


(a)	BGE provides energy to Generation for Generation’s own use.


(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.


(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

The entire disclosure for related party transactions. Examples of related party transactions include transactions between (a) a parent company and its subsidiary; (b) subsidiaries of a common parent; (c) and entity and its principal owners; and (d) affiliates.

Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE)

Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE)

12 Months Ended

Dec. 31, 2015

Quarterly Financial Data [Abstract]

(Unaudited) (Exelon, Generation, ComEd, PECO and BGE)

Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income						Net Income on Common Stock
	2015		2014		2015			2014			2015		2014
Quarter ended:
March 31	$	8,830	$	7,237	$	1,366	^(a)	$	168	^(b)	$	693	$	90
June 30	6,514		6,024		1,134		^(a)	842		^(b)	638		522
September 30	7,401		6,912		1,200		^(a)	1,738		^(b)	629		993
December 31	6,702		7,255		707			348			309		18		^(c)

____________________________


(a)	In the first, second, and third quarter of 2015, Exelon reclassified $(1) million, $7 million, and $2 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.


(b)	In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.


(c)	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.



	Average Basic Shares Outstanding (in millions)		Net Income per Basic Share
	2015	2014	2015		2014
Quarter ended:
March 31	862	858	$	0.80	$	0.10
June 30	863	860	0.74		0.61
September 30	913	861	0.69		1.15
December 31	921	861	0.34		0.02
	Average Diluted Shares Outstanding (in millions)		Net Income per Diluted Share
	2015	2014	2015		2014
Quarter ended:
March 31	867	861	$	0.80	$	0.10
June 30	866	864	0.74		0.60
September 30	915	863	0.69		1.15
December 31	924	868	0.33		0.02

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:



	2015								2014
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	31.37	$	34.44	$	34.98	$	38.25	$	38.93	$	36.26	$	37.73	$	33.94
Low price	25.09		28.41		31.28		31.71		33.07		30.66		33.11		26.45
Close	27.77		29.70		31.42		33.61		37.08		34.09		36.48		33.56
Dividends	0.310		0.310		0.310		0.310		0.310		0.310		0.310		0.310

Generation

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income							Net (Loss) Income on Membership Interest
	2015		2014		2015 (a)			2014				2015		2014
Quarter ended:
March 31	$	5,840	$	4,390	$	719	^(a)	$	(384	)	^(b)	$	443	$	(185	)
June 30	4,232		3,789		703		^(a)	441			^(b)	398		340
September 30	4,768		4,412		622		^(a)	1,225			^(b)	377		771
December 31	4,294		4,802		230			(105		)		154		(91		)

____________________________


(a)	In the first, second, and third quarter of 2015, Generation reclassified $(1) million, $7 million, and $1 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.


(b)	In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.

ComEd

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income					Net Income
	2015		2014		2015		2014			2015		2014
Quarter ended:
March 31	$	1,185	$	1,134	$	230	$	238		$	90	$	98
June 30	1,148		1,128		243		258		^(a)	99		111
September 30	1,376		1,222		327		287		^(a)	149		126
December 31	1,196		1,079		217		196			87		73

____________________________


(a)	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income.

PECO

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income on Common Stock
	2015		2014		2015		2014		2015		2014
Quarter ended:
March 31	$	985	$	993	$	223	$	149	$	139	$	89
June 30	661		656		124		134		70		84
September 30	740		693		154		133		90		81
December 31	645		750		128		156		79		98

BGE

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income attributable to Common Shareholders
	2015		2014		2015		2014		2015		2014
Quarter ended:
March 31	$	1,036	$	1,054	$	204	$	169	$	106	$	85
June 30	628		653		99		55		44		16
September 30	725		697		110		102		51		46
December 31	746		761		144		113		74		52

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)

12 Months Ended

Dec. 31, 2015

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Operations and Other Comprehensive Income



	For the Years Ended December 31,
(In millions)	2015			2014			2013
Operating expenses
Operating and maintenance	$	—		$	9		$	9
Operating and maintenance from affiliates	43			38			34
Other	4			3			12
Total operating expenses	47			50			55
Operating loss	(47		)	(50		)	(55		)
Other income and (deductions)
Interest expense, net	(168		)	(237		)	(116		)
Equity in earnings of investments	2,461			1,779			1,903
Interest income from affiliates, net	43			53			36
Other, net	(43		)	(2		)	(78		)
Total other income	2,293			1,593			1,745
Income before income taxes	2,246			1,543			1,690
Income taxes	(23		)	(80		)	(29		)
Net income	$	2,269		$	1,623		$	1,719
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service cost (benefit) reclassified to periodic costs	$	(46	)	$	(30	)	$	—
Actuarial loss reclassified to periodic cost	220			147			208
Transition obligation reclassified to periodic cost	—			—			—
Pension and non-pension postretirement benefit plan valuation adjustment	(99		)	(497		)	669
Unrealized loss on cash flow hedges	9			(148		)	(248		)
Unrealized gain on marketable securities	—			1			2
Unrealized gain on equity investments	(3		)	8			106
Unrealized loss on foreign currency translation	(21		)	(9		)	(10		)
Reversal of CENG equity method AOCI	—			(116		)	—
Other comprehensive income (loss)	60			(644		)	727
Comprehensive income	$	2,329		$	979		$	2,446

See Notes to Financial Statements

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Statements of Cash Flows



	For the Years Ended December 31,
(In millions)	2015			2014			2013
Net cash flows provided by operating activities	$	3,071		$	806		$	1,053
Cash flows from investing activities
Return on investment of direct financing lease termination	—			335			—
Changes in Exelon intercompany money pool	(1,217		)	(83		)	(60		)
Note receivable from affiliates	550			—			484
Capital expenditures	—			1			—
Change in restricted cash	—			—			38
Investment in affiliates	(212		)	(70		)	(38		)
Other investing activities	(55		)	(126		)	15
Net cash flows provided by (used in) investing activities	(934		)	57			439
Cash flows from financing activities
Changes in short-term borrowings	—			—			10
Issuance of long-term debt	4,200			1,150			—
Retirement of long-term debt	(2,263		)	(23		)	(450		)
Issuance of common stock	1,868			—			—
Dividends paid on common stock	(1,105		)	(1,065		)	(1,249		)
Proceeds from employee stock plans	32			35			47
Other financing activities	(58		)	(84		)	(6		)
Net cash flows provided by (used in) financing activities	2,674			13			(1,648		)
Increase (decrease) in cash and cash equivalents	4,811			876			(156		)
Cash and cash equivalents at beginning of period	879			3			159
Cash and cash equivalents at end of period	$	5,690		$	879		$	3

See Notes to Financial Statements

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets



	December 31,
(In millions)	2015		2014
ASSETS
Current assets
Cash and cash equivalents	$	5,690	$	879
Accounts receivable, net
Other accounts receivable	272		209
Accounts receivable from affiliates	20		24
Notes receivable from affiliates	1,478		818
Regulatory assets	241		254
Other	5		22
Total current assets	7,706		2,206
Property, plant and equipment, net	53		54
Deferred debits and other assets
Regulatory assets	3,072		3,186
Investments in affiliates	26,119		26,670
Deferred income taxes	2,036		2,147
Non-pension postretirement benefit asset	108		—
Notes receivable from affiliates	933		943
Other	404		149
Total deferred debits and other assets	32,672		33,095
Total assets	$	40,431	$	35,355

See Notes to Financial Statements

Exelon Corporation and Subsidiary Companies

Schedule I – Condensed Financial Information of Parent (Exelon Corporate)

Condensed Balance Sheets



	December 31,
(In millions)	2015			2014
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	188		$	—
Long-term debt due within one year	60			1,409
Accounts payable	5			2
Accrued expenses	440			25
Regulatory liabilities	63			51
Pension obligations	52			45
Other	1			30
Total current liabilities	809			1,562
Long-term debt	6,017			2,818
Long-term debt to affiliate	—			182
Deferred credits and other liabilities
Regulatory liabilities	31			37
Pension obligations	7,520			7,638
Non-pension postretirement benefit obligations	—			16
Deferred income taxes	134			93
Other	122			398
Total deferred credits and other liabilities	7,807			8,182
Total liabilities	14,633			12,744
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2000 shares authorized, 920 shares and 860 shares outstanding at December 31, 2015 and 2014, respectively)	18,678			16,709
Treasury stock, at cost (35 shares at December 31, 2015 and 2014, respectively)	(2,327		)	(2,327		)
Retained earnings	12,068			10,910
Accumulated other comprehensive loss, net	(2,624		)	(2,684		)
Total shareholders’ equity	25,795			22,608
BGE preference stock not subject to mandatory redemption	3			3
Total liabilities and shareholders’ equity	$	40,431		$	35,355

See Notes to Financial Statements

Basis of Presentation

Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.

Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. Exelon owned none of PECO’s preference securities, which PECO redeemed in 2013.

Mergers

For BGE’s debt, the difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE as part of the 2012 Constellation Merger. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the fair value of BGE long-term debt regulatory asset.

Debt and Credit Agreements

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper borrowings at both December 31, 2015 and December 31, 2014.

Credit Agreements

On May 30, 2014, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank commitments of $500 million through May 2019. As of December 31, 2015, Exelon Corporation had available capacity under those commitments of $474 million. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporation’s credit agreement.

Long-Term Debt

The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2015 and December 31, 2014:



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Junior subordinated notes				6.5	%	2024	$	1,150		$	1,150
Contract payment - junior subordinated notes				2.5	%	2017	64			108
Senior unsecured notes ^(a)	1.6	%	-	7.6	%	2017 - 2045	4,639			2,658
Total long-term debt							5,853			3,916
Unamortized debt discount and premium, net							(4		)	1
Unamortized debt issuance costs							(47		)	(23		)
Fair value adjustment of consolidated subsidiary							275			333
Long-term debt due within one year							(60		)	(1,409		)
Long-term debt							$	6,017		$	2,818

___________


(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.

The debt maturities for Exelon Corporate for the periods 2016, 2017, 2018, 2019, 2020 and thereafter are as follows:



2016	$	45
2017	569
2018	—
2019	—
2020	1,450
Remaining years	3,789
Total long-term debt	$	5,853

Commitments and Contingencies

See Note 23—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.

Related Party Transactions

The financial statements of Exelon Corporate include related party transactions as presented in the tables below:



	For the Years Ended December 31,
(In millions)	2015			2014			2013
Operating and maintenance from affiliates:
BSC ^(a)	$	43		$	38		$	34
Interest income from affiliates, net:
Generation	$	43		$	53		$	36
Equity in earnings of investments:
Exelon Energy Delivery Company, LLC ^(b)	$	1,079		$	958		$	834
Exelon Ventures Company, LLC ^(c)	—			926			1,076
UII, LLC	20			(6		)	(2		)
Exelon Transmission Company, LLC	(8		)	(7		)	(5		)
Exelon Enterprise	(1		)	(1		)	—
Generation	1,371			(91		)	—
Total equity in earnings of investments	$	2,461		$	1,779		$	1,903

Cash contributions received from affiliates	$	3,209		$	1,370		$	1,175



	December 31,
(in millions)	2015			2014
Accounts receivable from affiliates (current):
BSC ^(a)	$	—		$	2
Generation	16			12
ComEd	2			3
PECO	1			2
BGE	1			5
Total accounts receivable from affiliates (current)	$	20		$	24
Notes receivable from affiliates (current):
BSC ^(a)	$	226		$	262
Generation ^(d)	1,252			556
Total receivable from affiliates (current):	$	1,478		$	818
Investments in affiliates:
BSC ^(a)	$	191		$	193
Exelon Energy Delivery Company, LLC ^(b)	14,163			13,590
UII, LLC	102			130
Exelon Transmission Company, LLC	3			1
Voluntary Employee Beneficiary Association trust	7			9
Exelon Enterprises	22			23
Generation	11,637			12,720
Other	(6		)	4
Total investments in affiliates	$	26,119		$	26,670
Notes receivable from affiliates (non-current):
Generation ^(d)	$	933		$	943
Notes payable to affiliates (current):
ComEd	$	188		$	—
Long-term debt to affiliates (non-current):
ComEd	$	—		$	182

_____________________


(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.


(b)	Exelon Energy Delivery Company, LLC consists of ComEd, PECO and BGE.


(c)	Exelon Ventures Company, LLC primarily consisted of Generation and was fully dissolved as of December 31, 2014. Exelon Enterprises, Exelon Generation Company, LLC, and Exelon Consolidations are now directly owned Exelon Corporate investments as of December 31, 2014.

(d)

In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2015

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

Exelon Corporation and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts				Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2015
Allowance for uncollectible accounts ^(a)	$	311	$	113	$	27		^(b)	$	167	^(c)	$	284
Deferred tax valuation allowance	50		—		(27		)		10			13
Reserve for obsolete materials	95		10		2				2			105
For the year ended December 31, 2014
Allowance for uncollectible accounts ^(a)	$	272	$	175	$	69		^(b)	$	205	^(c)	$	311
Deferred tax valuation allowance	13		—		37				—			50
Reserve for obsolete materials	58		5		34				2			95
For the year ended December 31, 2013
Allowance for uncollectible accounts ^(a)	$	293	$	121	$	37		^(b)	$	179	^(c)	$	272
Deferred tax valuation allowance	36		1		—				24			13
Reserve for obsolete materials	53		17		—				12			58

___________________


(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $8 million, and $9 million for the years ended December 31, 2015, 2014, and 2013, respectively.


(b)	Includes charges for late payments and non-service receivables.


(c)	Write-off of individual accounts receivable.

Exelon Generation Company, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

Generation



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 10, 2016 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Balance Sheets at December 31, 2015 and 2014

		Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2015, 2014 and 2013

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Exelon Generation Company, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C						Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses			Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2015
Allowance for uncollectible accounts	$	60	$	22		$	—		$	5		$	77
Deferred tax valuation allowance	48		—			(27		)	10			11
Reserve for obsolete materials	93		9			—			—			102
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	57	$	14		$	8		$	19		$	60
Deferred tax valuation allowance	11		—			37			—			48
Reserve for obsolete materials	55		5			32			(1		)	93
For the year ended December 31, 2013
Allowance for uncollectible accounts	$	84	$	(16	)	$	—		$	11		$	57
Deferred tax valuation allowance	35		1			—			25			11
Reserve for obsolete materials	50		16			—			11			55

Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

ComEd



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 10, 2016 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Balance Sheets at December 31, 2015 and 2014

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Commonwealth Edison Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2015
Allowance for uncollectible accounts	$	84	$	39	$	18	^(a)	$	66	^(b)	$	75
Reserve for obsolete materials	2		1		2			2			3
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	62	$	45	$	33	^(a)	$	56	^(b)	$	84
Reserve for obsolete materials	2		—		2			2			2
For the year ended December 31, 2013
Allowance for uncollectible accounts	$	70	$	33	$	29	^(a)	$	70	^(b)	$	62
Reserve for obsolete materials	2		1		—			1			2

_____________________


(a)	Primarily charges for late payments and non-service receivables.


(b)	Write-off of individual accounts receivable.

PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

PECO



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 10, 2016 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Balance Sheets at December 31, 2015 and 2014

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

PECO Energy Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2015
Allowance for uncollectible accounts ^(a)	$	100	$	37	$	9	^(b)	$	63	^(c)	$	83
Reserve for obsolete materials	1		—		—			—			1
For the year ended December 31, 2014
Allowance for uncollectible accounts ^(a)	$	107	$	52	$	11	^(b)	$	70	^(c)	$	100
Reserve for obsolete materials	1		—		—			—			1
For the year ended December 31, 2013
Allowance for uncollectible accounts ^(a)	$	99	$	61	$	7	^(b)	$	60	^(c)	$	107
Reserve for obsolete materials	1		—		—			—			1

_____________________


(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $8 million, and $9 million for the years ended December 31, 2015, 2014, and 2013, respectively.


(b)	Primarily charges for late payments.


(c)	Write-off of individual accounts receivable.

Baltimore Gas and Electric Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts

BGE



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 10, 2016 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013

		Consolidated Balance Sheets at December 31, 2015 and 2014

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2015, 2014 and 2013

		Notes to Consolidated Financial Statements

2.		Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Baltimore Gas and Electric Company and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2015
Allowance for uncollectible accounts	$	67	$	15	$	—	^(b)	$	33	^(a)	$	49
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	—		—		—			—			—
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	46	$	64	$	17	^(b)	$	60	^(a)	$	67
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	1		—		—			1			—
For the year ended December 31, 2013
Allowance for uncollectible accounts	$	40	$	43	$	1		$	38	^(a)	$	46
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	1		—		—			—			1

_____________________


(a)	Write-off of individual accounts receivable.


(b)	Primarily charges for late payments.

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Description of Business (Exelon, Generation, ComEd, PECO and BGE)

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 Power 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.

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

Use Of Estimates (Exelon, Generation, ComEd, PECO and BGE)

Use of Estimates (Exelon, Generation, ComEd, PECO and BGE)

Reclassifications (Exelon, ComEd, and BGE)

Reclassifications (Exelon, Generation, ComEd, PECO and BGE)

Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE)

Revenues (Exelon, Generation, ComEd, PECO and BGE)

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

Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE)

Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)

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

Restricted Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)

Allowance for Uncollectible Accounts (Exelon, Generation, ComEd, PECO and BGE)

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

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


•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,


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


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

Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities:


•	Exelon has disclosed, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon’s consolidated VIEs for which creditors do not have recourse to Exelon’s general credit.


•	Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity.

See Note 2 — Variable Interest Entities for additional information.

Inventories (Exelon, Generation, ComEd, PECO and BGE)

Inventory is recorded at the lower of weighted average cost or market. Provisions are recorded for excess and obsolete inventory.

Marketable Securities (Exelon, Generation, ComEd, PECO and BGE)

Property Plant And Equipment (Exelon, Generation, ComEd, PECO and BGE)

Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)

Nuclear Fuel (Exelon and Generation)

Nuclear Outage Costs (Exelon and Generation)

New Site Development Costs (Exelon and Generation)

Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE)

Depreciation, Depletion, and Amortization (Exelon, Generation, ComEd, PECO and BGE)

Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE)

See Note 7 — Property, Plant and Equipment for further information regarding depreciation.

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

Capitalized Interest (Exelon, Generation, ComEd, PECO and BGE)

Capitalized Interest and AFUDC (Exelon, Generation, ComEd, PECO and BGE)

Allowance For Funds Used During Construction (Exelon, Generation, ComEd, PECO and BGE)

Guarantees (Exelon, Generation, ComEd, PECO and BGE)

Long-lived Assets (Exelon, Generation, ComEd, PECO and BGE)

Goodwill (Exelon, Generation, ComEd, PECO and BGE)

Equity Method Investments (Exelon, Generation, ComEd, PECO and BGE)

Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation)

Direct Financing Lease Investments (Exelon, Generation, ComEd, PECO and BGE)

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

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

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.

Investment, Policy [Policy Text Block]

Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation)

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

Exelon has identified the following new accounting standards that have been recently adopted that management believes may significantly affect the Registrants.

Balance Sheet Classification of Deferred Taxes



For the year ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Increase (Decrease)
Current assets - Deferred income taxes	$	(244	)	$	(327	)	$	—		$	(69	)	$	(6	)
Deferred debits and other assets - Other	3			—			—			—			—
Current liabilities - Deferred income taxes	—			—			(63		)	—			(52		)
Deferred credits and other liabilities - Deferred income taxes	(241		)	(327		)	63			(69		)	46

The adoption of this guidance had no impact on the Registrants’ Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows.

Simplifying the Accounting for Measurement-Period Adjustments

Application of Normal Purchases Normal Sales Exception to Power Contracts in Nodal Energy Markets

Simplifying the Presentation of Debt Issuance Costs

The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of the Registrants.

Recognition and Measurement of Financial Assets and Financial Liabilities

Simplifying the Measurement of Inventory

Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share

Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement

Amendments to the Consolidation Analysis

Revenue from Contracts with Customers

Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2015

Accounting Policies [Abstract]

Schedule Of Capitalized Software

The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:



Net unamortized software costs	Exelon		Generation		ComEd		PECO		BGE
December 31, 2015	$	633	$	180	$	172	$	86	$	178
December 31, 2014	596		193		133		84		163

Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO		BGE
2015	$	208	$	73	$	47	$	33	$	46
2014	186		59		45		28		43
2013	198		67		52		33		36

Schedule Of Capitalized Interest And AFUDC

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



		Exelon^(a)		Generation^(a)		ComEd		PECO		BGE
2015	Total incurred interest ^(b)	$	1,170	$	445	$	336	$	116	$	113
	Capitalized interest	79		79		—		—		—
	Credits to AFUDC debt and equity	44		—		9		7		28
2014	Total incurred interest ^(b)	$	1,144	$	419	$	323	$	115	$	118
	Capitalized interest	63		63		—		—		—
	Credits to AFUDC debt and equity	37		—		5		8		24
2013	Total incurred interest ^(b)	$	1,423	$	411	$	584	$	117	$	129
	Capitalized interest	54		54		—		—		—
	Credits to AFUDC debt and equity	35		—		16		6		13

_______________________


(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.


(b)	Includes interest expense to affiliates.

New Accounting Pronouncement, Early Adoption [Table Text Block]

The Registrants early adopted the standard retrospectively in the fourth quarter of 2015, resulting in the following impacts as of December 31, 2014 in the Consolidated Balance Sheets of the Registrants:



For the year ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Increase (Decrease)
Current assets - Deferred income taxes	$	(244	)	$	(327	)	$	—		$	(69	)	$	(6	)
Deferred debits and other assets - Other	3			—			—			—			—
Current liabilities - Deferred income taxes	—			—			(63		)	—			(52		)
Deferred credits and other liabilities - Deferred income taxes	(241		)	(327		)	63			(69		)	46

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2015

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities

As of December 31, 2015 and 2014, these assets and liabilities primarily consisted of the following:



		December 31, 2015									December 31, 2014 (a)
		Exelon			Generation			BGE				Exelon		Generation		BGE
Cash and cash equivalents			$	164		$	164		$	—		$	392	$	392	$	—
Restricted cash			100			77			23			117		96		21
Accounts receivable, net
	Customer		219			219			—			297		297		—
	Other		43			43			—			57		57		—
Mark-to-market derivatives assets			140			140			—			171		171		—
Inventory
	Materials and supplies		181			181			—			172		172		—
Other current assets			35			30			—			37		30		—
	Total current assets		882			854			23			1,243		1,215		21

Property, plant and equipment, net			5,160			5,160			—			4,638		4,638		—
Nuclear decommissioning trust funds			2,036			2,036			—			2,097		2,097		—
Goodwill			47			47			—			47		47		—
Mark-to-market derivatives assets			53			53			—			44		44		—
Other noncurrent assets			90			85			3			90		77		3
	Total noncurrent assets		7,386			7,381			3			6,916		6,903		3
	Total assets		$	8,268		$	8,235		$	26		$	8,159	$	8,118	$	24

Long-term debt due within one year			$	111		$	27		$	79		$	87	$	5	$	75
Accounts payable			216			216			—			292		292		—
Accrued expenses			115			113			2			111		108		2
Mark-to-market derivative liabilities			5			5			—			24		24		—
Unamortized energy contract liabilities			12			12			—			22		22		—
Other current liabilities			13			13			—			25		25		—
	Total current liabilities		472			386			81			561		476		77

	Long-term debt		666			623			41			212		81		120
	Asset retirement obligations		1,999			1,999			—			1,763		1,763		—
	Pension obligation^(b)		9			9			—			9		9		—
	Unamortized energy contract liabilities		39			39			—			51		51		—
	Other noncurrent liabilities		79			79			—			132		132		—
	Noncurrent liabilities		2,792			2,749			41			2,167		2,036		120
	Total liabilities		$	3,264		$	3,135		$	122		$	2,728	$	2,512	$	197

___________


(a)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to classification of deferred taxes and simplifying the presentation of debt costs. See Note 1- Significant Accounting Policies for additional information.


(b)	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 17—Retirement Benefits for additional details.

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



December 31, 2015	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	263	$	164	$	427
Total liabilities^(a)	22		125		147
Exelon's ownership interest in VIE^(a)	—		11		11
Other ownership interests in VIE^(a)	241		28		269
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		21		21
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	17		—		17



December 31, 2014	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	114	$	91	$	205
Total liabilities^(a)	3		49		52
Exelon's ownership interest in VIE^(a)	—		9		9
Other ownership interests in VIE^(a)	111		33		144
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		13		13
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	27		—		27

___________________

(a)



	December 31, 2015						December 31, 2014 ^(a)
	Exelon ^(b)		Generation		BGE		Exelon ^(b)		Generation		BGE
Current assets	$	909	$	881	$	23	$	1,275	$	1,247	$	21
Noncurrent assets	8,009		8,004		3		7,573		7,560		3
Total assets	$	8,918	$	8,885	$	26	$	8,848	$	8,807	$	24
Current liabilities	$	473	$	387	$	81	$	611	$	526	$	77
Noncurrent liabilities	2,927		2,884		41		2,728		2,597		120
Total liabilities	$	3,400	$	3,271	$	122	$	3,339	$	3,123	$	197

_______________________


(a)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to classification of deferred taxes and simplifying the presentation of debt costs. See Note 1- Significant Accounting Policies for additional information.


(b)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.

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

Public Utilities General Disclosures [Table Text Block]

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2015

Regulated Operations [Abstract]

For each of the following years, the ICC approved the following total increases/(decreases) in ComEd's electric distributions formula rate filings:



Annual Distribution Filings	2015				2014				2013
ComEd's requested total revenue requirement (decrease) increase	$	(50	)		$	269			$	353

Final ICC Order
Initial revenue requirement increase	$	85			$	160			$	160
Annual reconciliation (decrease) increase	(152		)		72				181
Total revenue requirement (decrease) increase	$	(67	)		$	232			$	341

Allowed Return on Rate Base:
Initial revenue requirement	7.05		%		7.06		%		6.94		%
Annual reconciliation	7.02		%		7.04		%		6.94		%
Allowed ROE:
Initial revenue requirement	9.14		%	^(a)	9.25		%	^(a)	8.72		%
Annual reconciliation	9.09		%	^(a)	9.20		%	^(a)	8.72		%

Effective date of rates	January 2016				January 2015				January 2014

__________________

(a) Includes a reduction of 5 basis points for a reliability performance metric penalty.

For each of the following years, the following total increases/(decreases) were included in ComEd's and BGE's electric transmission formula rate filings:



	ComEd									BGE
Annual Transmission Filings	2015			2014			2013			2015			2014			2013
Initial revenue requirement increase ^(a)	$	68		$	36		$	38		$	—		$	9		$	2
Annual reconciliation (decrease) increase	18			(14		)	30			(3		)	5			(3		)
Total revenue requirement increase	$	86		$	22		$	68		$	(3	)	$	14		$	(1	)

Allowed return on rate base ^(b)	8.61		%	8.62		%	8.7		%	8.46		%	8.53		%	8.35		%
Allowed ROE	11.5		%	11.5		%	11.5		%	11.3		%	11.3		%	11.3		%

Effective date of rates ^(c)	June 2015			June 2014			June 2013			June 2015			June 2014			June 2013

_____________

(b)

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

Regulatory Construction Commitment

ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE’s estimated commitments are as follows:



	Total		2016		2017		2018		2019		2020
ComEd	$	297	$	204	$	61	$	26	$	6	$	—
PECO	67		31		24		8		4		—
BGE	373		140		112		62		46		13

Schedule of Regulatory Assets



December 31, 2015	Exelon		ComEd		PECO		BGE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79
AMI programs	399		140		63		196
Under-recovered distribution service costs	189		189		—		—
Debt costs	47		46		1		8
Fair value of BGE long-term debt	162		—		—		—
Severance	9		—		—		9
Asset retirement obligations	108		67		22		19
MGP remediation costs	286		255		30		1
Under-recovered uncollectible accounts	52		52		—		—
Renewable energy	247		247		—		—
Energy and transmission programs	84		43		1		40
Deferred storm costs	2		—		—		2
Electric generation-related regulatory asset	20		—		—		20
Rate stabilization deferral	87		—		—		87
Energy efficiency and demand response programs	279		—		1		278
Merger integration costs	6		—		—		6
Conservation voltage reduction	3		—		—		3
Under-recovered revenue decoupling	30		—		—		30
CAP arrearage	7		—		7		—
Other	35		10		19		3
Total regulatory assets	6,824		1,113		1,617		781
Less: current portion	759		218		34		267
Total noncurrent regulatory assets	$	6,065	$	895	$	1,583	$	514

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2015 and 2014.



December 31, 2015	Exelon		ComEd		PECO		BGE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79
AMI programs	399		140		63		196
Under-recovered distribution service costs	189		189		—		—
Debt costs	47		46		1		8
Fair value of BGE long-term debt	162		—		—		—
Severance	9		—		—		9
Asset retirement obligations	108		67		22		19
MGP remediation costs	286		255		30		1
Under-recovered uncollectible accounts	52		52		—		—
Renewable energy	247		247		—		—
Energy and transmission programs	84		43		1		40
Deferred storm costs	2		—		—		2
Electric generation-related regulatory asset	20		—		—		20
Rate stabilization deferral	87		—		—		87
Energy efficiency and demand response programs	279		—		1		278
Merger integration costs	6		—		—		6
Conservation voltage reduction	3		—		—		3
Under-recovered revenue decoupling	30		—		—		30
CAP arrearage	7		—		7		—
Other	35		10		19		3
Total regulatory assets	6,824		1,113		1,617		781
Less: current portion	759		218		34		267
Total noncurrent regulatory assets	$	6,065	$	895	$	1,583	$	514

Schedule of Regulatory Liabilities



December 31, 2015	Exelon		ComEd		PECO		BGE
Regulatory liabilities
Other postretirement benefits	$	94	$	—	$	—	$	—
Nuclear decommissioning	2,577		2,172		405		—
Removal costs	1,527		1,332		—		195
Energy efficiency and demand response programs	92		52		40		—
DLC program costs	9		—		9		—
Electric distribution tax repairs	95		—		95		—
Gas distribution tax repairs	28		—		28		—
Energy and transmission programs	131		53		60		18
Over-recovered revenue decoupling	1		—		—		1
Other	16		5		2		8
Total regulatory liabilities	4,570		3,614		639		222
Less: current portion	369		155		112		38
Total noncurrent regulatory liabilities	$	4,201	$	3,459	$	527	$	184

Purchase Of Receivables

The following tables provide information about the purchased receivables of the Registrants as of December 31, 2015 and 2014.



As of December 31, 2015	Exelon			ComEd			PECO			BGE
Purchased receivables ^(a)	$	229		$	103		$	67		$	59
Allowance for uncollectible accounts ^(b)	(31		)	(16		)	(7		)	(8		)
Purchased receivables, net	$	198		$	87		$	60		$	51

As of December 31, 2014	Exelon			ComEd			PECO			BGE
Purchased receivables ^(a)	$	290		$	139		$	76		$	75
Allowance for uncollectible accounts ^(b)	(42		)	(21		)	(8		)	(13		)
Purchased receivables, net	$	248		$	118		$	68		$	62

_________________________

(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.

Schedule of Public Utilities Genera Disclosures [Table Text Block]



	ComEd									BGE
Annual Transmission Filings	2015			2014			2013			2015			2014			2013
Initial revenue requirement increase ^(a)	$	68		$	36		$	38		$	—		$	9		$	2
Annual reconciliation (decrease) increase	18			(14		)	30			(3		)	5			(3		)
Total revenue requirement increase	$	86		$	22		$	68		$	(3	)	$	14		$	(1	)

Allowed return on rate base ^(b)	8.61		%	8.62		%	8.7		%	8.46		%	8.53		%	8.35		%
Allowed ROE	11.5		%	11.5		%	11.5		%	11.3		%	11.3		%	11.3		%

Effective date of rates ^(c)	June 2015			June 2014			June 2013			June 2015			June 2014			June 2013

Mergers, Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of Business Acquisitions, by Acquisition

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



Total consideration transferred	$	332

Identifiable assets acquired and liabilities assumed
Working capital assets	$	390
Mark-to-market derivative assets	184
Unamortized energy contract assets	115
Customer relationships	50
Working capital liabilities	(196		)
Mark-to-market derivative liabilities	(57		)
Unamortized energy contract liabilities	(110		)
Deferred tax liability	(16		)
Total net identifiable assets, at fair value	$	360
Bargain purchase gain (after-tax)	$	28

Summary of Asset Divestitures

The table below presents the major classes of assets and liabilities held for sale at December 31, 2014. Assets held for sale at December 31, 2015 are not material.



	December 31, 2014
Assets
Property, plant and equipment, net ^(a)	$	143
Inventory	4
Total assets held for sale	$	147
Liabilities
Accrued expenses	$	1
Asset retirement obligations	4
Total liabilities held for sale^(b)	$	5

_____________

(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.



Station	Net Generation Capacity	Location	Operating Segment	Percent Owned
Fore River	726 MW	North Weymouth, MA	New England	100	%
West Valley	185 MW	Salt Lake City, UT	Other	100	%
Keystone	714 MW	Shelocta, PA	Mid-Atlantic	41.98	%
Conemaugh	532 MW	New Florence, PA	Mid-Atlantic	31.28	%
Safe Harbor	278 MW	Conestoga, PA	Mid-Atlantic	66.7	%
Quail Run	488 MW	Odessa, TX	ERCOT	100	%

Restructuring and Related Costs [Table Text Block]



	For the year ended,
Acquisition, Integration and Financing Costs ^(a)	2015		2014
Exelon	$	80	$	179
Generation	25		11
ComEd	10		4
PECO	5		2
BGE	5		2

___________

Tabular disclosure of information related to a disposal group. Includes, but is not limited to, a discontinued operation, disposal classified as held-for-sale or disposed of by means other than sale or disposal of an individually significant component.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=51716988&loc=SL51721533-107759

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721665-107760

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=51717284&loc=d3e1474-107760

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=51717284&loc=d3e1361-107760

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721683-107760

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=51719941&loc=SL51724579-110230

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5C
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721675-107760

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721663-107760

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 360
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=51719941&loc=d3e2941-110230

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5B
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721673-107760

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 3A
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721659-107760

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721671-107760

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 205
-SubTopic 20
-Section 50
-Paragraph 5D
-URI http://asc.fasb.org/extlink&oid=51717284&loc=SL51721677-107760

Investment in Constellation Energy Nuclear Group, LLC (Tables)

12 Months Ended

Dec. 31, 2015

Schedule of total equity in earnings of investment in CENG

The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above:



Fair Values	Exelon and Generation
Current assets	$	499
Nuclear decommissioning trust fund	1,955
Property, plant and equipment	3,073
Nuclear fuel	482
Other assets	10
Total assets	6,019

Current liabilities	237
Asset retirement obligation	1,816
Pension and other employee benefit obligations	281
Unamortized energy contract liabilities	171
Other liabilities	114
Total liabilities	2,619
Total net assets	$	3,400

Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2015

Receivables [Abstract]

Schedule Of Accounts Notes Loans And Financing Receivable



2015	Exelon			Generation				ComEd			PECO				BGE
Unbilled customer revenues	$	1,203		$	732		^(a)	$	218		$	105			$	148
Allowance for uncollectible accounts ^(b)	(284		)	(77		)		(75		)	(83		)	^(c)	(49		)



2014	Exelon			Generation				ComEd			PECO				BGE
Unbilled customer revenues	$	1,381		$	823		^(a)	$	204		$	140			$	214
Allowance for uncollectible accounts ^(b)	(311		)	(60		)		(84		)	(100		)	^(c)	(67		)	^(d)

_________________________


(a)	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.


(b)	Includes the allowance for uncollectible accounts on customer and other accounts receivable.


(c)	Excludes the non-current allowance for uncollectible accounts of $8 million at both December 31, 2015 and 2014, related to PECO’s current installment plan receivables described below.

(d)

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2015

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015			2014
Asset Category
Electric—generation	1-56	$	25,615	19,004,000,000	$	22,911
Nuclear fuel ^(a)	1-8	6,384		4,815,000,000	5,947
Construction work in progress	N/A	2,017		1,352,000,000	1,404
Other property, plant and equipment ^(b)	5-31	466		374,000,000	378
Total property, plant and equipment		34,482			30,640
Less: accumulated depreciation ^(c)		8,639			7,612
Property, plant and equipment, net		$	25,843		$	23,028

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.

(b)


(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-90	$	32,546	$	30,157
Electric—generation	1-56	25,615		22,911
Gas—transportation and distribution	5-90	3,864		3,505
Common—electric and gas	5-50	1,149		1,169
Nuclear fuel ^(a)	1-8	6,384		5,947
Construction work in progress	N/A	3,075		2,167
Other property, plant and equipment ^(b)	5-50	1,181		1,056
Total property, plant and equipment		73,814		66,912
Less: accumulated depreciation ^(c)		16,375		14,742
Property, plant and equipment, net		$	57,439	$	52,170

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.

(b)


(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-80	$	20,576	$	18,884
Construction work in progress	N/A	572		276
Other property, plant and equipment ^{(a), (b)}	38-50	64		65
Total property, plant and equipment		21,212		19,225
Less: accumulated depreciation		3,710		3,432
Property, plant and equipment, net		$	17,502	$	15,793

_________________________


(a)	Includes buildings under capital lease with a net carrying value at December 31, 2015 and 2014 of $7 million and $8 million, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively.


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

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-90	$	6,663	$	6,339
Gas—distribution	5-90	1,951		1,761
Common—electric and gas	5-40	655		623
Construction work in progress	N/A	312		317
Other property, plant and equipment ^(a)	20	32		32
Total property, plant and equipment		9,613		9,072
Less: accumulated depreciation		3,016		2,868
Property, plant and equipment, net		$	6,597	$	6,204

_______________________


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

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2015 and 2014:



	Average Service Life (years)	2015		2014
Asset Category
Electric—transmission and distribution	5-65	$	7,230	$	6,886
Gas—transportation and distribution	5-70	2,206		2,039
Common—electric and gas	5-50	631		618
Construction work in progress	N/A	154		154
Other property, plant and equipment ^(a)	50	21		21
Total property, plant and equipment		10,242		9,718
Less: accumulated depreciation		3,101		2,917
Property, plant and equipment, net		$	7,141	$	6,801

_________________________


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

Property Plant And Equipment Average Service Life Percentage By Asset Category Table

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



Average Service Life Percentage by Asset Category	2015		2014		2013
Electric—transmission and distribution	2.83	%	2.93	%	2.91	%
Electric—generation	3.47	%	3.50	%	3.35	%
Gas	2.17	%	2.13	%	2.06	%
Common—electric and gas	7.79	%	7.32	%	7.53	%

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



Average Service Life Percentage by Asset Category	2015		2014		2013
Electric—transmission and distribution	2.39	%	2.55	%	2.73	%
Gas	1.87	%	1.84	%	1.79	%
Common—electric and gas	5.16	%	5.16	%	6.65	%



Average Service Life Percentage by Asset Category	2015		2014		2013
Electric—transmission and distribution	2.62	%	2.96	%	2.91	%
Gas	2.50	%	2.47	%	2.36	%
Common—electric and gas	10.35	%	9.49	%	8.45	%

Impairment of Long-Lived assets (Tables)

12 Months Ended

Dec. 31, 2015

Impairment or Disposal of Tangible Assets Disclosure [Abstract]

Schedule of Capital Leased Assets

At December 31, 2015 and 2014, the components of the net investment in long-term leases were as follows:



	December 31, 2015		December 31, 2014
Estimated residual value of leased assets	$	639	$	685
Less: unearned income	287		324
Net investment in long-term leases	$	352	$	361

Jointly Owned Electric Utility Plant (Tables)

12 Months Ended

Dec. 31, 2015

Public Utilities, Property, Plant and Equipment [Abstract]

Schedule of Jointly Owned Utility Plants

Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2015 and 2014 were as follows:



	Nuclear Generation												Fossil Fuel Generation			Transmission					Other
	Quad Cities			Peach Bottom			Salem ^(a)			Nine Mile Point Unit 2^(f)			Wyman			PA ^(b)		DE/NJ ^(c)			Other ^(d)
Operator	Generation			Generation			PSEG Nuclear			Generation			FP&L			First Energy		PSEG
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	5.89		%	Various		42.55		%	44.24		%
Exelon’s share at December 31, 2015:
Plant ^(e)	$	1,035		$	1,345		$	566		$	756		$	3		$	15	$	65		$	1
Accumulated depreciation ^(e)	309			368			167			42			3			7		35			1
Construction work in progress	11			18			40			56			—			—		—			—
Exelon’s share at December 31, 2014:
Plant ^(e)	$	995		$	1,095		$	531		$	676		$	3		$	14	$	64		$	2
Accumulated depreciation ^(e)	266			343			150			14			3			7		34			1
Construction work in progress	15			133			29			48			—			—		—			—

________________________


(a)	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2015 and 2014.


(b)	PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.


(c)	PECO owns a 42.55% share in 131 miles of 500kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.


(d)	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.


(e)	Excludes asset retirement costs.

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2015

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule Of Goodwill

Exelon’s, Generation's and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2015 and 2014 were as follows:



	ComEd						Generation				Exelon
	Gross Amount ^(a)		Accumulated Impairment Losses		Carrying Amount		Gross Amount		Carrying Amount		Gross Amount		Accumulated Impairment Losses		Carrying Amount
Balance, January 1, 2014	$	4,608	$	1,983	$	2,625	$	—	$	—	$	4,608	$	1,983	$	2,625
Goodwill from business combination	—		—		—		47		47		47		—		47
Balance, December 31, 2014	4,608		1,983		2,625		47		47		4,655		1,983		2,672
Impairment losses	—		—		—		—		—		—		—		—
Balance, December 31, 2015	$	4,608	$	1,983	$	2,625	$	47	$	47	$	4,655	$	1,983	$	2,672

_______________________


(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

Schedule of Finite-Lived Intangible Assets



	Weighted Average Amortization Years ^(k)										Estimated amortization expense
	Weighted Average Amortization Years ^(k)	Gross			Accumulated Amortization			Net			2016			2017			2018			2019			2020
Exelon
Software License Agreement ^(a)	10.0	$	95		$	(6	)	$	89		$	10		$	10		$	10		$	10		$	10
Generation
Unamortized Energy Contracts ^(b)
Exelon Wind ^(c)	18.0	224			(69		)	155			14			14			14			14			10
Antelope Valley^(d)	25.0	190			(20		)	170			8			8			8			8			8
Constellation ^(e)	1.5	1,499			(1,473		)	26			(33		)	(21		)	11			8			10
CENG ^(f)	1.7	(97		)	48			(49		)	(11		)	(15		)	(18		)	(15		)	(8		)
Integrys ^(g)	2.4	5			2			7			5			1			1			—			—
Customer Relationships ^(h)
Constellation ^(e)	12.4	214			(76		)	138			18			18			18			17			17
Integrys ^(g)	10.0	50			(6		)	44			5			5			5			5			5
Trade Names
Constellation ^(e)	10.0	243			(103		)	140			23			23			23			23			23
ComEd
Chicago settlement—1999 agreement ⁽ⁱ⁾	21.8	100			(83		)	17			3			3			3			4			4
Chicago settlement—2003 agreement ^(j)	17.9	62			(44		)	18			4			4			4			3			3
Total intangible assets		$	2,585		$	(1,830	)	$	755		$	46		$	50		$	79		$	77		$	82

_________________________


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

(b)


(c)	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.


(d)	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 242 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.


(e)	On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.


(f)	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.


(g)	See Note 4—Mergers, Acquisitions, and Dispositions for additional information.


(h)	Excludes $12 million of other miscellaneous customer relationships that have been acquired. The estimated amortization for these miscellaneous customer relationships is $1 million in each of the years from 2016 to 2020.

(i)

(j)


(k)	Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.

Schedule Of Finite-Lived Intangible Assets Amortization Expense

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2015, 2014 and 2013:



For the Year Ended December 31,	Exelon ^(a)		Generation ^(a)		ComEd
2015	$	76	$	69	$	7
2014	179		179		7
2013	478		550		7

_________________________

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2015

Fair Value Disclosures [Abstract]

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



	ComEd											PECO										BGE
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments in mutual funds ^(a)	—		—			—			—			8		—			—		8			4		—			—		4
Total assets	29		—			—			29			279		—			—		279			29		—			—		29
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(12		)	—		(12		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities ^(b)	—		—			(247		)	(247		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(247		)	(255		)	—		(12		)	—		(12		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	29	$	(8	)	$	(247	)	$	(226	)	$	279	$	(12	)	$	—	$	267		$	29	$	(4	)	$	—	$	25



	ComEd											PECO										BGE
As of December 31, 2014	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	25	$	—		$	—		$	25		$	12	$	—		$	—	$	12		$	103	$	—		$	—	$	103
Rabbi trust investments in mutual funds ^(a)	—		—			—			—			9		—			—		9			5		—			—		5
Total assets	25		—			—			25			21		—			—		21			108		—			—		108
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(15		)	—		(15		)	—		(5		)	—		(5		)
Mark-to-market derivative liabilities ^(b)	—		—			(207		)	(207		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(207		)	(215		)	—		(15		)	—		(15		)	—		(5		)	—		(5		)
Total net assets (liabilities)	$	25	$	(8	)	$	(207	)	$	(190	)	$	21	$	(15	)	$	—	$	6		$	108	$	(5	)	$	—	$	103

_________________________


(a)	At PECO, excludes $12 million and $14 million of the cash surrender value of life insurance investments at December 31, 2015 and 2014, respectively.


(b)	The Level 3 balance includes the current and noncurrent liability of $23 million and $224 million, respectively, at December 31, 2015, and $20 million and $187 million, respectively, at December 31, 2014, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Exelon



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	536	$	3	$	533	$	—	$	536	$	463	$	463
Long-term debt (including amounts due within one year) ^(a)	25,145		931		23,644		1,349		25,924		21,014		22,936
Long-term debt to financing trusts ^(b)	641		—		—		673		673		641		648
SNF obligation	1,021		—		818		—		818		1,021		833

Generation



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	29	$	—	$	29	$	—	$	29	$	36	$	36
Long-term debt (including amounts due within one year) ^(a)	8,959		—		7,767		1,349		9,116		8,196		8,822
SNF obligation	1,021		—		818		—		818		1,021		833

ComEd



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	294	$	—	$	294	$	—	$	294	$	304	$	304
Long-term debt (including amounts due within one year) ^(a)	6,509		—		7,069		—		7,069		5,925		6,788
Long-term debt to financing trusts ^(b)	205		—		—		213		213		205		213

PECO



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Long-term debt (including amounts due within one year) ^(a)	$	2,580	$	—	$	2,786	$	—	$	2,786	$	2,232	$	2,537
Long-term debt to financing trusts	184		—		—		195		195		184		199

BGE



	December 31, 2015										December 31, 2014
	Carrying Amount		Fair Value								Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total		Carrying Amount		Fair Value
Short-term liabilities	$	213	$	3	$	210	$	—	$	213	$	123	$	123
Long-term debt (including amounts due within one year) ^(a)	1,858		—		2,044		—		2,044		1,932		2,178
Long-term debt to financing trusts ^(b)	252		—		—		264		264		252		236

Fair value of financial liabilities recorded at the carrying amount



	Generation								Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents ^(a)	$	104	$	—	$	—	$	104	$	5,766	$	—	$	—	$	5,766
Nuclear decommissioning trust fund investments
Cash equivalents ^(b)	219		92		—		311		219		92		—		311



	Generation									Exelon
As of December 31, 2015	Level 1			Level 2		Level 3		Total		Level 1			Level 2			Level 3			Total
Equities	3,008			1,894		—		4,902		3,008			1,894			—			4,902
Fixed income
Corporate debt	—			1,824		242		2,066		—			1,824			242			2,066
U.S. Treasury and agencies	1,323			15		—		1,338		1,323			15			—			1,338
Foreign governments	—			61		—		61		—			61			—			61
State and municipal debt	—			326		—		326		—			326			—			326
Other ^(c)	—			537		—		537		—		—	537		—	—		—	537
Fixed income subtotal	1,323			2,763		242		4,328		1,323			2,763			242			4,328
Middle market lending	—			—		428		428		—			—			428			428
Private equity	—			—		125		125		—			—			125			125
Real estate	—			—		35		35		—		—	—		—	35			35
Other	—			216		—		216		—			216			—			216
Nuclear decommissioning trust fund investments subtotal ^(d)	4,550			4,965		830		10,345		4,550			4,965			830			10,345
Pledged assets for Zion Station decommissioning
Cash equivalents	—			17		—		17		—			17			—			17
Equities	1			5		—		6		1			5			—			6
Fixed income
U.S. Treasury and agencies	6			2		—		8		6			2			—			8
Corporate debt	—			46		—		46		—			46			—			46
Other	—			1		—		1		—			1			—			1
Fixed income subtotal	6			49		—		55		6			49			—			55
Middle market lending	—			—		127		127		—			—			127			127
Pledged assets for Zion Station decommissioning subtotal ^(e)	7			71		127		205		7			71			127			205
Rabbi trust investments in mutual funds ^(f)	17		—	—		—		17		48			—			—			48
Commodity derivative assets
Economic hedges	1,922			3,467		1,707		7,096		1,922			3,467			1,707			7,096
Proprietary trading	36			64		30		130		36			64			30			130
Effect of netting and allocation of collateral ^(g)	(1,964	)		(2,629	)	(564	)	(5,157	)	(1,964	)		(2,629	)		(564	)		(5,157	)
Commodity derivative assets subtotal	(6	)		902		1,173		2,069		(6	)		902			1,173			2,069
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—		—		—		—			25			—			25
Economic hedges	—			20		—		20		—			20			—			20
Proprietary trading	10			5		—		15		10			5			—			15
Effect of netting and allocation of collateral	(3	)		(3	)	—		(6	)	(3	)		(3	)		—			(6	)
Interest rate and foreign currency derivative assets subtotal	7			22		—		29		7			47			—			54
Other investments	—			—		33		33		—			—			33			33
Total assets	4,679			5,960		2,163		12,802		10,372			5,985			2,163			18,520
Liabilities
Commodity derivative liabilities
Economic hedges	(2,382	)		(3,348	)	(850	)	(6,580	)	(2,382	)		(3,348	)		(1,097	)		(6,827	)
Proprietary trading	(33	)		(57	)	(37	)	(127	)	(33	)		(57	)		(37	)		(127	)
Effect of netting and allocation of collateral ^(g)	2,440			3,186		765		6,391		2,440			3,186			765			6,391
Commodity derivative liabilities subtotal	25			(219	)	(122	)	(316	)	25			(219	)		(369	)		(563	)
Interest rate and foreign currency derivative liabilities								—											—
Derivatives designated as hedging instruments	—			(16	)	—		(16	)	—			(16	)		—			(16	)
Economic hedges	—			(3	)	—		(3	)	—			(3	)		—			(3	)
Proprietary trading	(12	)		—		—		(12	)	(12	)		—			—			(12	)
Effect of netting and allocation of collateral	12			3		—		15		12			3			—			15



	Generation											Exelon
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Interest rate and foreign currency derivative liabilities subtotal	—		(16		)	—			(16		)	—		(16		)	—			(16		)
Deferred compensation obligation	—		(30		)	—			(30		)	—		(99		)	—			(99		)
Total liabilities	25		(265		)	(122		)	(362		)	25		(334		)	(369		)	(678		)
Total net assets	$	4,704	$	5,695		$	2,041		$	12,440		$	10,397	$	5,651		$	1,794		$	17,842

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



	Generation												Exelon
As of December 31, 2014	Level 1			Level 2			Level 3			Total			Level 1				Level 2				Level 3				Total
Assets
Cash equivalents ^(a)	$	405		$	—		$	—		$	405		$	1,119			$	—			$	—			$	1,119
Nuclear decommissioning trust fund investments
Cash equivalents ^(b)	208			37			—			245			208				37				—				245
Equities	3,035			2,207			—			5,242			3,035				2,207				—				5,242
Fixed income
Corporate debt	—			2,023			239			2,262			—				2,023				239				2,262
U.S. Treasury and agencies	996			—			—			996			996				—				—				996
Foreign governments	—			95			—			95			—				95				—				95
State and municipal debt	—			438			—			438			—				438				—				438
Other	—			511			—			511			—				511				—				511
Fixed income subtotal	996			3,067			239			4,302			996				3,067				239				4,302
Middle market lending	—			—			366			366			—				—				366				366
Private equity	—			—			83			83			—				—				83				83
Real estate	—			—			3			3			—			—	—			—	3				3
Other ^(c)	—			301			—			301			—				301				—				301
Nuclear decommissioning trust fund investments subtotal ^(d)	4,239			5,612			691			10,542			4,239				5,612				691				10,542
Pledged assets for Zion Station decommissioning
Cash equivalents	—			15			—			15			—				15				—				15
Equities	6			1			—			7			6				1				—				7
Fixed income
U.S. Treasury and agencies	5			3			—			8			5				3				—				8
Corporate debt	—			89			—			89			—				89				—				89
State and municipal debt	—			10			—			10			—				10				—				10
Other	—			3			—			3			—			—	3			—	—			—	3
Fixed income subtotal	5			105			—			110			5				105				—				110
Middle market lending	—			—			184			184			—				—				184				184
Pledged assets for Zion Station decommissioning subtotal ^(e)	11			121			184			316			11				121				184				316
Rabbi trust investments ^(f)
Cash equivalents	—			—			—			—			1				—				—				1
Mutual funds	16			—			—			16			46				—				—				46
Rabbi trust investments subtotal	16			—			—			16			47				—				—				47
Commodity derivative assets										—															—
Economic hedges	1,667			3,465			1,681			6,813			1,667				3,465				1,681				6,813
Proprietary trading	201			284			27			512			201				284				27				512
Effect of netting and allocation of collateral ^(g)	(1,982		)	(2,757		)	(557		)	(5,296		)	(1,982		)		(2,757		)		(557		)		(5,296		)
Commodity derivative assets subtotal	(114		)	992			1,151			2,029			(114		)		992				1,151				2,029
Interest rate and foreign currency derivative assets										—															—
Derivatives designated as hedging instruments	—			8			—			8			—				31				—				31
Economic hedges	—			12			—			12			—				13				—				13



	Generation												Exelon
As of December 31, 2014	Level 1			Level 2			Level 3			Total			Level 1			Level 2			Level 3			Total
Proprietary trading	18			9			—			27			18			9			—			27
Effect of netting and allocation of collateral	(17		)	(12		)	—			(29		)	(17		)	(31		)	—			(48		)
Interest rate and foreign currency derivative assets subtotal	1			17			—			18			1			22			—			23
Other investments	—			—			3			3			2			—			3			5
Total assets	4,558			6,742			2,029			13,329			5,305			6,747			2,029			14,081
Liabilities
Commodity derivative liabilities
Economic hedges	(2,241		)	(3,458		)	(788		)	(6,487		)	(2,241		)	(3,458		)	(995		)	(6,694		)
Proprietary trading	(195		)	(295		)	(42		)	(532		)	(195		)	(295		)	(42		)	(532		)
Effect of netting and allocation of collateral ^(g)	2,416			3,557			729			6,702			2,416			3,557			729			6,702
Commodity derivative liabilities subtotal	(20		)	(196		)	(101		)	(317		)	(20		)	(196		)	(308		)	(524		)
Interest rate and foreign currency derivative liabilities										—												—
Derivatives designated as hedging instruments	—			(12		)	—			(12		)	—			(41		)	—			(41		)
Economic hedges	—			(2		)	—			(2		)	—			(103		)	—			(103		)
Proprietary trading	(14		)	(9		)	—			(23		)	(14		)	(9		)	—			(23		)
Effect of netting and allocation of collateral	25			10			—			35			25			29			—			54
Interest rate and foreign currency derivative liabilities subtotal	11			(13		)	—			(2		)	11			(124		)	—			(113		)
Deferred compensation obligation	—			(31		)	—			(31		)	—			(107		)	—			(107		)
Total liabilities	(9		)	(240		)	(101		)	(350		)	(9		)	(427		)	(308		)	(744		)
Total net assets	$	4,549		$	6,502		$	1,928		$	12,979		$	5,296		$	6,320		$	1,721		$	13,337

_________________________


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


(b)	Includes $52 million and $43 million of cash received from outstanding repurchase agreements at December 31, 2015 and 2014, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

(d)


(e)	Excludes net assets of $1 million and $3 million at December 31, 2015 and 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.


(f)	Excludes $36 million and $35 million of cash surrender value of life insurance investment at December 31, 2015 and 2014, respectively, at Exelon Consolidated. Excludes $13 million and $11 million of cash surrender value of life insurance investment at December 31, 2015 and 2014, respectively, at Generation.

(g)

Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2015 and 2014:



	Generation																ComEd						Exelon
For The Year Ended December 31, 2015	Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments			Total Generation			Mark-to-Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of January 1, 2015	$	691		$	184		$	1,050			$	3		$	1,928		$	(207	)	$	—		$	1,721
Total realized / unrealized gains (losses)
Included in net income	4			—			22			^(a)	1			27			—			—			27
Included in noncurrent payables to affiliates	23			—			—				—			23			—			(23		)	—
Included in payable for Zion Station decommissioning	—			(2		)	—				—			(2		)	—			—			(2		)
Included in regulatory assets/liabilities	—			—			—				—			—			(40		)	23			(17		)
Change in collateral	—			—			29				—			29			—			—			29
Purchases, sales, issuances and settlements
Purchases	226			20			144				30			420			—			—			420
Sales	(8		)	(75		)	(25		)		—			(108		)	—			—			(108		)
Settlements	(106		)	—			—				—			(106		)	—			—			(106		)
Transfers into Level 3	4			—			80				—			84			—			—			84
Transfers out of Level 3	(4		)	—			(249		)		(1		)	(254		)	—			—			(254		)
Balance as of December 31, 2015	$	830		$	127		$	1,051			$	33		$	2,041		$	(247	)	$	—		$	1,794
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2015	$	4		$	—		$	856			$	—		$	860		$	—		$	—		$	860



	Generation							Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net ^(a)		Operating Revenues		Purchased Power and Fuel			Other, net ^(a)
Total gains (losses) included in net income for the year ended December 31, 2014	$	614	$	(88	)	$	6	$	614	$	(88	)	$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014	$	663	$	(23	)	$	4	$	663	$	(23	)	$	4

_________________________


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



	Generation							Exelon
	Operating Revenues		Purchased Power and Fuel			Other, net ^(a)		Operating Revenues		Purchased Power and Fuel			Other, net ^(a)
Total gains (losses) included in net income for the year ended December 31, 2015	$	67	$	(45	)	$	4	$	67	$	(45	)	$	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2015	$	858	$	(2	)	$	4	$	858	$	(2	)	$	4



	Generation																ComEd						Exelon
For The Year Ended December 31, 2014	Nuclear Decommissioning Trust Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives ^(d)				Other Investments			Total Generation			Mark-to-Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of January 1, 2014	$	350		$	112		$	465			$	15		$	942		$	(193	)	$	—		$	749
Total realized / unrealized gains (losses)
Included in net income	6			—			526			^(a)	—			532			—			—			532
Included in other comprehensive income	—			—			—				—			—			—			—			—
Included in noncurrent payables to affiliates	14			—			—				—			14			—			(14		)	—
Included in payable for Zion Station decommissioning	—			2			—				—			2			—			—			2
Included in regulatory assets/liabilities	—			—			—				—			—			(14		)	14			—
Change in collateral	—			—			198				—			198			—			—			198
Purchases, sales, issuances and settlements
Purchases	400			120			76			^(c)	2			598			—			—			598
Sales	(15		)	(50		)	(7		)		(8		)	(80		)	—			—			(80		)
Settlements	(64		)	—			—				—			(64		)	—			—			(64		)
Transfers into Level 3	—			—			(7		)		—			(7		)	—			—			(7		)
Transfers out of Level 3	—			—			(201		)		(6		)	(207		)	—			—			(207		)
Balance as of December 31, 2014	$	691		$	184		$	1,050			$	3		$	1,928		$	(207	)	$	—		$	1,721
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2014	$	4		$	—		$	640			$	—		$	644		$	—		$	—		$	644

_________________________


(a)	Includes a reduction for the reclassification of $834 million and $114 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2015 and 2014, respectively.

(b)


(c)	Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition.

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

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



Type of trade	Fair Value at December 31,2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Generation) ^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11	-	$88	^(d)
					Forward gas price	$1.18	-	$8.95	^(d)
				Option Model	Volatility percentage	5%	-	152%
Mark-to-market derivatives—Proprietary trading (Generation) ^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13	-	$78	^(d)
Mark-to-market derivatives (ComEd)	$	(247	)	Discounted Cash Flow	Forward heat rate ^(b)	9x	-	10x
					Marketability reserve	3.5%	-	7%
					Renewable factor	87%	-	128%

_________________________


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


(b)	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.


(c)	The fair values do not include cash collateral posted on level three positions of $201 million as of December 31, 2015.


(d)	Unlike the previous year, the New England region was not a significant driver for the upper end of the ranges for power and gas as of December 31, 2015.



Type of trade	Fair Value at December 31, 2014			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Generation) ^(a)(c)	$	893		Discounted Cash Flow	Forward power price	$15	-	$120	^(d)
					Forward gas price	$1.52	-	$14.02	^(d)
				Option Model	Volatility percentage	8%	-	257%
Mark-to-market derivatives— Proprietary trading (Generation) ^(a)(c)	$	(15	)	Discounted Cash Flow	Forward power price	$15	-	$117	^(d)
Mark-to-market derivatives (ComEd)	$	(207	)	Discounted Cash Flow	Forward heat rate ^(b)	8x	-	9x
					Marketability reserve	3.5%	-	8%
					Renewable factor	86%	-	126%

__________________________


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


(b)	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.


(c)	The fair values do not include cash collateral posted on level three positions of $172 million as of December 31, 2014


(d)	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 $97 and $8.14, respectively and would be approximately $76 for power proprietary trading.

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2015:



	Generation															Other								Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments		Economic Hedges		Collateral and Netting^(b)		Subtotal		Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	10		$	(5	)	$	15		$	—	$	—	$	—	$	—	$	15
Mark-to-market derivative assets (noncurrent assets)	—			10			5			(1		)	14			25		—		—		25		39
Total mark-to-market derivative assets	—			20			15			(6		)	29			25		—		—		25		54
Mark-to-market derivative liabilities (current liabilities)	(8		)	(2		)	(9		)	11			(8		)	—		—		—		—		(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(8		)	(1		)	(3		)	4			(8		)	—		—		—		—		(8		)
Total mark-to-market derivative liabilities	(16		)	(3		)	(12		)	15			(16		)	—		—		—		—		(16		)
Total mark-to-market derivative net assets (liabilities)	$	(16	)	$	17		$	3		$	9		$	13		$	25	$	—	$	—	$	25	$	38

_________________________

(a)

(b)

The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 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			Economic Hedges			Collateral and Netting^(b)			Subtotal			Total
Mark-to-market derivative assets (current assets)	$	7		$	7		$	20		$	(22	)	$	12		$	3		$	—		$	—		$	3		$	15
Mark-to-market derivative assets (noncurrent assets)	1			5			7			(7		)	6			20			1			(19		)	$	2		$	8
Total mark-to-market derivative assets	8			12			27			(29		)	18			23			1			(19		)	5			23
Mark-to-market derivative liabilities (current liabilities)	(8		)	(2		)	(14		)	25			1			—			—			—			—			1
Mark-to-market derivative liabilities (noncurrent liabilities)	(4		)	—			(9		)	10			(3		)	(29		)	(101		)	19			(111		)	(114		)
Total mark-to-market derivative liabilities	(12		)	(2		)	(23		)	35			(2		)	(29		)	(101		)	19			(111		)	(113		)
Total mark-to-market derivative net assets (liabilities)	$	(4	)	$	10		$	4		$	6		$	16		$	(6	)	$	(100	)	$	—		$	(106	)	$	(90	)

_________________________

(a)

(b)

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2015:



	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting ^(a)			Subtotal ^(b)			Economic Hedges ^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,236		$	108		$	(3,994	)	$	1,350		$	—		$	1,350
Mark-to-market derivative assets (noncurrent assets)	1,860			22			(1,163		)	719			—			719
Total mark-to-market derivative assets	7,096			130			(5,157		)	2,069			—			2,069
Mark-to-market derivative liabilities (current liabilities)	(4,907		)	(94		)	4,827			(174		)	(23		)	(197		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,673		)	(33		)	1,564			(142		)	(224		)	(366		)
Total mark-to-market derivative liabilities	(6,580		)	(127		)	6,391			(316		)	(247		)	(563		)
Total mark-to-market derivative net assets (liabilities)	$	516		$	3		$	1,234		$	1,753		$	(247	)	$	1,506

______________________

(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 $352 million and $180 million, respectively, and current and noncurrent liabilities are shown net of collateral of $480 million and $222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,234 million at December 31, 2015.


(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, 2014:



	Generation												ComEd			Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives
Mark-to-market derivative assets (current assets)	$	4,992		$	456		$	(4,184	)	$	1,264		$	—		$	1,264
Mark-to-market derivative assets (noncurrent assets)	1,821			56			(1,112		)	765			—			765
Total mark-to-market derivative assets	6,813			512			(5,296		)	2,029			—			2,029
Mark-to-market derivative liabilities (current liabilities)	(4,947		)	(468		)	5,200			(215		)	(20		)	(235		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,540		)	(64		)	1,502			(102		)	(187		)	(289		)
Total mark-to-market derivative liabilities	(6,487		)	(532		)	6,702			(317		)	(207		)	(524		)
Total mark-to-market derivative net assets (liabilities)	$	326		$	(20	)	$	1,406		$	1,712		$	(207	)	$	1,505

______________________

(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 $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.


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

Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense

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:



		Year Ended December 31,
	Income Statement Location	2015			2014			2013			2015			2014		2013
	Income Statement Location	Gain (Loss) on Swaps									Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	(1	)	$	(16	)	$	(15	)	$	—		$	2	$	(6	)
Exelon	Interest expense	$	2		$	3		$	(24	)	$	(9	)	$	15	$	(3	)

______________________


(a)	For the years ended December 31, 2015 and 2014, the loss on Generation swaps included $(1) million and $(17) million realized in earnings, respectively, with an immaterial amount and $4 million excluded from hedge effectiveness testing, respectively.

The activity of accumulated OCI related to cash flow hedges



	Income Statement Location	Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
		Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative gain at January 1, 2014		$	114			$	120
Effective portion of changes in fair value		(15		)		(31		)
Reclassifications from accumulated OCI to net income	Operating revenues	(117		)	^(a)	(117		)	^(a)
Accumulated OCI derivative gain at December 31, 2014		(18		)		(28		)
Effective portion of changes in fair value		(8		)		(12		)
Reclassifications from accumulated OCI to net income	Other, net	—				16			^(b)
Reclassifications from accumulated OCI to net income	Interest expense	7			^(c)	7			^(c)
Reclassifications from accumulated OCI to net income	Operating revenues	(2		)		(2		)
Accumulated OCI derivative gain at December 31, 2015		$	(21	)		$	(19	)

_______________________


(a)	Amount is net of related income tax expense of $78 million for the year ended December 31, 2014.


(b)	Amount is net of related income tax benefit of $10 million for the year ended December 31, 2015.


(c)	Amount is net of related income tax expense of $4 million for the year ended December 31, 2015.

Change in fair value and reclassification of derivative contracts

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.



	Location on Income Statement	For the Years Ended December 31,
	Location on Income Statement	2015			2014			2013
Change in fair value of commodity positions	Operating Revenues	$	8		$	(1	)	$	(22	)
Reclassification to realized at settlement of commodity positions	Operating Revenues	(14		)	(29		)	(15		)
Net commodity mark-to-market gains (losses)	Operating Revenues	(6		)	(30		)	(37		)
Change in fair value of treasury positions	Operating Revenues	8			1			1
Reclassification to realized at settlement of treasury positions	Operating Revenues	(10		)	3			(3		)
Net treasury mark-to market gains (losses)	Operating Revenues	(2		)	4			(2		)
Net mark-to market gains (losses)	Operating Revenues	$	(8	)	$	(26	)	$	(39	)



	Generation												Intercompany Eliminations		Exelon Corporate			Exelon
Year Ended December 31, 2015	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			Operating Revenues ^(a)		Interest Expense			Total
Change in fair value of commodity positions	$	759		$	(355	)	$	—		$	404		$	—	$	—		$	404
Reclassification to realized at settlement of commodity positions	(563		)	409			—			(154		)	—		—			(154		)
Net commodity mark-to-market gains (losses)	196			54			—			250			—		—			250
Change in fair value of treasury positions	13			—			—			13			—		36			49
Reclassification to realized at settlement of treasury positions	(6		)	—			—			(6		)	—		64			58
Net treasury mark-to market gains (losses)	7			—			—			7			—		100			107
Net mark-to market gains (losses)	$	203		$	54		$	—		$	257		$	—	$	100		$	357
	Generation												Intercompany Eliminations		Exelon Corporate			Exelon
Year Ended December 31, 2014	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			Operating Revenues (a)		Interest Expense			Total
Change in fair value of commodity positions	$	(413	)	$	(194	)	$	—		$	(607	)	$	—	$	—		$	(607	)
Reclassification to realized at settlement of commodity positions	231			(223		)	—			8			—		—			8
Net commodity mark-to-market gains (losses)	(182		)	(417		)	—			(599		)	—		—			(599		)
Change in fair value of treasury positions	10			—			(2		)	8			—		(100		)	(92		)
Reclassification to realized at settlement of treasury positions	(2		)	—			—			(2		)	—		—			(2		)
Net treasury mark-to market gains (losses)	8			—			(2		)	6			—		(100		)	(94		)
Net mark-to market gains (losses)	$	(174	)	$	(417	)	$	(2	)	$	(593	)	$	—	$	(100	)	$	(693	)



	Generation											Intercompany Eliminations			Exelon Corporate		Exelon
Year Ended December 31, 2013	Operating Revenues			Purchased Power and Fuel		Interest Expense			Total			Operating Revenues ^(a)			Interest Expense		Total
Change in fair value of commodity positions	$	286		$	180	$	—		$	466		$	(6	)	$	—	$	460
Reclassification to realized at settlement of commodity positions	(64		)	104		—			40			13			—		53
Net commodity mark-to-market gains (losses)	222			284		—			506			7			—		513
Change in fair value of treasury positions	(1		)	—		(4		)	(5		)	—			—		(5		)
Reclassification to realized at settlement of treasury positions	(1		)	—		—			(1		)	—			—		(1		)
Net treasury mark-to market gains (losses)	(2		)	—		(4		)	(6		)	—			—		(6		)
Net mark-to market gains (losses)	$	220		$	284	$	(4	)	$	500		$	7		$	—	$	507

________________________


(a)	Prior to the Constellation 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.

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

The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 7A.—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 $15 million, $36 million and $31 million, respectively.



Rating as of December 31, 2015	Total Exposure Before Credit Collateral		Credit Collateral ^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,397	$	50	$	1,347	1	$	432
Non-investment grade	67		25		42		—	—
No external ratings
Internally rated—investment grade	521		—		521		—	—
Internally rated—non-investment grade	77		7		70		—	—
Total	$	2,062	$	82	$	1,980	1	$	432



Net Credit Exposure by Type of Counterparty	December 31, 2015
Financial institutions	$	187
Investor-owned utilities, marketers, power producers	886
Energy cooperatives and municipalities	872
Other	35
Total	$	1,980

______________________


(a)	As of December 31, 2015, credit collateral held from counterparties where Generation had credit exposure included $13 million of cash and $69 million of letters of credit.



	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2015			2014
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(932	)	$	(1,433	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	684			1,140
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(248	)	$	(293	)

__________________________


(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.


(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.


(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2015

Debt Disclosure [Abstract]

Schedule of Short-term Debt

Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2015 and 2014:



	Maximum Program Size at December 31,				Outstanding Commercial Paper at December 31,				Average Interest Rate on Commercial Paper Borrowings for the Year Ended December 31,
Commercial Paper Issuer	2015 (a)(b)		2014 (a)(b)		2015		2014		2015		2014
Exelon Corporate	$	500	$	500	$	—	$	—	n.a.		n.a.
Generation	5,450		5,600		—		—		0.49	%	0.32	%
ComEd	1,000		1,000		294		304		0.53	%	0.33	%
PECO	600		600		—		—		n.a.		n.a.
BGE	600		600		210		120		0.48	%	0.29	%
Total	$	8,150	$	8,300	$	504	$	424

_____________________


(a)	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generation as of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effective program size.

(b)

Exelon



	2015			2014			2013
Average borrowings	$	499		$	571		$	254
Maximum borrowings outstanding	739			1,164			682
Average interest rates, computed on a daily basis	0.53		%	0.32		%	0.37		%
Average interest rates, at December 31	0.88		%	0.53		%	0.35		%
Generation
	2015			2014			2013
Average borrowings	$	1		$	93		$	42
Maximum borrowings outstanding	50			552			291
Average interest rates, computed on a daily basis	0.49		%	0.32		%	0.32		%
Average interest rates, at December 31	n.a.			n.a.			n.a.



ComEd
	2015			2014			2013
Average borrowings	$	461		$	415		$	203
Maximum borrowings outstanding	684			597			446
Average interest rates, computed on a daily basis	0.53		%	0.33		%	0.40		%
Average interest rates, at December 31	0.89		%	0.50		%	0.37		%
BGE
	2015			2014			2013
Average borrowings	$	37		$	64		$	35
Maximum borrowings outstanding	210			180			135
Average interest rates, computed on a daily basis	0.48		%	0.29		%	0.31		%
Average interest rates, computed at December 31	0.87		%	0.61		%	0.31		%

Schedule of Line of Credit Facilities

At December 31, 2015, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:



							Available Capacity at December 31, 2015
Borrower	Aggregate Bank Commitment ^(a)		Facility Draws		Outstanding Letters of Credit^(c)		Actual		To Support Additional Commercial Paper ^(b)
Exelon Corporate	$	500	$	—	$	26	$	474	$	474
Generation	5,725		—		1,449		4,276		4,174
ComEd	1,000		—		2		998		704
PECO	600		—		1		599		599
BGE	600		—		—		600		390
Total	$	8,425	$	—	$	1,478	$	6,947	$	6,341

_______________________

(a)


(b)	Excludes $275 million bilateral credit facilities that do not back Generation’s commercial paper program.


(c)	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.

Schedule Of Credit Agreement Covenants

The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2015:



	Exelon	Generation	ComEd	PECO	BGE
Credit agreement threshold	2.50 to 1	3.00 to 1	2.00 to 1	2.00 to 1	2.00 to 1

At December 31, 2015, the interest coverage ratios at the Registrants were as follows:



	Exelon	Generation	ComEd	PECO	BGE
Interest coverage ratio	9.77	12.31	7.25	8.94	10.66

Schedule of Long-term Debt Instruments

PECO



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
First mortgage bonds ^(a)	1.20	%	-	5.95	%	2016 - 2044	$	2,600		$	2,250
Total long-term debt							2,600			2,250
Unamortized debt discount and premium, net							(5		)	(4		)
Unamortized debt issuance costs ^(b)							(15		)	(14		)
Long-term debt due within one year							(300		)	—
Long-term debt							$	2,280		$	2,232
Long-term debt to financing trusts ^(c)
Subordinated debentures to PECO Trust III				7.38	%	2028	$	81		$	81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103			103
Long-term debt to financing trusts							$	184		$	184

_____________________


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


(b)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

Generation



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Senior unsecured notes	2.00	%	-	7.60	%	2017 - 2042	$	5,971		$	5,771
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			—
Nuclear fuel procurement contracts	3.15	%	-	3.35	%	2018 - 2020	127			70
Notes payable and other ^(a)(b)	1.43	%		7.83	%	2016 - 2035	166			26
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,162			1,166
Variable rates	2.42	%	-	5.00	%	2017 - 2030	1,058			1,101
Total long-term debt							8,919			8,134
Fair value adjustment							127			146
Unamortized debt discount and premium, net							(17		)	(14		)
Unamortized debt issuance costs ^(c)							(70		)	(70		)
Long-term debt due within one year							(90		)	(614		)
Long-term debt							$	8,869		$	7,582

______________________


(a)	Includes Generation’s capital lease obligations of $21 million and $24 million at December 31, 2015 and 2014, respectively. Generation will make lease payments of $4 million, $4 million, $4 million, $5 million and $4 million in 2016, 2017, 2018, 2019, 2020, respectively.

The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2015 and 2014:

Exelon



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Rate stabilization bonds	5.72	%	-	5.82	%	2017	$	120		$	195
First mortgage bonds ^(a)	1.20	%	-	6.45	%	2016 - 2045	9,019			8,079
Senior unsecured notes	1.55	%	-	7.60	%	2017 - 2045	9,803			7,071
Unsecured bonds	2.80	%	-	6.35	%	2016 - 2036	1,750			1,750
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			—
Nuclear fuel procurement contracts	3.15	%	-	3.35	%	2018 - 2020	127			70
Notes payable and other ^(b)(c)	1.43	%	-	7.83	%	2016 - 2053	314			174
Junior subordinated notes				6.50	%	2024	1,150			1,150
Contract payment - junior subordinated notes				2.50	%	2017	64			108
Long-term software licensing agreement				3.95	%	2024	111			—
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,162			1,166
Variable rates	2.42	%	-	5.00	%	2017 - 2030	1,058			1,101
Total long-term debt							25,113			20,864
Unamortized debt discount and premium, net							(63		)	(37		)
Unamortized debt issuance costs ^(d)							(180		)	(150		)
Fair value adjustment							275			333
Fair value hedge carrying value adjustment, net							—			4
Long-term debt due within one year							(1,500		)	(1,802		)
Long-term debt							$	23,645		$	19,212
Long-term debt to financing trusts ^(e)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Subordinated debentures to PECO Trust III				7.38	%	2028	81			81
Subordinated debentures to PECO Trust IV				5.75	%	2033	103			103
Subordinated debentures to BGE Trust				6.20	%	2043	258			258
Total long-term debt to financing trusts							648			648
Unamortized debt issuance costs ^(d)							(7		)	(7		)
Long-term debt to financing trusts							$	641		$	641

____________________


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


(b)	Includes capital lease obligations of $29 million and $32 million at December 31, 2015 and 2014, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $4 million, and $8 million will be made in 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.


(c)	Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2 - Variable Interest Entities for additional information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.


(d)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

ComEd



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
First mortgage bonds ^(a)	1.95	%	-	6.45	%	2016 - 2045	$	6,419		$	5,829
Notes payable and other^(b)	6.95	%	-	7.49	%	2016 - 2053	148			148
Total long-term debt							6,567			5,977
Unamortized debt discount and premium, net							(20		)	(19		)
Unamortized debt issuance costs ^(c)							(38		)	(33		)
Long-term debt due within one year							(665		)	(260		)
Long-term debt							$	5,844		$	5,665
Long-term debt to financing trust ^(d)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Total long-term debt to financing trusts							206			206
Unamortized debt issuance costs ^(c)							(1		)	(1		)
Long-term debt to financing trusts							$	205		$	205

______________________


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


(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2015 and 2014, respectively. Lease payments of less than $1 million will be made from 2016 through expiration at 2053.


(c)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

BGE



						Maturity Date	December 31,
	Rates					Maturity Date	2015			2014
Long-term debt
Rate stabilization bonds	5.72	%	-	5.82	%	2017	$	120		$	195
Senior unsecured notes	2.80	%	-	6.35	%	2016 - 2036	1,750			1,750
Total long-term debt							1,870			1,945
Unamortized debt discount and premium, net							(3		)	(3		)
Unamortized debt issuance costs ^(a)							(9		)	(10		)
Long-term debt due within one year							(378		)	(75		)
Long-term debt							$	1,480		$	1,857
Long-term debt to financing trusts ^(b)
Subordinated debentures to BGE Capital Trust II				6.20	%	2043	$	258		$	258
Total long-term debt to financing trusts							258			258
Unamortized debt issuance costs ^(a)							(6		)	(6		)
Long-term debt to financing trusts							$	252		$	252

___________________


(a)	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.


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

Schedule of Maturities of Long-term Debt

Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2016 through 2020 and thereafter are as follows:



Year	Exelon			Generation		ComEd			PECO			BGE
2016	$	1,487		$	90	$	665		$	300		$	378
2017	1,841			805		425			—			42
2018	1,393			53		840			500			—
2019	973			673		300			—			—
2020	3,311			1,911		500			—			—
Thereafter	16,756		^(a)	5,387		4,043		^(b)	1,984		^(c)	1,708		^(d)
Total	$	25,761		$	8,919	$	6,773		$	2,784		$	2,128

____________________


(a)	Includes $648 million due to ComEd, PECO and BGE financing trusts.


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


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


(d)	Includes $258 million due to BGE financing trust.

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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Schedule of Components of Income Tax Expense (Benefit)

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2015

Income Tax Disclosure [Abstract]

The following table represents the net interest receivable (payable), including interest related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.



Net interest receivable (payable) as of	Exelon			Generation		ComEd			PECO		BGE
December 31, 2015	$	(288	)	$	80	$	(210	)	$	3	$	(1	)
December 31, 2014	(310		)	40		(203		)	3		(1		)

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



For the Year Ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	407		$	546		$	(80	)	$	64		$	25
Deferred	566			16			310			69			126
Investment tax credit amortization	(22		)	(19		)	(2		)	—			(1		)
State
Current	(86		)	(90		)	7			(10		)	—
Deferred	208			49			45			20			39
Total	$	1,073		$	502		$	280		$	143		$	189
For the Year Ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	121		$	360		$	(171	)	$	28		$	24
Deferred	576			(35		)	395			87			90
Investment tax credit amortization	(20		)	(16		)	(2		)	—			(1		)
State
Current	42			35			7			(2		)	—
Deferred	(53		)	(137		)	39			1			27
Total	$	666		$	207		$	268		$	114		$	140
For the Year Ended December 31, 2013	Exelon			Generation			ComEd			PECO			BGE
Included in operations:
Federal
Current	$	744		$	250		$	160		$	126		$	9
Deferred	140			360			(27		)	23			100
Investment tax credit amortization	(15		)	(11		)	(2		)	(1		)	(1		)
State
Current	181			50			50			16			—
Deferred	(6		)	(34		)	(29		)	(2		)	26
Total	$	1,044		$	615		$	152		$	162		$	134

Interest Income and Interest Expense Disclosure [Table Text Block]



Net interest expense (income) for the years ended	Exelon			Generation			ComEd		PECO			BGE
December 31, 2015	$	(13	)	$	(31	)	$	7	$	—		$	—
December 31, 2014	(36		)	(50		)	6		—			1
December 31, 2013	391			17			281		(1		)	—

Effective Income Tax Rate Reconciliation

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



For the Year Ended December 31, 2015	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	3.7		1.0		4.9		1.0		5.3
Qualified nuclear decommissioning trust fund loss	(0.4	)	(0.8	)	—		—		—
Domestic production activities deduction	(0.7	)	(1.3	)	—		—		—
Health care reform legislation	—		—		—		—		0.1
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9	)	(1.5	)	(0.3	)	(0.1	)	(0.1	)
Plant basis differences	(1.5	)	—		(0.1	)	(8.7	)	(0.7	)
Production tax credits and other credits	(1.9	)	(3.4	)	—		—		—
Non-controlling interest	0.3		0.5		—		—		—
Statute of limitations expiration	(1.4	)	(2.4	)	—		—		—
Other	—		—		0.2		0.2		—
Effective income tax rate	32.2	%	27.1	%	39.7	%	27.4	%	39.6	%
For the Year Ended December 31, 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	1.3		(1.9	)	4.5		(0.1	)	5.0
Qualified nuclear decommissioning trust fund income	2.4		4.8		—		—		—
Domestic production activities deduction	(2.0	)	(4.1	)	—		—		—
Health care reform legislation	0.1		—		0.2		—		0.2
Amortization of investment tax credit, including deferred taxes on basis difference	(1.1	)	(2.0	)	(0.3	)	(0.1	)	(0.3	)
Plant basis differences	(1.9	)	—		(0.1	)	(10.4	)	0.2
Production tax credits and other credits	(2.4	)	(4.8	)	—		—		—
Non-controlling interest	(1.8	)	(3.7	)
Statute of limitations expiration	(2.6	)	(5.3	)	—		—		—
Other	(0.2	)	(1.1	)	0.3		0.1		(0.2	)
Effective income tax rate	26.8	%	16.9	%	39.6	%	24.5	%	39.9	%
For the Year Ended December 31, 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	4.8		1.8		3.4		1.6		4.9
Qualified nuclear decommissioning trust fund income	3.7		6.1		—		—		—
Domestic production activities deduction	—		—		—		—		—
Health care reform legislation	0.1		—		0.7		—		0.2
Amortization of investment tax credit, including deferred taxes on basis difference	(1.9	)	(3.0	)	(0.6	)	(0.1	)	—
Plant basis differences	(1.6	)	—		(0.8	)	(7.1	)	(0.2	)
Production tax credits and other credits	(2.1	)	(3.4	)	(0.1	)	—		—
Statute of limitations expiration	(0.1	)	(0.2	)	—		—		—
Other	(0.3	)	0.4		0.3		(0.3	)	(0.9	)
Effective income tax rate	37.6	%	36.7	%	37.9	%	29.1	%	39.0	%

Tax Effects of Temporary Differences

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2015 and 2014 are presented below:



For the Year Ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(13,393	)	$	(4,269	)	$	(4,424	)	$	(2,901	)	$	(1,821	)
Accrual based contracts	(136		)	(136		)	—			—			—
Derivatives and other financial instruments	(203		)	(181		)	(4		)	—			—
Deferred pension and postretirement obligation	1,801			(371		)	(505		)	(9		)	(47		)
Nuclear decommissioning activities	(592		)	(592		)	—			—			—
Deferred debt refinancing costs	133			48			(15		)	(1		)	(4		)
Regulatory assets and liabilities	(1,706		)	—			(219		)	16			(264		)
Tax loss carryforward	103			56			—			—			33
Tax credit carryforward	327			374			—			—			—
Investment in CENG	(595		)	(595		)	—			—			—
Other, net	1,112			425			270			105			27
Deferred income tax liabilities (net)	$	(13,149	)	$	(5,241	)	$	(4,897	)	$	(2,790	)	$	(2,076	)
Unamortized investment tax credits	(622		)	(598		)	(17		)	(2		)	(5		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(13,771	)	$	(5,839	)	$	(4,914	)	$	(2,792	)	$	(2,081	)
For the Year Ended December 31, 2014	Exelon			Generation			ComEd			PECO			BGE
Plant basis differences	$	(12,143	)	$	(3,834	)	$	(3,945	)	$	(2,749	)	$	(1,660	)
Accrual based contracts	(178		)	(178		)	—			—			—
Derivatives and other financial instruments	(46		)	(79		)	(4		)	—			—
Deferred pension and postretirement obligation	1,914			(390		)	(543		)	2			(53		)
Nuclear decommissioning activities	(726		)	(726		)	—			—			—
Deferred debt refinancing costs	112			57			(18		)	(2		)	(4		)
Regulatory assets and liabilities	(1,824		)	—			(286		)	27			(258		)
Tax loss carryforward	111			48			—			11			39
Tax credit carryforward	97			143			—			—			—
Investment in CENG	(563		)	(563		)	—			—			—
Other, net	1,029			346			255			111			30
Deferred income tax liabilities (net)	$	(12,217	)	$	(5,176	)	$	(4,541	)	$	(2,600	)	$	(1,906	)
Unamortized investment tax credits	(555		)	(528		)	(20		)	(2		)	(5		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(12,772	)	$	(5,704	)	$	(4,561	)	$	(2,602	)	$	(1,911	)

Summary of Loss Carryforwards

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2015.



	Exelon		Generation		ComEd	PECO	BGE
Federal
Federal general business credits carryforward	416	^(a)	415		—	—	—
State
State net operating losses and other credit carryforwards	2,086	^(b)	1,259	^(b)	—	—	618	^(c)
Deferred taxes on state tax attributes (net)	117		66		—	—	34
Valuation allowance on state tax attributes	13		11		—	—	1

_____________________


(a)	Exelon’s federal general business credit carryforwards will expire beginning in 2032.


(b)	Exelon’s and Generation's state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2016.


(c)	BGE’s state net operating losses will expire beginning in 2026

Reconciliation of Unrecognized Tax Benefits Excluding Amounts Pertaining to Examined Tax Returns Foll Forward

The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2015, 2014 and 2013:



	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2015	$	1,829		$	1,357		$	149		$	44		$	—
Increases based on tax positions related to 2015	108			—			—			—			106
Change to positions that only affect timing	(705		)	(659		)	(7		)	(44		)	—
Increases based on tax positions prior to 2015	79			65			—			—			14
Decreases based on tax positions prior to 2015	(116		)	(112		)	—			—			—
Decrease from settlements with taxing authorities	(31		)	(31		)	—			—			—
Decreases from expiration of statute of limitations	(86		)	(86		)	—			—			—
Unrecognized tax benefits at December 31, 2015	$	1,078		$	534		$	142		$	—		$	120
	Exelon			Generation			ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2014	$	2,175		$	1,415		$	324		$	44		$	—
Increases based on tax positions related to 2014	15			15			—			—			—
Change to positions that only affect timing	(255		)	33			(175		)	—			—
Increases based on tax positions prior to 2014	18			18			—			—			—
Decreases based on tax positions prior to 2014	(1		)	(2		)	—			—			—
Decrease from settlements with taxing authorities	(35		)	(34		)	—			—			—
Decreases from expiration of statute of limitations	(88		)	(88		)	—			—			—
Unrecognized tax benefits at December 31, 2014	$	1,829		$	1,357		$	149		$	44		$	—



	Exelon			Generation			ComEd		PECO		BGE
Unrecognized tax benefits at January 1, 2013	$	1,024		$	876		$	67	$	44	$	—
Increases based on tax positions related to 2013	19			19			—		—		—
Change to positions that only affect timing	649			36			257		—		—
Increases based on tax positions prior to 2013	493			493			—		—		—
Decreases based on tax positions prior to 2013	(6		)	(5		)	—		—		—
Decreases from expiration of statute of limitations	(4		)	(4		)	—		—		—
Unrecognized tax benefits at December 31, 2013	$	2,175		$	1,415		$	324	$	44	$	—

Summary of Open Tax Years by Jurisdiction

Description of tax years that remain open to assessment by major jurisdiction



Taxpayer	Open Years
Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns	1999, 2001-2014
Exelon and subsidiaries Illinois unitary income tax returns	2007-2014
Constellation combined New York corporate income tax returns	2010-March 2012
Various separate company Pennsylvania corporate net income tax returns	2010-2014
BGE Maryland corporate net income tax returns	2011-2014
Various Exelon Maryland corporate net income tax returns	2012-2014
Various Constellation (Non-BGE) Maryland corporate net income tax returns	2011-2014

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2015

Asset Retirement Obligation Disclosure [Abstract]

Nuclear Decommissioning Asset Retirement Obligation Rollforward

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2014 to December 31, 2015:



	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2014	$	4,855
Consolidation of CENG ^(a)	1,760
Accretion expense	334
Net increase due to changes in, and timing of, estimated future cash flows	19
Costs incurred to decommission retired plants	(7		)
Nuclear decommissioning ARO at December 31, 2014^(b)	6,961
Accretion expense	387
Net increase due to changes in, and timing of, estimated future cash flows	901
Costs incurred to decommission retired plants	(3		)
Nuclear decommissioning ARO at December 31, 2015 ^(b)	$	8,246

_________________________


(a)	Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.


(b)	Includes $7 million and $8 million as the current portion of the ARO at December 31, 2015 and 2014, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

Unrealized Gains Losses On Nuclear Decommissioning Trust Funds

The following table provides unrealized gains on NDT funds for 2015, 2014 and 2013:



	Exelon and Generation
	For the Years Ended December 31,
	2015			2014		2013
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	(282	)	$	180	$	406
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units ^(b)(c)	(197		)	134		146

_______________________


(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 $7 million, $29 million and $7 million of net unrealized gains related to the Zion Station pledged assets in 2015, 2014 and 2013, respectively. Net unrealized gains 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.

Nuclear Decommissioning Pledged Assets

The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2015 and 2014:



	Exelon and Generation
	2015		2014
Carrying value of Zion Station pledged assets	$	206	$	319
Payable to Zion Solutions ^(a)	189		292
Current portion of payable to Zion Solutions ^(b)	99		137
Cumulative withdrawals by Zion Solutions to pay decommissioning costs ^(c)	786		666

___________________


(a)	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.


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


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

Non Nuclear Decommissioning Asset Retirement Obligation Rollforward

The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2014 to December 31, 2015:



	Exelon			Generation			ComEd			PECO			BGE
Non-nuclear AROs at January 1, 2014	$	351		$	201		$	101		$	30		$	19
Net increase (decrease) due to changes in, and timing of, estimated future cash flows ^(a)	(1		)	(2		)	2			—			(1		)
Development projects ^(b)	11			11			—			—			—
Accretion expense ^(c)	15			11			3			1			—
Liabilities held for sale ^(d)	(4		)	(4		)	—			—			—
Sale of generating assets ^(e)	(20		)	(20		)	—			—			—
Payments	(6		)	(3		)	(2		)	(1		)	—
Non-nuclear AROs at December 31, 2014 ^(f)	346			194			104			30			18
Net increase (decrease) due to changes in, and timing of, estimated future cash flows ^(a)	(10		)	(12		)	6			(4		)	—
Development projects ^(b)	10			10			—			—			—
Accretion expense ^(c)	16			10			5			1			—
Sale of generating assets ^(e)	(2		)	(2		)	—			—			—
Payments	(5		)	(3		)	(2		)	—			—
Non-nuclear AROs at December 31, 2015 ^(f)	$	355		$	197		$	113		$	27		$	18

________________________

(a)


(b)	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.


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


(d)	Represents AROs related to generating stations classified as held for sale. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.


(e)	Reflects a reduction to the ARO resulting primarily from the sales of Schuylkill generating station in 2015 and Keystone and Conemaugh generating stations in 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.

(f)

Implications of Potential Early Plant Retirements Implications of Potential Early Plant Retirements (Tables)

12 Months Ended

Dec. 31, 2015

Implications of Potential Early Plant Retirements [Abstract]

Implications of Potential Early Plant Retirement [Table Text Block] [Table Text Block]



(in millions)	Quad Cities			Clinton				Ginna			Total
Asset Balances
Materials and supplies inventory	$	50		$	57			$	29		$	136
Nuclear fuel inventory, net	218			107				60			385
Completed plant, net	1,030			579				127			1,736
Construction work in progress	11			9				11			31

Liability Balances
Asset retirement obligation	(698		)	(401		)		(644		)	(1,743		)

NRC License Renewal Term	2032			2046			^(a)	2029

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Schedule Of Pension And Other Postretirement Participation



	Operating Company^(d)
Name of Plan:	Generation	ComEd	PECO	BGE	BSC
Qualified Pension Plans:
Exelon Corporation Retirement Program^(a)	X	X	X	X	X
Exelon Corporation Cash Balance Pension Plan^(a)	X	X	X	X	X
Exelon Corporation Pension Plan for Bargaining Unit Employees^(a)	X	X			X
Exelon New England Union Employees Pension Plan^(a)	X
Exelon Employee Pension Plan for Clinton, TMI and Oyster Creek^(a)	X	X	X		X
Pension Plan of Constellation Energy Group, Inc.^(b)	X	X	X	X	X
Pension Plan of Constellation Energy Nuclear Group, LLC^(c)	X			X	X
Nine Mile Point Pension Plan^(c)	X				X
Constellation Mystic Power, LLC Union Employees Pension Plan Including Plan A and Plan B^(b)	X
Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan and 2000 Excess Benefit Plan^(a)	X	X	X		X
Exelon Corporation Supplemental Management Retirement Plan^(a)	X	X	X	X	X
Constellation Energy Group, Inc. Senior Executive Supplemental Plan^(b)	X			X	X
Constellation Energy Group, Inc. Supplemental Pension Plan^(b)	X			X	X
Constellation Energy Group, Inc. Benefits Restoration Plan^(b)	X	X		X	X
Constellation Nuclear Plan, LLC Executive Retirement Plan^(c)	X				X
Constellation Energy Nuclear Plan, LLC Benefits Restoration Plan^(c)	X				X
Baltimore Gas & Electric Company Executive Benefit Plan^(b)	X			X	X
Baltimore Gas & Electric Company Manager Benefit Plan^(b)	X	X		X	X



	Operating Company^(d)
Name of Plan:	Generation	ComEd	PECO	BGE	BSC
Other Postretirement Benefit Plans:
PECO Energy Company Retiree Medical Plan^(a)	X	X	X	X	X
Exelon Corporation Health Care Program^(a)	X	X	X	X	X
Exelon Corporation Employees’ Life Insurance Plan^(a)	X	X	X	X	X
Constellation Energy Group, Inc. Retiree Medical Plan^(b)	X	X	X	X	X
Constellation Energy Group, Inc. Retiree Dental Plan^(b)	X			X	X
Constellation Energy Group, Inc. Employee Life Insurance Plan and Family Life Insurance Plan^(b)	X	X	X	X	X
Constellation Mystic Power, LLC Post-Employment Medical Account Savings Plan^(b)	X
Exelon New England Union Post-Employment Medical Savings Account Plan^(a)	X
Retiree Medical Plan of Constellation Energy Nuclear Group LLC^(c)	X			X	X
Retiree Dental Plan of Constellation Energy Nuclear Group LLC^(c)	X			X	X
Nine Mile Point Nuclear Station, LLC Medical Care and Prescription Drug Plan for Retired Employees^(c)	X				X

______________________


(a)	These plans are collectively referred to as the Legacy Exelon plans.


(b)	These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans.


(c)	These plans are collectively referred to as the Legacy CENG plans.


(d)	Employees generally remain in their legacy benefit plans when transferring between operating companies.

Defined Benefit Plan Change In Benefit Obligation RollForward

The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:



	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Change in benefit obligation:
Net benefit obligation at beginning of year	$	18,256		$	15,459		$	4,197		$	4,451
Service cost	326			293			119			117
Interest cost	710			749			167			186
Plan participants’ contributions	—			—			42			42
Actuarial (gain) loss	(582		)	2,095			(341		)	502
Plan amendments	—			—			(23		)	(1,012		)
Acquisitions/divestitures^(a)	—			594			—			142
Curtailments	—			(8		)	—			—
Settlements	(34		)	(30		)	—			—
Gross benefits paid	(923		)	(896		)	(223		)	(231		)
Net benefit obligation at end of year	$	17,753		$	18,256		$	3,938		$	4,197



	Pension Benefits						Other Postretirement Benefits
	2015			2014			2015			2014
Change in plan assets:
Fair value of net plan assets at beginning of year	$	14,874		$	13,571		$	2,430		$	2,238
Actual return on plan assets	(32		)	1,443			4			90
Employer contributions	462			332			40			291
Plan participants’ contributions	—			—			42			42
Gross benefits paid	(923		)	(896		)	(223		)	(231		)
Acquisitions/divestitures^(a)	—			454			—			—
Settlements	(34		)	(30		)	—			—
Fair value of net plan assets at end of year	$	14,347		$	14,874		$	2,293		$	2,430

_______________________


(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.

Schedule of Amounts Recognized in Balance Sheet

Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:



	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015		2014
Other current liabilities	$	21	$	16	$	27	$	25
Pension obligations	3,385		3,366		—		—
Non-pension postretirement benefit obligations	—		—		1,618		1,742
Unfunded status (net benefit obligation less net plan assets)	$	3,406	$	3,382	$	1,645	$	1,767

Defined Benefit Plan Pension Plans With Projected Benefit Obligations And Accumulated Benefit Obligations In Excess Of Plan Assets



	PBO in excess of plan assets
	2015		2014
Projected benefit obligation	$	17,753	$	18,256
Fair value of net plan assets	14,347		14,874



	ABO in excess of plan assets
	2015		2014
Projected benefit obligation	$	17,753	$	18,256
Accumulated benefit obligation	16,792		17,191
Fair value of net plan assets	14,347		14,874

Schedule of Defined Benefit Plans Disclosures

A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant's Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2015, 2014 and 2013.



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Components of net periodic benefit cost:
Service cost	$	326		$	293		$	317		$	119		$	117		$	162
Interest cost	710			749			650			167			186			194
Expected return on assets	(1,026		)	(994		)	(1,015		)	(151		)	(154		)	(132		)
Amortization of:
Prior service cost (credit)	13			14			14			(174		)	(122		)	(19		)
Actuarial loss	571			420			562			80			50			83
Settlement charges	2			2			9			—			—			—
Net periodic benefit cost	$	596		$	484		$	537		$	41		$	77		$	288

Changes In Plan Assets And Benefit Obligations Recognized In OCI And Regulatory Assets

The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2015, 2014 and 2013 for all plans combined.



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Changes in plan assets and benefit obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial loss (gain)	$	476		$	1,639		$	(1,169	)	$	(194	)	$	561		$	(628	)
Amortization of actuarial loss	(571		)	(420		)	(562		)	(80		)	(50		)	(83		)
Current year prior service (credit) cost	—			—			—			(23		)	(1,012		)	15
Amortization of prior service (cost) credit	(13		)	(14		)	(14		)	174			122			19
Settlements	(2		)	(2		)	(8		)	—			—			—
Total recognized in AOCI and regulatory assets (liabilities)^(a)	$	(110	)	$	1,203		$	(1,753	)	$	(123	)	$	(379	)	$	(677	)

______________________

(a)

Changes In Plan Assets And Benefit Obligations Not Recognized In OCI And Regulatory Assets



	Pension Benefits				Other Postretirement Benefits
	2015		2014		2015			2014
Prior service cost (credit)	$	36	$	49	$	(812	)	$	(963	)
Actuarial loss	7,310		7,407		711			985
Total ^(a)	$	7,346	$	7,456	$	(101	)	$	22

_______________________

(a)

Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year

The valuation is expected to be completed in the first quarter of 2016 for the majority of the benefit plans.



	Pension Benefits		Other Postretirement Benefits
Prior service cost (credit)	$	13	$	(175	)
Actuarial loss	501		50
Total ^(a)	$	514	$	(125	)

___________________


(a)	Of the $514 million related to pension benefits at December 31, 2015, $290 million and $224 million are expected to be amortized from AOCI and regulatory assets in 2016, respectively. Of the $(125) million related to other postretirement benefits at December 31, 2015, $(64) million and $(61) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2016, respectively.

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate	4.29	%		3.94	%		4.80	%		4.29	%		3.92	%		4.90	%
Rate of compensation increase			^(a)			^(a)			^(b)			^(a)			^(a)			^(b)
Mortality table	RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements
Health care cost trend on covered charges	N/A			N/A			N/A			5.50% decreasing to ultimate trend of 5.00% in 2017			6.00% decreasing to ultimate trend of 5.00% in 2017			6.00% decreasing to ultimate trend of 5.00% in 2017

_____________________________


(a)	3.25% through 2019 and 3.75% thereafter.


(b)	3.25% through 2018 and 3.75% thereafter.

Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost

The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2015, 2014 and 2013:



	Pension Benefits									Other Postretirement Benefits
	2015			2014			2013			2015			2014			2013
Discount rate	3.94	%	^(a)	4.80	%	^(b)	3.92	%	^(c)	3.92	%	^(a)	4.90	%	^(b)	4.00	%	^(c)
Expected return on plan assets	7.00	%	^(d)	7.00	%	^(d)	7.50	%	^(d)	6.50	%	^(d)	6.59	%	^(d)	6.45	%	^(d)
Rate of compensation increase			^(e)			^(f)			^(g)			^(e)			^(f)			^(g)
Mortality table	RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table projected to 2012 with improvement scale AA, with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements
Health care cost trend on covered charges	N/A			N/A			N/A			6.00% decreasing to ultimate trend of 5.00% in 2017			6.00% decreasing to ultimate trend of 5.00% in 2017			6.50% decreasing to ultimate trend of 5.00% in 2017

___________________________


(a)	The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2015. Discount rates for CENG's legacy pension and OPEB plans ranged from 3.68%-4.14% and 4.32%-4.43%, respectively.

(b)

(c)


(d)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.


(e)	3.25% through 2019 and 3.75% thereafter.


(f)	3.25% through 2018 and 3.75% thereafter.


(g)	3.25% through 2017 and 3.75% thereafter.

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

A one percentage point change in assumed health care cost trend rates would have the following effects:



Effect of a one percentage point increase in assumed health care cost trend:
on 2015 total service and interest cost components	$	12
on postretirement benefit obligation at December 31, 2015	100
Effect of a one percentage point decrease in assumed health care cost trend:
on 2015 total service and interest cost components	(9		)
on postretirement benefit obligation at December 31, 2015	(89		)

Pension And Other Postretirement Benefit Contributions

The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans:



	Pension Benefits						Other Postretirement Benefits
	2015^(a)		2014^(a)		2013		2015		2014		2013
Generation	$	231	$	173	$	119	$	14	$	124	$	30
ComEd	143		122		118		7		125		4
PECO	40		11		11		—		5		20
BGE	1		—		—		16		17		24
BSC^(b)	47		26		91		3		20		5
Exelon	$	462	$	332	$	339	$	40	$	291	$	83

_________________________


(a)	Exelon's and Generation's pension contributions include $36 million and $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2015 and 2014, respectively.


(b)	Includes $5 million, $9 million, and $72 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2015, 2014, and 2013, respectively.

Defined Benefit Plan Estimated Future Benefit Payments

Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2015 were:



	Pension Benefits		Other Postretirement Benefits
2016	$	1,153	$	217
2017	997		223
2018	1,009		228
2019	1,036		235
2020	1,071		244
2021 through 2025	5,923		1,341
Total estimated future benefit payments through 2025	$	11,189	$	2,488

Schedule Of Pension And Other Postretirement Benefit Costs

. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:



For the Year Ended December 31,	Generation		ComEd		PECO		BSC^(a)		BGE		Exelon
2015	$	269	$	206	$	39	$	57	$	66	637
2014	250		162		36		46		67		561
2013	347		309		43		71		55		825

_____________________


(a)	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.

Defined Benefit Plan Weighted Average Asset Allocations And Target Allocations

Exelon’s pension and other postretirement benefit plan target asset allocations at December 31, 2015 and 2014 asset allocations were as follows:

Pension Plans



			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2015		2014
Equity securities	32	%	35	%	33	%
Fixed income securities	37	%	34		37
Alternative investments^(a)	31	%	31		30
Total			100	%	100	%

Other Postretirement Benefit Plans



			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2015		2014
Equity securities	39	%	43	%	42	%
Fixed income securities	26	%	27		34
Alternative investments^(a)	35	%	30		24
Total			100	%	100	%

___________________


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

Defined Benefit Plan Fair Value Of Plan Assets



At December 31, 2015^(a)	Level 1		Level 2		Level 3		Total
Pension plan assets
Cash equivalents	$	210	$	—	$	—	$	210
Equities^(b)	3,571		1,462		2		5,035
Fixed income:
U.S. Treasury and agencies	1,001		79		—		1,080
State and municipal debt	—		61		—		61
Corporate debt	—		2,901		165		3,066
Other^(b)	—		395		203		598
Fixed income subtotal	1,001		3,436		368		4,805
Private equity	—		—		924		924
Hedge funds	—		1,129		795		1,924
Real estate	—		—		725		725
Private credit	—		—		699		699
Pension plan assets subtotal	4,782		6,027		3,513		14,322



At December 31, 2015^(a)	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents	15		—		—		15
Equities	510		482		—		992
Fixed income:
U.S. Treasury and agencies	11		53		—		64
State and municipal debt	—		131		—		131
Corporate debt	—		44		—		44
Other	155		205		—		360
Fixed income subtotal	166		433		—		599
Hedge funds	—		312		139		451
Real estate	—		—		131		131
Private credit	—		—		103		103
Other postretirement benefit plan assets subtotal	691		1,227		373		2,291
Total pension and other postretirement benefit plan assets^(c)	$	5,473	$	7,254	$	3,886	$	16,613



At December 31, 2014^(a)	Level 1		Level 2		Level 3		Total
Pension plan assets
Cash equivalents	$	1	$	—	$	—	$	1
Equities^(b)	3,261		1,449		2		4,712
Fixed income:
U.S. Treasury and agencies	1,051		88		—		1,139
State and municipal debt	—		80		—		80
Corporate debt	—		3,125		120		3,245
Other^(b)	—		930		152		1,082
Fixed income subtotal	1,051		4,223		272		5,546
Private equity	—		—		900		900
Hedge funds	—		1,355		785		2,140
Real estate	243		—		685		928
Private credit	—		—		607		607
Pension plan assets subtotal	4,556		7,027		3,251		14,834



At December 31, 2014^(a)	Level 1		Level 2		Level 3		Total
Other postretirement benefit plan assets
Cash equivalents	11		—		—		11
Equities	480		525		—		1,005
Fixed income:
U.S. Treasury and agencies	15		59		—		74
State and municipal debt	—		197		—		197
Corporate debt	—		42		—		42
Other	253		272		—		525
Fixed income subtotal	268		570		—		838
Hedge funds	—		339		—		339
Real estate	8		—		116		124
Private credit	—		—		110		110
Other postretirement benefit plan assets subtotal	767		1,434		226		2,427
Total pension and other postretirement benefit plan assets^(c)	$	5,323	$	8,461	$	3,477	$	17,261

__________________________


(a)	See Note 12—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)


(c)	Excludes net assets of $27 million and $42 million at December 31, 2015 and 2014, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.

Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation



	Hedge funds			Private equity			Real estate			Fixed income			Equities		Private Credit			Total
Pension Assets
Balance as of January 1, 2015	$	785		$	900		$	685		$	272		$	2	$	607		$	3,251
Actual return on plan assets:
Relating to assets still held at the reporting date	(39		)	60			76			(14		)	—		(19		)	64
Relating to assets sold during the period	4			—			9			—			—		—			13
Purchases, sales and settlements:
Purchases	104			186			116			125			—		200			731
Sales	(57		)	—			(54		)	(7		)	—		(5		)	(123		)
Settlements^(a)	(2		)	(222		)	(107		)	(8		)	—		(84		)	(423		)
Balance as of December 31, 2015	$	795		$	924		$	725		$	368		$	2	$	699		$	3,513
Other Postretirement Benefits
Balance as of January 1, 2015	$	—		$	—		$	116		$	—		$	—	$	110		$	226
Actual return on plan assets:
Relating to assets still held at the reporting date	1			—			15			—			—		(7		)	9
Purchases, sales and settlements:
Purchases	138			—			62			—			—		—			200
Settlements^(a)	—			—			(62		)	—			—		—			(62		)
Balance as of December 31, 2015	$	139		$	—		$	131		$	—		$	—	$	103		$	373



	Hedge funds			Private equity			Real estate			Fixed income			Equities		Private credit			Total
Pension Assets
Balance as of January 1, 2014	$	706		$	806		$	544		$	41		$	2	$	371		$	2,470
Actual return on plan assets:
Relating to assets still held at the reporting date	59			112			81			7			—		20			279
Relating to assets sold during the period	2			—			—			—			—		1			3
Purchases, sales and settlements:
Purchases	74			169			112			227			—		265			847
Sales	(25		)	—			(19		)	(3		)	—		(13		)	(60		)
Settlements^(a)	(1		)	(203		)	(60		)	—			—		(37		)	(301		)
Transfers into (out of) Level 3^(b)(c)	(30		)	16			27			—			—		—			13
Balance as of December 31, 2014	$	785		$	900		$	685		$	272		$	2	$	607		$	3,251
Other Postretirement Benefits
Balance as of January 1, 2014	$	—		$	2		$	109		$	—		$	—	$	4		$	115
Actual return on plan assets:
Relating to assets still held at the reporting date	—			—			13			—			—		1			14
Purchases, sales and settlements:
Purchases	—			1			1			—			—		109			111
Sales	—			(2		)	(7		)	—			—		(4		)	(13		)
Settlements^(a)	—			(1		)	—			—			—		—			(1		)
Balance as of December 31, 2014	$	—		$	—		$	116		$	—		$	—	$	110		$	226

________________________


(a)	Represents cash settlements only.


(b)	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.

(c)

Schedule Of Defined Contributions

. The following table presents matching contributions to the savings plan for the years ended December 31, 2015, 2014 and 2013:



For the Year Ended December 31,	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		BSC^(b)
2015	$	148	$	80	$	32	$	11	$	14	$	11
2014	103		51		26		8		8		10
2013	85		40		22		8		8		7

_________________________


(a)	Includes $9 million and $5 million related to CENG for the year ended December 31, 2015, and for the period from April 1, 2014 to December 31, 2014, respectively.


(b)	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 (Tables)

12 Months Ended

Dec. 31, 2015

Restructuring and Related Activities [Abstract]

Business Acquisition, Integration, Restructuring and Other Related Costs [Text Block]

Schedule of Restructuring and Related Costs



	For the year ended,
Acquisition, Integration and Financing Costs ^(a)	2015		2014
Exelon	$	80	$	179
Generation	25		11
ComEd	10		4
PECO	5		2
BGE	5		2

___________

Schedule of Corporate Restructuring Severance Obligations

Schedule Of Severance Costs

Severance Benefits ^(a)

Severance Charges-2015

Severance Charges-2014

Severance Charges-2013

________________________


(a)	The amounts above for Generation include $1 million, $1 million, and $2 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2015, December 31, 2014, and December 31, 2013, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material.

Contingently Redeemable Noncontrolling Interest Contingently Redeemable Noncontrolling Interest (Table)

12 Months Ended

Dec. 31, 2015

Noncontrolling Interest Disclosure [Abstract]

Redeemable Noncontrolling Interest [Table Text Block]

The following table summarizes the changes in the contingently redeemable noncontrolling interest for the year ended December 31, 2015:



	Year Ended December 31, 2015
Beginning Balance	$	—
Cash received from noncontrolling interest	32
Release of contingency	(4		)
Ending Balance	$	28

18. Contingently Redeemable Noncontrolling Interest (Exelon, Generation)

In November 2015, 2015 ESA Investco, LLC, a wholly owned subsidiary of Generation, entered into an arrangement to sell a portion of its equity to a tax equity investor. Pursuant to the operating agreement, in certain situations the equity contributions made by the noncontrolling interest holder could be contingently redeemable. These situations are outside of the control of Generation and the noncontrolling interest holder resulting in a portion of the noncontrolling interest being considered contingently redeemable and thus presented in mezzanine equity in the consolidated balance sheet.

The following table summarizes the changes in the contingently redeemable noncontrolling interest for the year ended December 31, 2015:



	Year Ended December 31, 2015
Beginning Balance	$	—
Cash received from noncontrolling interest	32
Release of contingency	(4		)
Ending Balance	$	28

Shareholder Equity Shareholder Equity (Tables)

12 Months Ended

Dec. 31, 2015

Shareholder [Abstract]

Schedule of Common Stock Outstanding Roll Forward [Table Text Block]

The following table presents common stock authorized and outstanding as of December 31, 2015 and 2014:



				December 31,
				2015	2014
	Par Value		Shares Authorized	Shares Outstanding
Common Stock
Exelon	no par value		2,000,000,000	919,924,742	859,833,343
ComEd	$	12.50	250,000,000	127,016,973	127,016,947
PECO	no par value		500,000,000	170,478,507	170,478,507
BGE	no par value		175,000,000	1,000	1,000

Schedule of Auction Market Preferred Securities by Stock Series [Table Text Block]



			December 31,
	Redemption Price ^(a)		2015	2014	2015		2014
	Redemption Price ^(a)		Shares Outstanding		Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.00	400,000	400,000	$	40	$	40
6.97%, 1993 Series	100.00		500,000	500,000	50		50
6.70%, 1993 Series	100.00		400,000	400,000	40		40
6.99%, 1995 Series	100.00		600,000	600,000	60		60
Total preference stock			1,900,000	1,900,000	$	190	$	190

______________________


(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

Schedule of Stock by Class

Tabular disclosure of information pertaining to auction market preferred securities, including liquidation preference, liquidation value, par value, rate setting interval, redemption requirements, dividend distributions, roll forward of shares outstanding, shares authorized, aggregate value of auction market preferred securities, variable interest rate earned, and other information necessary to a fair presentation. If redeemable, the auction market preferred securities are redeemable solely at the option of the issuer.

Tabular disclosure of an entity's stock, including par or stated value per share, number and dollar amount of share subscriptions, shares authorized, shares issued, shares outstanding, number and dollar amount of shares held in an employee trust, dividend per share, total dividends, share conversion features, par value plus additional paid in capital, the value of treasury stock and other information necessary to a fair presentation, and EPS information. Stock by class includes common, convertible, and preferred stocks which are not redeemable or redeemable solely at the option of the issuer. Includes preferred stock with redemption features that are solely within the control of the issuer and mandatorily redeemable stock if redemption is required to occur only upon liquidation or termination of the reporting entity. If more than one issue is outstanding, state the title of each issue and the corresponding dollar amount; dollar amount of any shares subscribed but unissued and the deduction of subscriptions receivable there from; number of shares authorized, issued, and outstanding.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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Reference 12: http://www.xbrl.org/2003/role/presentationRef
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Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 30
-Article 5

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

12 Months Ended

Dec. 31, 2015

Schedule of Stock by Class

Stock Based Compensation Tax Benefit

The following table presents information regarding Exelon’s tax benefits for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Realized tax benefit when exercised/distributed:
Restricted stock units	$	30	$	17	$	11
Performance share awards	18		11		11
Stock deferral plan	—		—		1

Schedule of Assumptions Used

The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the year ended 2012:



	Year ended December 31, 2012
Dividend yield	5.28	%
Expected volatility	23.20	%
Risk-free interest rate	1.30	%
Expected life (years)	6.25
Weighted average grant date fair value (per share)	4.18

Schedule of Share-based Compensation, Stock Options, Activity

The following table presents information with respect to stock option activity for the year ended December 31, 2015:



	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2014	18,830,967		$	46.85
Options exercised	(7,133	)	21.25
Options forfeited	(5,250	)	39.81
Options expired	(3,245,827	)	47.75
Balance of shares outstanding at December 31, 2015	15,572,757		$	46.68	3.85	$	9
Exercisable at December 31, 2015 (a)	15,490,507		$	46.72	3.84	$	9

____________________


(a)	Includes stock options issued to retirement eligible employees.

Stock Options Exercised

The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Intrinsic value^(a)	$	—	$	3	$	4
Cash received for exercise price	—		7		19

______________________


(a)	The difference between the market value on the date of exercise and the option exercise price.

Schedule of Nonvested Share Activity

The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2015:



	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2014 (a)	432,035		$	39.91
Vested	(344,535	)	39.93
Forfeited	(5,250	)	39.81
Nonvested at December 31, 2015 (a)	82,250		$	39.81

_____________________


(a)	Excludes 279,000 and 746,140 of stock options issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.

Schedule of Nonvested Restricted Stock Units Activity

The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2015:



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2014 (a)	3,758,218		$	31.27
Granted	2,132,856		36.55
Vested	(1,597,255	)	32.88
Forfeited	(76,232	)	33.06
Undistributed vested awards^(b)	(654,333	)	35.35
Nonvested at December 31, 2015 (a)	3,563,254		$	32.92

_______________________


(a)	Excludes 1,097,630 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.


(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2015.

Schedule of Nonvested Performance-based Units Activity

The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2015:



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2014 (a)	2,696,097		$	30.62
Granted	1,556,273		35.88
Change in performance	(118,398	)	35.88
Vested	(704,141	)	32.80
Forfeited	(52,167	)	32.25
Undistributed vested awards ^(b)	(820,505	)	33.95
Nonvested at December 31, 2015 (a)	2,557,159		$	31.88

_______________________


(a)	Excludes 1,817,883 and 1,535,791 of performance share awards issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.


(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2015.

Not Settled Performance Share Awards Balance Sheet Presentation

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:



	December 31,
	2015		2014
Current liabilities^(a)	$	28	$	28
Deferred credits and other liabilities ^(b)	32		36
Common stock	35		33
Total	$	95	$	97

__________________________


(a)	Represents the current liability related to performance share awards expected to be settled in cash.


(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]



	Year Ended December 31,
Components of Stock-Based Compensation Expense	2015			2014			2013
Performance share awards	$	41		$	59		$	48
Restricted stock units	71			61			61
Stock options	1			2			3
Other stock-based awards	6			5			6
Total stock-based compensation expense included in operating and maintenance expense	119			127			118
Income tax benefit	(46		)	(47		)	(44		)
Total after-tax stock-based compensation expense	$	73		$	80		$	74

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]

The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
Subsidiaries	2015		2014		2013
Generation	$	64	$	52	$	48
ComEd	6		7		9
PECO	3		3		5
BGE	3		5		6
BSC ^(a)	43		60		50
Total	$	119	$	127	$	118

________________________


(a)	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 (Tables)

12 Months Ended

Dec. 31, 2015

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share

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



	Year Ended December 31,
	2015		2014		2013
Net income attributable to common shareholders	$	2,269	$	1,623	$	1,719
Weighted average common shares outstanding—basic	890		860		856
Assumed exercise and/or distributions of stock-based awards	3		4		4
Weighted average common shares outstanding—diluted	893		864		860

Changes in Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2015

Equity [Abstract]

Schedule Of Accumulated Other Comprehensive Income (Loss)

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2015 and 2014:



For the Year Ended December 31, 2015	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	$	(28	)	$	3	$	(2,640	)	$	(19	)	$	—		$	(2,684	)
OCI before reclassifications	(12		)	—		(100		)	(21		)	(3		)	(136		)
Amounts reclassified from AOCI ^(b)	21			—		175			—			—			196
Net current-period OCI	9			—		75			(21		)	(3		)	60
Ending balance	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)
Generation ^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—		$	(36	)
OCI before reclassifications	(8		)	—		—			(21		)	(3		)	(32		)
Amounts reclassified from AOCI ^(b)	5			—		—			—			—			5
Net current-period OCI	(3		)	—		—			(21		)	(3		)	(27		)
Ending balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
PECO ^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI ^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1



For the Year Ended December 31, 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	(31		)	(1		)	(498		)	(9		)	11			(528		)
Amounts reclassified from AOCI ^(b)	(117		)	2			118			—			(119		)	(116		)
Net current-period OCI	(148		)	1			(380		)	(9		)	(108		)	(644		)
Ending balance	$	(28	)	$	3		$	(2,640	)	$	(19	)	$	—		$	(2,684	)
Generation ^(a)
Beginning balance	$	114		$	2		$	—		$	(10	)	$	108		214
OCI before reclassifications	(15		)	(1		)	—			(9		)	11			(14		)
Amounts reclassified from AOCI ^(b)	(117		)	—			—			—			(119		)	(236		)
Net current-period OCI	(132		)	(1		)	—			(9		)	(108		)	(250		)
Ending balance	$	(18	)	$	1		$	—		$	(19	)	$	—		$	(36	)
PECO ^(a)
Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1
OCI before reclassifications	—			—			—			—			—			—
Amounts reclassified from AOCI ^(b)	—			—			—			—			—			—
Net current-period OCI	—			—			—			—			—			—
Ending balance	$	—		$	1		$	—		$	—		$	—		$	1

_______________________


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


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

Reclassification Out Of Accumulated Other Comprehensive Income

The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2015 and 2014:

For the Year Ended December 31, 2015



Details about AOCI components	Items reclassified out of AOCI ^(a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Terminated interest rate swaps	$	(26	)	$	—		Other, net
Energy related hedges	2			2			Operating revenues
Other cash flow hedges	(11		)	(11		)	Interest expense
Total before tax	(35		)	(9		)
Tax benefit	14			4
Net of tax	$	(21	)	$	(5	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	74		$	—
Actuarial losses^(b)	(361		)	—
Total before tax	(287		)	—
Tax benefit	112			—
Net of tax	$	(175	)	$	—

Total Reclassifications	$	(196	)	$	(5	)	Comprehensive income

For the Year Ended December 31, 2014



Details about AOCI components	Items reclassified out of AOCI ^(a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Energy related hedges	$	195		$	195		Operating revenues
Total before tax	195			195
Tax expense	(78		)	(78		)
Net of tax	$	117		$	117		Comprehensive income

Gains and (losses) on available for sale securities
Other available securities for sale	$	(2	)	$	—		Other Income and Deductions
Total before tax	(2		)	—
Net of tax	$	(2	)	$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	46		$	—
Actuarial losses^(b)	(239		)	—
Total before tax	(193		)	—
Tax benefit	75			—
Net of tax	$	(118	)	$	—		Comprehensive income

Equity investments
Sale of equity method investment	$	5		$	5		Equity in losses of unconsolidated affiliates
Reversal of CENG equity method AOCI	193			193			Gain on Consolidation of CENG
Total before tax	198			198
Tax expense	(79		)	(79		)
Net of tax	$	119		$	119

Total Reclassifications	$	116		$	236		Comprehensive income

_____________________


(a)	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 17 — Retirement Benefits for additional details).


(c)	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.

Schedule of Components of Income Tax Expense (Benefit)

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2015 and 2014:



	For the Years Ended December 31,
	2015			2014			2013
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	30		$	19		$	—
Actuarial loss reclassified to periodic cost	(140		)	(93		)	(133		)
Pension and non-pension postretirement benefit plan valuation adjustment	62			317			(430		)
Change in unrealized (gain) loss on cash flow hedges	(6		)	96			166
Change in unrealized (gain) loss on equity investments	1			73			(71		)
Total	$	(53	)	$	412		$	(468	)

Generation
Change in unrealized loss on cash flow hedges	$	2		$	84		$	262
Change in unrealized (gain) loss on equity investments	1			73			(72		)
Total	$	3		$	157		$	190

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2015

Environmental Loss Contingency Tables [Abstract]

Schedule of Government Settlement Agreements

Energy Commitments

Utility Energy Purchase Commitments

Other Purchase Obligation

Fuel Purchase Commitments

Commercial Commitments

PECO’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	22	$	22	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	9		9		—		—		—		—		—
Financing trust guarantees ^(c)	178		—		—		—		—		—		178
Total commercial commitments	$	209	$	31	$	—	$	—	$	—	$	—	$	178

________________________


(a)	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

ComEd’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	16	$	16	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	8		6		—		2		—		—		—
Financing trust guarantees ^(c)	200		—		—		—		—		—		200
Total commercial commitments	$	224	$	22	$	—	$	2	$	—	$	—	$	200

_________________________


(a)	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.

Exelon’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	1,583	$	1,565	$	5	$	—	$	—	$	13	$	—
Surety bonds^(b)	809		733		49		3		2		16		6
Financing trust guarantees ^(c)	628		—		—		—		—		—		628
Energy marketing contract guarantees ^(d)	3,126		3,126		—		—		—		—		—
Nuclear insurance premiums ^(e)	3,060		—		—		—		—		—		3,060
Total commercial commitments	$	9,206	$	5,424	$	54	$	3	$	2	$	29	$	3,694

___________________________


(a)	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.

(d)

(e)

BGE’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	10		10		—		—		—		—		—
Financing trust guarantees ^(c)	250		—		—		—		—		—		250
Total commercial commitments	$	262	$	12	$	—	$	—	$	—	$	—	$	250

________________________


(a)	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.


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


(c)	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.

Generation’s commercial commitments as of December 31, 2015, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2016		2017		2018		2019		2020		2021 and beyond
Letters of credit (non-debt) ^(a)	$	1,503	$	1,485	$	5	$	—	$	—	$	13	$	—
Surety bonds	737		692		45		—		—		—		—
Energy marketing contract guarantees ^(b)	1,532		1,532		—		—		—		—		—
Nuclear insurance premiums ^(c)	3,060		—		—		—		—		—		3,060
Total commercial commitments	$	6,832	$	3,709	$	50	$	—	$	—	$	13	$	3,060

________________________


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

(b)

(c)

Nuclear insurance premiums — 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.

Other Commitments

Operating Leases Of Lessee Disclosure



	Exelon ^(a)		Generation^(a)(b)		ComEd ^(c)		PECO ^(c)		BGE ^(c)(d)
2016	$	133	$	86	$	14	$	3	$	12
2017	109		69		9		3		10
2018	86		57		5		2		9
2019	74		45		5		2		8
2020	70		44		3		2		7
Remaining years	702		655		1		—		19
Total minimum future lease payments	$	1,174	$	956	$	37	$	12	$	65

______________________


(a)	Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.

(b)

(c)


(d)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.

Operating Leases Rent Expense

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2015, 2014 and 2013:



For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE
2015	$	922	$	851	$	12	$	9	$	32
2014	865		806		15		14		12
2013	806		744		15		21		11

__________________________


(a)	Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments table above. Payments made under Generation’s contracted generation lease agreements totaled $798 million, $755 million and $694 million during 2015, 2014 and 2013, respectively.

Accrued environmental liabilities



December 31, 2015	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation ^(a)
Exelon	$	369	$	301
Generation	63		—
ComEd	266		264
PECO	37		35
BGE ^(a)	3		2



December 31, 2014	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	347	$	277
Generation	63		—
ComEd	238		235
PECO	45		42
BGE	1		—

Supplemental Financial Information (Tables)

12 Months Ended

Dec. 31, 2015

Supplemental Financial Information [Abstract]

Components of taxes other than income

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2015, 2014 and 2013.



For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	474	$	105	$	236	$	133	$	85
Property	407		250		27		11		119
Payroll	201		118		28		14		16
Other	118		16		5		2		4
Total taxes other than income	$	1,200	$	489	296		$	160	$	224



For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	456	$	89	$	238	$	128	$	86
Property	396		240		25		15		114
Payroll	200		118		28		14		18
Other	102		18		2		2		3
Total taxes other than income	$	1,154	$	465	$	293	$	159	$	221



For the year ended December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Taxes other than income
Utility ^(a)	$	449	$	79	$	241	$	129	$	82
Property	302		205		24		14		112
Payroll	159		89		27		13		15
Other	185		16		7		2		4
Total taxes other than income	$	1,095	$	389	$	299	$	158	$	213

_____________________

(a)

Components of non-operating income and expenses



For the year ended December 31, 2015	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	232		$	232		$	—	$	—		$	—
Non-regulatory agreement units	156			156			—		—			—
Net unrealized losses on decommissioning trust funds—
Regulatory agreement units	(282		)	(282		)	—		—			—
Non-regulatory agreement units	(197		)	(197		)	—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	7			7			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)	21			21			—		—			—
Total decommissioning-related activities	(63		)	(63		)	—		—			—
Investment income (loss)	8			3			—		(2		)	4		^(c)
Long-term lease income	15			—			—		—			—
Interest income related to uncertain income tax positions	1			1			—		—			—
AFUDC—Equity	24			—			5		5			14
Terminated interest rate swaps ^(d)	(26		)	—			—		—			—
PHI merger related debt exchange ^(e)	(22		)	—			—		—			—
Other	17			(1		)	16		2			—
Other, net	$	(46	)	$	(60	)	$	21	$	5		$	18



For the year ended December 31, 2014	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	216		$	216		$	—	$	—		$	—
Non-regulatory agreement units	159			159			—		—			—
Net unrealized gains on decommissioning trust funds—
Regulatory agreement units	180			180			—		—			—
Non-regulatory agreement units	134			134			—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	29			29			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)	(358		)	(358		)	—
Total decommissioning-related activities	360			360			—		—			—
Investment income	1			1			—		(1		)	7			^(c)
Long-term lease income	24			—			—		—			—
Interest income related to uncertain income tax positions	40			54			—		—			—
AFUDC—Equity	21			—			3		6			12
Other	9			(9		)	14		2			(1		)
Other, net	$	455		$	406		$	17	$	7		$	18



For the year ended December 31, 2013	Exelon			Generation			ComEd		PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds ^(a)—
Regulatory agreement units	$	256		$	256		$	—	$	—		$	—
Non-regulatory agreement units	77			77			—		—			—
Net unrealized gains on decommissioning trust funds—
Regulatory agreement units	406			406			—		—			—
Non-regulatory agreement units	146			146			—		—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	7			7			—		—			—
Regulatory offset to decommissioning trust fund-related activities ^(b)	(546		)	(546		)	—					—
Total decommissioning-related activities	346			346			—		—			—
Investment income	8			(1		)	—		(1		)	9		^(c)
Long-term lease income	28			—			—		—			—
Interest income related to uncertain income tax positions	24			4			—		—			—
AFUDC—Equity	22			—			11		4			7
Other	32			6			15		3			1
Other, net	$	460		$	355		$	26	$	6		$	17

_________________________


(a)	Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning 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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.

(d)


(e)	See Note 14—Debt and Credit Agreements and 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.

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

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2015, 2014 and 2013.



For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	2,227	$	1,007	$	635	$	240	$	289
Regulatory assets	170		—		72		20		77
Amortization of intangible assets, net	54		47		—		—		—
Amortization of energy contract assets and liabilities^(a)	22		22		—		—		—
Nuclear fuel^(b)	1,116		1,116		—		—		—
ARO accretion^(c)	398		397		—		—		—
Total depreciation, amortization, accretion and depletion	$	3,987	$	2,589	$	707	$	260	$	366



For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	2,080	$	922	$	588	$	227	$	288
Regulatory assets	191		—		99		9		83
Amortization of intangible assets, net	44		44		—		—		—
Amortization of energy contract assets and liabilities^(a)	135		135		—		—		—
Nuclear fuel^(b)	1,073		1,073		—		—		—
ARO accretion^(c)	345		345		—		—		—
Total depreciation, amortization, accretion and depletion	$	3,868	$	2,519	$	687	$	236	$	371



For the year ended December 31, 2013	Exelon		Generation		ComEd		PECO		BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,893	$	813	$	545	$	219	$	264
Regulatory assets	212		—		119		9		84
Amortization of intangible assets, net	48		43		5		—		—
Amortization of energy contract assets and liabilities^(a)	430		507		—		—		—
Nuclear fuel^(b)	921		921		—		—		—
ARO accretion^(c)	275		275		—		—		—
Total depreciation, amortization and accretion	$	3,779	$	2,559	$	669	$	228	$	348

________________________


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


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


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

Schedule of Cash Flow, Supplemental Disclosure



For the year ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	930		$	348		$	308		$	94		$	120
Income taxes (net of refunds)	342			476			(265		)	64			73
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	637		$	269		$	206		$	39		$	65
Loss from equity method investments	7			8			—			—			—
Provision for uncollectible accounts	120			22			53			30			15
Provision for excess and obsolete inventory	10			9			1			—			—
Stock-based compensation costs	97			—			—			—			—
Other decommissioning-related activity^(a)	(82		)	(82		)	—			—			—
Energy-related options^(b)	21			21			—			—			—
Amortization of regulatory asset related to debt costs	7			—			5			2			—
Amortization of rate stabilization deferral	73			—			—			—			73
Amortization of debt fair value adjustment	(17		)	(17		)	—			—			—
Amortization of debt costs	58			15			4			2			2
Discrete impacts from EIMA^(c)	144			—			144			—			—
Lower of cost or market inventory adjustment	23			23			—			—			—
Other	11			—			3			(3		)	(18		)
Total other non-cash operating activities	$	1,109		$	268		$	416		$	70		$	137
Non-cash investing and financing activities:
Change in PPE related to ARO update	$	885		$	885		$	—		$	—		$	—
Change in capital expenditures not paid	96			82			34			(13		)	(9		)
Non-cash financing of capital projects	77			77			—			—			—
Nuclear fuel procurement ^(d)	57			57			—			—			—
Indemnification of like-kind exchange position ^(e)	—			—			7			—			—
Long-term software licensing agreement ^(f)	95			—			—			—			—

____________________________


(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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


(c)	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 3 — Regulatory Matters for more information.


(d)	Relates to the nuclear fuel procurement contract for the purchase of fixed quantities of converted uranium, which was delivered to Generation in 2015. Generation is required to make payments starting September 28, 2018, with the final payment being due no later than September 30, 2020.


(e)	See Note 15 — Income Taxes for discussion of the like-kind exchange tax position.


(f)	Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note 14 — Debt and Credit Agreements for additional information.



For the year ended December 31, 2014	Exelon			Generation				ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	940		$	322			$	292		$	94		$	111
Income taxes (net of refunds)	314			227				(6		)	85			(21		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	560		$	249			$	162		$	36		$	64
Loss from equity method investments	22			20				—			—			—
Provision for uncollectible accounts	156			14				26			52			64
Provision for excess and obsolete inventory	5			5				—			—			—
Stock-based compensation costs	91			—				—			—			—
Other decommissioning-related activity ^(a)	(132		)	(132		)		—			—			—
Energy-related options ^(b)	122			122				—			—			—
Amortization of regulatory asset related to debt costs	11			—				8			3			—
Amortization of rate stabilization deferral	65			—				—			—			65
Amortization of debt fair value adjustment	(23		)	(23		)		—			—			—
Merger-related commitments	44			44				—			—			—
Amortization of debt costs	53			12				4			2			2
Discrete impacts from EIMA ^(c)	53			—				53			—			—
Lower of cost or market inventory adjustment	29			29				—			—			—
Other	(2		)	6				2			(1		)	(15		)
Total other non-cash operating activities	$	1,054		$	346			$	255		$	92		$	180
Non-cash investing and financing activities:
Change in PPE related to ARO update	$	72		$	72			$	—		$	—		$	—
Change in capital expenditures not paid	220			(61		)	^(d)	78			—			25
Fair value of net assets recorded upon CENG consolidation ^(e)	3,400			3,400				—			—			—
Issuance of equity units ^(f)	131			—				—			—			—
Nuclear fuel procurement ^(g)	70			70				—			—			—
Indemnification of like-kind exchange position ^(h)	—			—				5			—			—

______________________


(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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


(c)	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 3 — Regulatory Matters for more information.


(d)	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.


(e)	See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.


(f)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 20 — Stock-Based Compensation Plans for additional information.


(g)	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation in 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.


(h)	See Note 15 — Income Taxes for discussion of the like-kind exchange tax position.



For the year ended December 31, 2013	Exelon			Generation				ComEd			PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	866		$	291			$	283		$	95		$	130
Income taxes (net of refunds)	112			(18		)		33			70			42
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	825		$	345			$	308		$	43		$	56
Gain from equity method investments	(10		)	(10		)		—			—			—
Provision for uncollectible accounts	101			10				(15		)	61			44
Provision for excess and obsolete inventory	9			9				—			—			—
Stock-based compensation costs	120			—				—			—			—
Other decommissioning-related activity ^(a)	(169		)	(169		)		—			—			—
Energy-related options ^(b)	104			104				—			—			—
Amortization of regulatory asset related to debt costs	12			—				9			3			—
Amortization of rate stabilization deferral	66			—				—			—			66
Amortization of debt fair value adjustment	(34		)	(34		)		—			—			—
Discrete impacts from EIMA ^(c)	(271		)	—				(271		)	—			—
Amortization of debt costs	18			10				1			2			2
Other	(53		)	5				(4		)	(1		)	(15		)
Total other non-cash operating activities	$	718		$	270			$	28		$	108		$	153
Non-cash investing and financing activities:
Change in PPE related to ARO update	$	(128	)	$	(128	)		$	—		$	—		$	4
Change in capital expenditures not paid	(38		)	(107		)	^(d)	(8		)	13			(48		)
Consolidated VIE dividend to noncontrolling interest	63			63				—			—			—
Indemnification of like-kind exchange position ^(e)	—			—				176			—			—

_________________________


(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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters.


(d)	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.


(e)	See Note 15 — Income Taxes for discussion of the like-kind exchanged tax position.

Accrued Liabilities Current

The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2015 and 2014.



December 31, 2015	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8
Bloom	63		63		—		—		—
Net Power	23		23		—		—		—
Other equity method investments	4		3		—		—		—
Total equity method investments	112		89		6		8		8
Other investments:
Net investment in leases ^(b)	358		6		—		—		—
Employee benefit trusts and investments^(c)	85		31		—		20		4
Other cost method investments	55		55		—		—		—
Other available for sale investments	29		29		—		—		—
Total investments	$	639	$	210	$	6	$	28	$	12



December 31, 2014	Exelon		Generation		ComEd		PECO		BGE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8
Bloom	13		13		—		—		—
Net Power	9		9		—		—		—
Sunnyside	5		5		—		—		—
Other equity method investments	1		1		—		—		—
Total equity method investments	50		28		6		8		8
Other investments:
Net investment in leases ^(b)	367		7		—		—		—
Employee benefit trusts and investments^(c)	85		27		—		23		4
Other cost method investments	37		37		—		—		—
Other available for sale investments	5		5		—		—		—
Total investments	$	544	$	104	$	6	$	31	$	12

_________________________


(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.


(b)	Represents direct financing lease investments. See Note 8 —Impairment of Long-Lived Assets for additional information.


(c)	The Registrants’ investments in these marketable securities are recorded at fair market value.

The following tables provide additional information about liabilities of the Registrants at December 31, 2015 and 2014.



December 31, 2015	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)	$	1,014		$	547		$	183	$	66	$	57
Taxes accrued	293			186			63		4		23
Interest accrued	915			77			443		35		27
Severance accrued	21			11			3		—		1
Other accrued expenses	133			114			14		4		2
Total accrued expenses	$	2,376		$	935		$	706	$	109	$	110

December 31, 2014	Exelon			Generation			ComEd		PECO		BGE
Accrued expenses
Compensation-related accruals^(a)	$	832		$	447		$	153	$	50	$	58
Taxes accrued	305			248			59		3		42
Interest accrued	240			66			102		33		29
Severance accrued	49			33			2		1		2
Other accrued expenses	113		^(b)	92		^(b)	15		4		—
Total accrued expenses	$	1,539		$	886		$	331	$	91	$	131

_______________________


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.


(b)	Includes $19 million for amounts accrued related to Antelope Valley as of December 31, 2014.

Segment Information (Tables)

12 Months Ended

Dec. 31, 2015

Segment Reporting [Abstract]

Analysis and reconciliation of reportable segment information



	Generation ^(a)		ComEd		PECO		BGE		Other ^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2015
Competitive businesses electric revenues	$	15,944	$	—	$	—	$	—	$	—	$	(744	)	$	15,200
Competitive businesses natural gas revenues	2,433		—		—		—		—		—			2,433
Competitive businesses other revenues	758		—		—		—		—		(1		)	757
Rate-regulated electric revenues	—		4,905		2,486		2,490		—		(5		)	9,876
Rate-regulated natural gas revenues	—		—		546		645		—		(15		)	1,176
Shared service and other revenues	—		—		—		—		1,372		(1,367		)	5
2014
Competitive businesses electric revenues	$	14,533	$	—	$	—	$	—	$	—	$	(760	)	$	13,773



	Generation ^(a)			ComEd		PECO		BGE		Other ^(b)			Intersegment Eliminations			Exelon
Competitive businesses natural gas revenues	2,705			—		—		—		—			(1		)	2,704
Competitive businesses other revenues	155			—		—		—		—			(1		)	154
Rate-regulated electric revenues	—			4,564		2,448		2,460		—			(5		)	9,467
Rate-regulated natural gas revenues	—			—		646		705		—			(26		)	1,325
Shared service and other revenues	—			—		—		—		1,285			(1,279		)	6
2013
Competitive businesses electric revenues	$	13,862		$	—	$	—	$	—	$	—		$	(1,366	)	$	12,496
Competitive businesses natural gas revenues	1,721			—		—		—		—			—			1,721
Competitive businesses other revenues	47			—		—		—		—			(1		)	46
Rate-regulated electric revenues	—			4,464		2,500		2,405		—			(4		)	9,365
Rate-regulated natural gas revenues	—			—		600		660		—			(14		)	1,246
Shared service and other revenues	—			—		—		—		1,241			(1,227		)	14
Intersegment revenues^(d):
2015	$	745		$	4	$	2	$	14	$	1,367		$	(2,127	)	$	5
2014	762			4		2		25		1,280			(2,067		)	6
2013	1,367			3		1		13		1,237			(2,607		)	14
Depreciation and amortization
2015	$	1,054		$	707	$	260	$	366	$	63		$	—		$	2,450
2014	967			687		236		371		53			—			2,314
2013	856			669		228		348		52			—			2,153
Operating expenses ^(c):
2015	$	16,872		$	3,889	$	2,404	$	2,578	$	1,444		$	(2,131	)	$	25,056
2014	16,923			3,586		2,522		2,726		1,353			(2,071		)	25,039
2013	13,976			3,510		2,434		2,616		1,324			(2,618		)	21,242
Equity in earnings (losses) of unconsolidated affiliates
2015	$	(8	)	$	—	$	—	$	—	$	1		$	—		$	(7	)
2014	(20		)	—		—		—		—			—			(20		)
2013	10			—		—		—		—			—			10
Interest expense, net:
2015	$	365		$	332	$	114	$	99	$	123		$	—		$	1,033
2014	356			321		113		106		169			—			1,065
2013	357			579		115		122		183			—			1,356
Income (loss) before income taxes:
2015	$	1,850		$	706	$	521	$	477	$	(219	)	$	(5	)	$	3,330
2014	1,226			676		466		351		(227		)	(6		)	2,486
2013	1,675			401		557		344		(191		)	(13		)	2,773
Income taxes:
2015	$	502		$	280	$	143	$	189	$	(41	)	$	—		$	1,073



	Generation ^(a)		ComEd		PECO		BGE		Other ^(b)			Intersegment Eliminations			Exelon
2014	207		268		114		140		(63		)	—			666
2013	615		152		162		134		(20		)	1			1,044
Net income (loss):
2015	$	1,340	$	426	$	378	$	288	$	(177	)	$	(5	)	$	2,250
2014	1,019		408		352		211		(164		)	(6		)	1,820
2013	1,060		249		395		210		(171		)	(14		)	1,729
Capital expenditures:
2015	$	3,841	$	2,398	$	601	$	719	$	65		$	—		7,624
2014	3,012		1,689		661		620		95			—			6,077
2013	2,752		1,433		537		587		86			—			5,395
Total assets:
2015	$	46,529	$	26,532	$	10,367	$	8,295	$	15,389		$	(11,728	)	$	95,384
2014	44,951		25,358		9,860		8,056		9,711			(11,520		)	86,416

__________________________

(a)


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

(c)

(d)

Analysis and reconciliation of reportable segment revenues for Generation



	2015							2014							2013
	Revenues from external customers^(b)		Intersegment revenues			Total revenues		Revenues from external customers^(b)(d)		Intersegment revenues^(d)			Total revenues		Revenues from external customers^(b)(d)		Intersegment revenues^(d)			Total revenues
Mid-Atlantic^(a)	$	5,974	$	(74	)	$	5,900	$	5,414	$	(155	)	$	5,259	$	5,261	$	(57	)	$	5,204
Midwest	4,712		(2		)	4,710		4,488		(13		)	4,475		4,298		(28		)	4,270
New England	2,217		(5		)	2,212		1,468		(46		)	1,422		1,279		(42		)	1,237
New York	996		(11		)	985		846		(3		)	843		717		(3		)	714
ERCOT	863		(6		)	857		938		(3		)	935		1,223		(7		)	1,216
Other Power Regions	1,182		(80		)	1,102		1,379		(70		)	1,309		1,084		(116		)	968
Total Revenues for Reportable Segments	$	15,944	$	(178	)	$	15,766	$	14,533	$	(290	)	$	14,243	$	13,862	$	(253	)	$	13,609
Other ^(c)	3,191		178			3,369		2,860		290			3,150		1,768		253			2,021
Total Generation Consolidated Operating Revenues	$	19,135	$	—		$	19,135	$	17,393	$	—		$	17,393	$	15,630	$	—		$	15,630

_______________________


(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, beginning on April 1, 2014, CENG's revenues are included on a fully consolidated basis.


(b)	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

(c)

(d)

Reconciliation of revenues from segments to consolidated

Generation total revenues net of purchased power and fuel expense:



	2015							2014									2013
	RNF from external customers^(b)		Intersegment RNF			Total RNF		RNF from external customers^(b)(d)			Intersegment RNF^d)			Total RNF			RNF from external customers^(b)(d)			Intersegment RNF^(d)			Total RNF
Mid-Atlantic^(a)	$	3,556	$	15		$	3,571	$	3,544		$	(113	)	$	3,431		$	3,287		$	(17	)	$	3,270
Midwest	2,912		(20		)	2,892		2,607			(8		)	2,599			2,606			(20		)	2,586
New England	519		(58		)	461		450			(99		)	351			299			(114		)	185
New York	584		50			634		439			44			483			(55		)	51			(4		)
ERCOT	425		(132		)	293		573			(256		)	317			627			(191		)	436
Other Power Regions	440		(190		)	250		517			(190		)	327			397			(196		)	201
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	8,436	$	(335	)	$	8,101	$	8,130		$	(622	)	$	7,508		$	7,161		$	(487	)	$	6,674
Other ^(c)	678		335			1,013		(662		)	622			(40		)	272			487			759
Total Generation Revenues net of purchased power and fuel expense	$	9,114	$	—		$	9,114	$	7,468		$	—		$	7,468		$	7,433		$	—		$	7,433

____________________________


(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, beginning on April 1, 2014, CENG's revenue net of purchased power and fuel expense are included on a fully consolidated basis.


(b)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(c)

(d)

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2015

The financial statements of PECO include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015		2014		2013
Operating revenues from affiliates:
Generation ^(a)	$	2	$	2	$	1
Purchased power from affiliate
Generation^(b)	$	220	$	194	$	392
Operating and maintenance from affiliates:
BSC ^(c)	$	107	$	96	$	98
Generation	3		3		3
Total operating and maintenance from affiliates	$	110	$	99	$	101
Interest expense to affiliates, net:
PECO Trust III	$	6	$	6	$	6
PECO Trust IV	6		6		6
Total interest expense to affiliates, net	$	12	$	12	$	12
Capitalized costs
BSC ^(c)	$	40	$	39	$	46
Cash dividends paid to parent	$	279	$	320	$	332
Contribution from parent	$	16	$	24	$	27

The financial statements of BGE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015		2014		2013
Operating revenues from affiliates:
Generation ^(a)	$	14	$	25	$	13
Purchased power from affiliate
Generation ^(b)	$	498	$	382	$	452
Operating and maintenance from affiliates:
BSC ^(c)	$	118	$	103	$	83
Interest expense to affiliates, net:
BGE Capital Trust II	$	16	$	16	$	16
Capitalized costs
BSC ^(c)	$	28	$	19	$	15
Cash dividends paid to parent	$	158	$	—	$	—
Contribution from parent	$	7	$	—	$	—

The financial statements of Exelon include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015			2014			2013
Operating revenues from affiliates:
PECO ^(a)	$	1		$	1		$	10
CENG ^(b)	—			17			56
BGE ^(a)	4			5			4
Other	4			—			—
Total operating revenues from affiliates	$	9		$	23		$	70
Purchase power and fuel from affiliates:
CENG^(c)	$	—		$	282		$	992
Keystone Fuels, LLC ^(d)	—			138			144
Conemaugh Fuels, LLC ^(d)	—			99			98
Safe Harbor Water Power Corp ^(d)	—			12			22
Total purchase power and fuel from affiliates	$	—		$	531		$	1,256
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13		$	13
PECO Trust III	6			6			6
PECO Trust IV	6			6			6
BGE Capital Trust II	16			16			16
Total interest expense to affiliates, net	$	41		$	41		$	41
Earnings (losses) in equity method investments:
CENG ^(e)	$	—		$	(19	)	$	9
Qualifying facilities and domestic power projects	(8		)	(1		)	1
Other	$	1		$	—		$	—
Total earnings (losses) in equity method investments	$	(7	)	$	(20	)	$	10

The financial statements of Generation include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015			2014			2013
Operating revenues from affiliates:
ComEd ^(a)	$	18		$	176		$	506
PECO ^(b)	224			198			405
BGE ^(c)	502			387			455
CENG ^(d)	—			17			56
BSC	1			1			1
Other	4			—			—
Total operating revenues from affiliates	$	749		$	779		$	1,423
Purchase power and fuel from affiliates:
ComEd	$	—		$	1		$	1
BGE	14			25			13
CENG ^(e)	—			282			992
Keystone Fuels, LLC ⁽ⁱ⁾	—			138			144
Conemaugh Fuels, LLC ⁽ⁱ⁾	—			99			98
Safe Harbor Water Power Corporation⁽ⁱ⁾	—			12			22
Total purchase power and fuel from affiliates	$	14		$	557		$	1,270
Operating and maintenance from affiliates:
ComEd ^(f)	$	4		$	3		$	2
PECO ^(f)	2			2			1
BSC ^(g)	614			618			571
Total operating and maintenance from affiliates	$	620		$	623		$	574
Interest expense to affiliates, net:
Exelon Corporate ^(j)	$	43		$	53		$	59
Earnings (losses) in equity method investments
CENG^(h)	$	—		$	(19	)	$	9
Qualifying facilities and domestic power projects	(8		)	(1		)	1
Total earnings (losses) in equity method investments	$	(8	)	$	(20	)	$	10
Capitalized costs
BSC ^(g)	$	76		$	91		$	93
Cash distribution paid to member	$	2,474		$	645		$	625
Contribution from member	$	47		$	53		$	26

The financial statements of ComEd include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2015		2014		2013
Operating revenues from affiliates
Generation	$	4	$	4	$	3
Purchased power from affiliate
Generation ^(a)	$	18	$	176	$	512
Operating and maintenance from affiliate
BSC ^(b)	$	195	$	166	$	157
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC ^(b)	$	103	$	77	$	69
Cash dividends paid to parent	$	299	$	307	$	220
Contribution from parent	$	202	$	273	$	—



	December 31,
	2015		2014
Prepaid voluntary employee beneficiary association trust ^(d)	$	—	$	1
Payables to affiliates (current):
Generation ^(b)	$	31	$	40
BSC ^(c)	17		17
Exelon Corporate	1		5
PECO	—		1
BGE Capital Trust II	3		3
Total payables to affiliates (current)	$	52	$	66
Long-term debt to BGE financing trust
BGE Capital Trust II	$	252	$	252

______________________


(a)	BGE provides energy to Generation for Generation’s own use.


(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.


(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(d)

The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.



	December 31,
	2015		2014
Receivables from affiliates (current):
ComEd ^(a)	$	15	$	43
PECO ^(b)	36		29
BGE ^(c)	31		40
Other	1		1
Total receivables from affiliates (current)	$	83	$	113
Intercompany money pool (current):
Exelon Corporate	$	1,252	$	—
Long-term debt due to affiliates (current):
Exelon Corporate ^(l)	$	—	$	556
Payables to affiliates (current):
Exelon Corporate ^(j)	$	16	$	12
BSC ^(g)	78		83
ComEd	9		12
Other	1		—
Total payables to affiliates (current)	$	104	$	107
Long-term debt due to affiliates (noncurrent):
Exelon Corporate ^(l)	$	933	$	943
Payables to affiliates (noncurrent):
BSC ^(g)	$	—	$	1
ComEd ^(k)	2,172		2,389
PECO ^(k)	405		490
Total payables to affiliates (noncurrent)	$	2,577	$	2,880

_______________________


(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.


(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.


(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.

(d)

(e)


(f)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.


(g)	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(h)


(i)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.


(j)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.


(k)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 16—Asset Retirement Obligations.

(l)



	December 31,
	2015		2014
Payables to affiliates (current):
ComEd Financing III	$	4	$	4
PECO Trust III	1		1
BGE Capital Trust II	3		3
Total payables to affiliates (current)	$	8	$	8
Long-term debt due to financing trusts:
ComEd Financing III	$	205	$	205
PECO Trust III	81		81
PECO Trust IV	103		103
BGE Capital Trust II	252		252
Total long-term debt due to financing trusts	$	641	$	641

____________________________

(a)

(b)

(c)


(d)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.

(e)



	December 31,
	2015		2014
Prepaid voluntary employee beneficiary association trust ^(d)	$	2	$	3
Receivable from affiliate (current):
ComEd	$	2	$	2
BGE	—		1
Total receivable from affiliates (current)	$	2	$	3
Receivable from affiliate (noncurrent):
Generation ^(e)	$	405	$	490
Payables to affiliates (current):
Generation^(b)	$	36	$	29
BSC^(c)	17		20
Exelon Corporate	1		2
PECO Trust III	1		1
Total payables to affiliates (current)	$	55	$	52
Long-term debt to financing trusts:
PECO Trust III	$	81	$	81
PECO Trust IV	103		103
Total long-term debt to financing trusts	$	184	$	184

________________________


(a)	PECO provides energy to Generation for Generation’s own use.


(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.


(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.


(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.



	December 31,
	2015		2014
Prepaid voluntary employee beneficiary association trust ^(c)	$	11	$	13
Receivable from affiliates (current):
Voluntary employee beneficiary association trust	$	2	$	2
Generation	9		12
Exelon Corporate ^(e)	188		—
Total receivable from affiliates (current)	$	199	$	14
Receivable from affiliates (noncurrent):
Generation ^(d)	$	2,172	$	2,389
Exelon Corporate ^(e)	—		182
Total receivable from affiliates (noncurrent)	$	2,172	$	2,571
Payables to affiliates (current):
Generation ^(a)	$	15	$	43
BSC ^(b)	39		32
ComEd Financing III	4		4
PECO	2		2
Exelon Corporate	2		3
Total payables to affiliates (current)	$	62	$	84
Long-term debt to ComEd financing trust
ComEd Financing III	$	205	$	205

_______________________

(a)


(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(c)


(d)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.


(e)	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.

Quarterly Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2015

Average Basic And Diluted Shares And Net Income Per Basic And Diluted Share



	Operating Revenues				Operating Income						Net Income on Common Stock
	2015		2014		2015			2014			2015		2014
Quarter ended:
March 31	$	8,830	$	7,237	$	1,366	^(a)	$	168	^(b)	$	693	$	90
June 30	6,514		6,024		1,134		^(a)	842		^(b)	638		522
September 30	7,401		6,912		1,200		^(a)	1,738		^(b)	629		993
December 31	6,702		7,255		707			348			309		18		^(c)

____________________________


(a)	In the first, second, and third quarter of 2015, Exelon reclassified $(1) million, $7 million, and $2 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.


(b)	In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.


(c)	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.



	Average Basic Shares Outstanding (in millions)		Net Income per Basic Share
	2015	2014	2015		2014
Quarter ended:
March 31	862	858	$	0.80	$	0.10
June 30	863	860	0.74		0.61
September 30	913	861	0.69		1.15
December 31	921	861	0.34		0.02
	Average Diluted Shares Outstanding (in millions)		Net Income per Diluted Share
	2015	2014	2015		2014
Quarter ended:
March 31	867	861	$	0.80	$	0.10
June 30	866	864	0.74		0.60
September 30	915	863	0.69		1.15
December 31	924	868	0.33		0.02

Per Share Information

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:



	2015								2014
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	31.37	$	34.44	$	34.98	$	38.25	$	38.93	$	36.26	$	37.73	$	33.94
Low price	25.09		28.41		31.28		31.71		33.07		30.66		33.11		26.45
Close	27.77		29.70		31.42		33.61		37.08		34.09		36.48		33.56
Dividends	0.310		0.310		0.310		0.310		0.310		0.310		0.310		0.310

The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income							Net (Loss) Income on Membership Interest
	2015		2014		2015 (a)			2014				2015		2014
Quarter ended:
March 31	$	5,840	$	4,390	$	719	^(a)	$	(384	)	^(b)	$	443	$	(185	)
June 30	4,232		3,789		703		^(a)	441			^(b)	398		340
September 30	4,768		4,412		622		^(a)	1,225			^(b)	377		771
December 31	4,294		4,802		230			(105		)		154		(91		)

____________________________


(a)	In the first, second, and third quarter of 2015, Generation reclassified $(1) million, $7 million, and $1 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.


(b)	In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income					Net Income
	2015		2014		2015		2014			2015		2014
Quarter ended:
March 31	$	1,185	$	1,134	$	230	$	238		$	90	$	98
June 30	1,148		1,128		243		258		^(a)	99		111
September 30	1,376		1,222		327		287		^(a)	149		126
December 31	1,196		1,079		217		196			87		73

____________________________


(a)	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income.

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income on Common Stock
	2015		2014		2015		2014		2015		2014
Quarter ended:
March 31	$	985	$	993	$	223	$	149	$	139	$	89
June 30	661		656		124		134		70		84
September 30	740		693		154		133		90		81
December 31	645		750		128		156		79		98

The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income attributable to Common Shareholders
	2015		2014		2015		2014		2015		2014
Quarter ended:
March 31	$	1,036	$	1,054	$	204	$	169	$	106	$	85
June 30	628		653		99		55		44		16
September 30	725		697		110		102		51		46
December 31	746		761		144		113		74		52

Significant Accounting Policies - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt	$ 23,645,000,000	$ 19,212,000,000
Percentage ownership of consolidated subsidiaries	100.00%
Percentage ownership of common stock	100.00%
Third Party interest in ComEd (less than $1 million)	$ 1,308,000,000	1,332,000,000
Minimum expectation of tax position to be realized	50.00%
New Accounting Pronouncement, Early Adoption, Effect [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt		157,000,000
Commonwealth Edison Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	99.00%
Third Party interest in ComEd (less than $1 million)	$ 1,000,000	1,000,000
CENG [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	50.01%
RITELine Illinois LLC [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Third Party interest in ComEd (less than $1 million)	$ 1,000,000	1,000,000
Minority interest ownership percentage by parent	12.50%
Exelon Generation Co L L C [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt	$ 7,936,000,000	6,639,000,000
Third Party interest in ComEd (less than $1 million)	$ 1,307,000,000	1,333,000,000
Ownership interest upper bound	99.00%
Ownership interest	50.01%
Cost of spent nuclear fuel disposal per kWh of net nuclear generation	$ (0.001)
Development costs expensed	22,000,000	13,000,000	$ 10,000,000
Exelon Generation Co L L C [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt		70,000,000
Commonwealth Edison Co [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt	$ 5,844,000,000	5,665,000,000
Percentage ownership of consolidated subsidiaries	100.00%
Commonwealth Edison Co [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt		34,000,000
Commonwealth Edison Co [Member] \| RITELine Illinois LLC [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	75.00%
Third-party percentage interest in subsidiaries	25.00%
PECO Energy Co [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt	$ 2,280,000,000	2,232,000,000
PECO Energy Co [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt		14,000,000
Baltimore Gas and Electric Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt	$ 1,480,000,000	1,857,000,000
Baltimore Gas and Electric Company [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Long-term debt		$ 16,000,000
Minimum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	20.00%
Maximum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	50.00%
Nuclear-Fuel Generating Facilities License Extension [Member] \| Exelon Generation Co L L C [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Useful life	20 years

Significant Accounting Policies - Summary of Capitalized Software Costs (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

^[1]

$ 633

$ 596

^[1],[2]

208

186

$ 198

^[1]

180

193

^[1],[2]

172

133

178

163

^[2]

$ 46

$ 43

$ 36

[1]	Net unamortized software costsExelon Generation ComEd PECO BGEDecember 31, 2015$633 $180 $172 $86 $178December 31, 2014596 193 133 84 163 Amortization of capitalized software costsExelon Generation ComEd PECO BGE 2015$208 $73 $47 $33 $462014186 59 45 28 432013198 67 52 33 36
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QjdBNkMxMjBFNTNGRENEMjMyODQxMjI1RThCMzdCRjEM}

Significant Accounting Policies - Summary of Total Interest Incurred, Capitalized and Credits to AFUDC (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

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

$ 1,170

$ 1,144

$ 1,423

^[1],[3]

^[1],[3]

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

445

419

411

^[1],[3]

^[1],[3]

^[2]

336

323

584

^[2]

116

115

117

^[1],[2]

113

118

129

^[1]

^[1]

$ 28

$ 24

$ 13

[1]	.
[2]	Includes interest expense to affiliates.
[3]	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.

Significant Accounting Policies Balance Sheet Classification of Deferred Taxes (Details) - USD ($)	Dec. 31, 2015	Dec. 31, 2014
Other noncurrent assets	$ 1,445,000,000	$ 923,000,000
Other noncurrent liabilities	1,491,000,000	2,147,000,000
New Accounting Pronouncement, Early Adoption, Effect [Member]
Deferred Income Taxes and Other Assets, Current	(244)
Other noncurrent assets	3
Deferred Tax Liabilities, Gross, Current	0
Other noncurrent liabilities	(241)
Commonwealth Edison Co [Member]
Other noncurrent assets	324,000,000	237,000,000
Other noncurrent liabilities	507,000,000	889,000,000
Commonwealth Edison Co [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Deferred Income Taxes and Other Assets, Current	0
Other noncurrent assets	0
Deferred Tax Liabilities, Gross, Current	(63)
Other noncurrent liabilities	63
Exelon Generation Co L L C [Member]
Other noncurrent assets	627,000,000	578,000,000
Other noncurrent liabilities	602,000,000	719,000,000
Exelon Generation Co L L C [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Deferred Income Taxes and Other Assets, Current	(327)
Other noncurrent assets	0
Deferred Tax Liabilities, Gross, Current	0
Other noncurrent liabilities	(327)
PECO Energy Co [Member]
Other noncurrent assets	21,000,000	20,000,000
Other noncurrent liabilities	90,000,000	95,000,000
PECO Energy Co [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Deferred Income Taxes and Other Assets, Current	(69)
Other noncurrent assets	0
Deferred Tax Liabilities, Gross, Current	0
Other noncurrent liabilities	(69)
Baltimore Gas and Electric Company [Member]
Other noncurrent assets	8,000,000	9,000,000
Other noncurrent liabilities	61,000,000	$ 60,000,000
Baltimore Gas and Electric Company [Member] \| New Accounting Pronouncement, Early Adoption, Effect [Member]
Deferred Income Taxes and Other Assets, Current	(6)
Other noncurrent assets	0
Deferred Tax Liabilities, Gross, Current	(52)
Other noncurrent liabilities	$ 46

Variable Interest Entities - Narrative (Details) $ in Millions		9 Months Ended	12 Months Ended
	Apr. 01, 2014 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2015 USD ($) VIE project MW	Dec. 31, 2014 USD ($) VIE	Dec. 31, 2013 USD ($)	Jun. 09, 2015 USD ($)	Jul. 18, 2014 USD ($)
Variable Interest Entity [Line Items]
Note Receivable		$ 27
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Number of variable interest entities not consolidated by equity holders \| VIE			8	6
Number of variable interest entities consolidated \| VIE			7	6
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided			$ 75
Required purchases of power from CENG's nuclear plants not sold to third parties			85.00%
Purchase of nuclear output by EDF			49.99%
Guarantee obligations maximum exposure			$ 9,206
Other Severance Charges [Member]
Consolidated Variable Interest Entity [Abstract]
Severance charges recorded			6
Constellation Energy Nuclear Group [Member] \| Financial Guarantee [Member]
Consolidated Variable Interest Entity [Abstract]
Guarantee obligations maximum exposure	$ 165
Constellation Energy Nuclear Group [Member] \| Payment Guarantee [Member]
Consolidated Variable Interest Entity [Abstract]
Due to affiliate	$ 245
Distributed Energy Company [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests			250				$ 91
Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests			172
Exelon Generation Co L L C [Member]
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided			$ 12
Ownership Percentage Of Consolidated Variable Interest Entities			100.00%
Debt and Capital Lease Obligations			$ 8,869	$ 7,582
Wind project entities with noncontrolling equity interests \| project			9
Noncontrolling equity interest ownership percentage held by third parties			1.00%
Number of projects with significant economic power \| project			8
Ownership interests in project entities			99.00%
Ownership interest			50.01%
Required purchases of power from CENG's nuclear plants not sold to third parties	85.00%
Severance charges recorded			$ 1
Purchase of nuclear output by EDF	49.99%
Guarantee obligations maximum exposure			6,832
Exelon Generation Co L L C [Member] \| Constellation Energy Nuclear Group [Member]
Consolidated Variable Interest Entity [Abstract]
Due from affiliates	$ 400		300
Exelon Generation Co L L C [Member] \| Constellation Energy Nuclear Group [Member] \| Payment Guarantee [Member]
Consolidated Variable Interest Entity [Abstract]
Due to affiliate	205
Exelon Generation Co L L C [Member] \| Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests			78
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided			$ 275
Exelon Generation Co L L C [Member] \| Solar Project Limited Liability Companies [Member]
Consolidated Variable Interest Entity [Abstract]
Business Acquisitions, Megawatts Acquired \| MW			242
Ownership Percentage Of Consolidated Variable Interest Entities			100.00%
Debt and Capital Lease Obligations			$ 655
Exelon Generation Co L L C [Member] \| AGE Biomass project [Member]
Consolidated Variable Interest Entity [Abstract]
Ownership Percentage Of Consolidated Variable Interest Entities			100.00%
Ownership interests in project entities			90.00%
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member]
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided	7		$ 7			$ 275
Remeasurement gain from derecognition of equity method investment	$ 261
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member] \| Equity Method Investment Variable Interest Entities [Member]
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided			637
Baltimore Gas and Electric Company [Member]
Consolidated Variable Interest Entity [Abstract]
Guarantee obligations maximum exposure			262
Baltimore Gas and Electric Company [Member] \| RSB Bond Co LLC [Member]
Consolidated Variable Interest Entity [Abstract]
Remittance of payments received from customers for rate stabilization to BondCo.			$ 86	$ 85	$ 83

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

Dec. 31, 2015

Dec. 31, 2014

Current assets

^[1]

$ 909

^[2]

$ 1,275

Noncurrent assets

^[1]

8,009

^[2]

7,573

^[1]

8,918

^[2]

8,848

Current liabilities

^[1]

473

^[2]

611

Noncurrent liabilities

^[1]

2,927

^[2]

2,728

^[1]

3,400

^[2]

3,339

^[3]

95,384

86,416

Liabilities

^[3]

68,062

62,283

Current assets

881

^[2]

1,247

Noncurrent assets

8,004

^[2]

7,560

8,885

^[2]

8,807

Current liabilities

387

^[2]

526

Noncurrent liabilities

2,884

^[2]

2,597

3,271

^[2]

3,123

^[4]

46,529

44,951

Liabilities

^[4]

33,559

30,900

Noncurrent liabilities

120

122

197

^[5]

8,295

8,056

Liabilities

^[5]

$ 5,418

$ 5,303

[1]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246MjU1NjY5QzIzOUJDQTEyODQyNjUxMjI1RThCM0I0ODAM}
[3]	Exelon’s consolidated assets include $8,268 million and $8,159 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,264 million and $2,728 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[4]	Generation’s consolidated assets include $8,235 million and $8,118 million at December 31, 2015 and 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,135 million and $2,512 million at December 31, 2015 and 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[5]	BGE’s consolidated assets include $26 million and $24 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $122 million and $197 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

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

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

$ 6,502

$ 1,878

$ 1,609

$ 1,486

3,187

3,482

912

1,227

1,365

1,279

1,104

1,024

748

865

15,334

11,853

57,439

52,170

10,342

10,537

2,672

2,625

758

773

1,445

923

22,611

22,393

^[1]

95,384

86,416

1,500

1,802

2,883

3,048

2,376

1,539

205

234

100

238

842

931

9,118

8,762

23,645

19,212

8,585

7,295

3,385

3,366

117

211

1,491

2,147

34,658

33,668

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

68,062

62,283

164

392

100

117

219

297

140

171

181

172

882

1,243

5,160

4,638

2,036

2,097

7,386

6,916

8,268

8,159

111

216

292

115

111

472

561

666

212

1,999

1,763

^[2]

132

2,792

2,167

3,264

2,728

431

780

1,258

671

123

158

2,095

2,295

360

318

1,365

1,276

880

847

531

658

6,342

7,311

25,843

23,028

10,342

10,537

733

771

627

578

14,344

14,612

^[3]

46,529

44,951

1,583

1,759

935

886

182

214

100

238

356

413

4,933

4,459

7,936

6,639

8,431

7,146

117

211

602

719

19,757

18,859

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

^[3]

33,559

30,900

164

392

219

297

140

171

181

172

854

1,215

5,160

4,638

2,036

2,097

7,381

6,903

8,235

8,118

216

292

113

108

386

476

623

1,999

1,763

^[2]

132

2,749

2,036

3,135

2,512

$ 31

$ 89

300

390

112

845

951

6,597

6,204

853

901

^[4]

8,295

8,056

378

209

215

110

131

1,134

794

1,480

1,857

2,552

2,400

Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]

^[4]

5,418

5,303

120

^[2]

120

$ 122

$ 197

[1]	Exelon’s consolidated assets include $8,268 million and $8,159 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,264 million and $2,728 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	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 17—Retirement Benefits for additional details
[3]	Generation’s consolidated assets include $8,235 million and $8,118 million at December 31, 2015 and 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,135 million and $2,512 million at December 31, 2015 and 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[4]	BGE’s consolidated assets include $26 million and $24 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $122 million and $197 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

^[1]

$ 427

$ 205

^[1]

147

Our ownership interest

^[1]

^[1]

269

144

206

319

Payable To Thirdparty To Decommission Nuclear Plant Funded By Pledged Assets

206

319

^[2]

189

292

Commercial Agreement Variable Interest Entities [Member]

^[1]

263

114

^[1]

Our ownership interest

^[1]

Commercial Agreement Variable Interest Entities [Member] | Scenario, Adjustment [Member]

^[1]

241

111

392

234

Equity Method Investment Variable Interest Entities [Member]

158

^[1]

164

^[1]

125

Our ownership interest

^[1]

^[1]

Investments [Member]

Investments [Member] | Commercial Agreement Variable Interest Entities [Member]

Investments [Member] | Equity Method Investment Variable Interest Entities [Member]

Contract Intangible Asset [Member]

Contract Intangible Asset [Member] | Commercial Agreement Variable Interest Entities [Member]

Contract Intangible Asset [Member] | Equity Method Investment Variable Interest Entities [Member]

Payment Guarantee [Member]

Payment Guarantee [Member] | Commercial Agreement Variable Interest Entities [Member]

Payment Guarantee [Member] | Equity Method Investment Variable Interest Entities [Member]

Asset Held In Trust Noncurrent [Member]

Asset Held In Trust Noncurrent [Member] | Commercial Agreement Variable Interest Entities [Member]

^[3]

Asset Held In Trust Noncurrent [Member] | Equity Method Investment Variable Interest Entities [Member]

^[3]

^[3]

$ 0

[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]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[3]	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 $206 million and $319 million as of December 31, 2015 and December 31, 2014, respectively; offset by payables to ZionSolutions LLC of $189 million and $292 million as of December 31, 2015 and December 31, 2014, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

Regulatory Matters - Narrative (Details)																							1 Months Ended			12 Months Ended					20 Months Ended	60 Months Ended	65 Months Ended
Regulatory Matters - Narrative (Details)	Dec. 17, 2015 USD ($)	Nov. 30, 2015 MWh	Nov. 06, 2015 USD ($)	Oct. 20, 2015	Sep. 10, 2015 USD ($)	Jun. 19, 2015 MWh	May 27, 2015 USD ($)	May 07, 2015 USD ($)	Mar. 27, 2015 USD ($)	Dec. 08, 2014	Sep. 15, 2014 USD ($)	Aug. 21, 2014 USD ($)	Dec. 13, 2013	Dec. 02, 2013 V mi	Aug. 23, 2013 USD ($)	Mar. 15, 2013 USD ($)	Feb. 27, 2013	Dec. 05, 2012 USD ($)	Nov. 01, 2012 MWh	Jul. 31, 2012 USD ($)	Apr. 12, 2012 MW	Aug. 09, 2011 USD ($)	Jan. 31, 2014 USD ($)	Sep. 30, 2012 USD ($)	Aug. 31, 2010 USD ($) smart_meter	Dec. 31, 2015 USD ($) V smart_meter	Dec. 31, 2014 USD ($) MW	Dec. 31, 2013 USD ($)	Dec. 31, 2012	Dec. 31, 2007 USD ($)	Dec. 31, 2015 USD ($) smart_meter	Nov. 30, 2010 USD ($)	Nov. 30, 2005 USD ($)	Nov. 05, 2015 USD ($)	Oct. 30, 2015 USD ($)	Jun. 03, 2014 USD ($)	Mar. 31, 2014 USD ($)	Feb. 26, 2014 USD ($)	Mar. 31, 2012 USD ($)	Dec. 16, 2010 USD ($)
Regulatory Matters Additional Narrative Information [Line Items]
Revenue reduction																							$ 8,000,000
Substation kilovolt \| V																										500,000
Near zero emissions coal fueled generation plant \| MW																											166
Parent company pension OPEB regulatory assets noncurrent																										$ 3,156,000,000					$ 3,156,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount																										$ (50,000,000)	$ 269,000,000	$ 353,000,000
Public Utilities, Approved Equity Capital Structure, Annual Reconciliation, Percentage																										7.02%	7.04%	6.94%
Regulatory Assets																										$ 6,824,000,000	$ 6,923,000,000				6,824,000,000
Noncurrent regulatory assets																										6,065,000,000	6,076,000,000				6,065,000,000
Regulatory liabilities																										369,000,000	310,000,000				369,000,000
Business Combination, Integration Related Costs																										80,000,000	179,000,000				121,000,000
Regulatory Liabilities																										4,570,000,000	4,860,000,000				4,570,000,000
Public Utilities, Approved Rate Increase (Decrease), Annual Reconciliation, Amount																										(152,000,000)	72,000,000	$ 181,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount																										$ (67,000,000)	$ 232,000,000	$ 341,000,000
Public Utilities, Approved Equity Capital Structure, Initial Revenue Requirement, Percentage																										7.05%	7.06%	6.94%
Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										$ 92,000,000	$ 59,000,000				92,000,000
Over Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										131,000,000	84,000,000				$ 131,000,000
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Additional revenue requirement allowed by updated government order																										$ 137,000,000	$ 88,000,000
Weighted average debt and equity return																										8.61%	8.62%	8.70%			8.61%
Rate of return on common equity																										11.50%	11.50%	11.50%
Subsequent contribution to technology innovation trust																				$ 4,000,000
Utility annual customer assistance																				$ 10,000,000
Term of contract																										20 years
Demand response peak demand reduction																										2.00%					2.00%
Low income sector consumption reduction targets Act 129 Phase II																										0.10%
Renewable energy procurement																										2.00%					2.00%
Regulatory Assets																										$ 1,113,000,000	$ 1,201,000,000				$ 1,113,000,000
Noncurrent regulatory assets																										895,000,000	852,000,000				895,000,000
Gross transmission revenue requirement																										68,000,000	36,000,000	$ 38,000,000
Transmission revenue true up																										18,000,000	(14,000,000)	30,000,000
Net transmission revenue requirement																										86,000,000	22,000,000	$ 68,000,000
Regulatory liabilities																										155,000,000	125,000,000				155,000,000
Business Combination, Integration Related Costs																										10,000,000	4,000,000
Regulatory Liabilities																										3,614,000,000	3,780,000,000				3,614,000,000
Customer refundable fees																										$ 0	3,000,000				0
Customer refundable fees, interest																											1,000,000
Commonwealth Edison Co [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Renewable energy resources cumulatively increase																										10.00%
Commonwealth Edison Co [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Renewable energy resources cumulatively increase																										25.00%
Commonwealth Edison Co [Member] \| Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										$ 52,000,000	25,000,000				52,000,000
Commonwealth Edison Co [Member] \| Over Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										53,000,000	19,000,000				$ 53,000,000
Over Recovered electric Supply Costs																										29,000,000	3,000,000
Renewable Energy Requirement Revenue																										$ 24,000,000	$ 16,000,000
Commonwealth Edison Co [Member] \| Energy Related Derivative [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Term of contract																										20 years
Commonwealth Edison Co [Member] \| FutureGen Industry Alliance [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Term of contract																											20 years
Commonwealth Edison Co [Member] \| Northern Illinois Project [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Length of transmission line \| mi														60
Substation kilovolt \| V														345,000
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Low income sector consumption reduction targets Act 129 Phase II																		4.50%
Electric distribution tax repairs																						$ 171,000,000
Gas distribution tax repairs refund																								$ 54,000,000
Smart meters initial phase deployment \| smart_meter																										1,600,000.0					1,600,000.0
Estimated number of smart meters to be installed \| smart_meter																										1,700,000					1,700,000
Projected investment in smart meters																										$ 589,000,000					$ 589,000,000
Projected investment in smart grid infrastructure																										155,000,000					155,000,000
Total smart grid smart meter investment grant awarded																										200,000,000					200,000,000
Total smart meter spend on investment																										578,000,000					578,000,000
Total smart grid spend on investment																										155,000,000					155,000,000
Smart grid investment grant awarded							$ 275,000,000	$ 534,000,000
Cumulative consumption reduction targets \| MWh						2,080,553													1,125,852
Public sector maximum consumption reduction targets Act 129 Phase II																		10.00%
Proposed funding Of direct load control program costs																$ 10,000,000
Requested increase in electric revenues																																								$ 225,000,000
Requested increase in gas revenues																																								$ 20,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 127,000,000				$ 190,000,000
Public Utilities, Requested Rate Increase (Decrease), Percentage									10.95%
Regulatory Assets																										1,617,000,000	$ 1,558,000,000				1,617,000,000
Noncurrent regulatory assets																										1,583,000,000	1,529,000,000				1,583,000,000
Regulatory liabilities																										112,000,000	90,000,000				112,000,000
Cost recovery for significant one-time events	$ 7,000,000
Business Combination, Integration Related Costs																										5,000,000	2,000,000
Regulatory Liabilities																										639,000,000	747,000,000				639,000,000
PECO Energy Co [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Percentage Tier I alternative energy resources																													3.50%
Percentage Tier II alternative energy resources																													6.20%
PECO Energy Co [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Low income sector consumption reduction targets Act 129 Phase II																		2.00%
Cumulative consumption reduction targets \| MWh		2,100,875
Percentage Tier I alternative energy resources																													8.00%
Percentage Tier II alternative energy resources																													10.00%
PECO Energy Co [Member] \| Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maximum civil penalty under Act 129																		$ 20,000,000
PECO Energy Co [Member] \| Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										40,000,000	34,000,000				40,000,000
PECO Energy Co [Member] \| Over Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										60,000,000	$ 58,000,000				$ 60,000,000
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Current year revenue adjustment																										$ 200,000,000
Weighted average debt and equity return																										8.46%	8.53%	8.35%			8.46%
Rate of return on common equity																										11.30%	11.30%	11.30%
Increase in electric delivery service revenue resulting from rate case settlement or order.																											$ 22,000,000	$ 34,000,000
Increase in gas delivery service revenue resulting from rate case settlement or order.																											38,000,000	12,000,000
Estimated number of smart meters to be installed \| smart_meter																									2,000,000
Projected investment in smart meters			$ 103,000,000																							$ 37,000,000					$ 37,000,000
Total smart meter spend on investment			140,000,000
Vendor refund			30,000,000
Annual depreciation expense decrease regulated property												$ 20,000,000
Adjustment to electric revenues increase requested			$ 121,000,000								$ 99,000,000				$ 83,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 68,000,000				$ 24,000,000											79,000,000
Requested rate of return on common equity			10.60%										9.75%
Rate Of Return Common Equity Gas Distribution			10.50%										9.60%
Regulatory Assets																										781,000,000	724,000,000				781,000,000
Total projected smart meter smart grid spend																									$ 480,000,000
Reimbursements received from the DOE																									$ 200,000,000
Noncurrent regulatory assets																										514,000,000	510,000,000				514,000,000
Upfront fee																																						$ 75
Recurring fee																																		$ 5.5				$ 11
Gross transmission revenue requirement																										0	9,000,000	2,000,000
Transmission revenue true up																										(3,000,000)	5,000,000	(3,000,000)
Net transmission revenue requirement																										(3,000,000)	14,000,000	$ (1,000,000)
Rate of return on common equity in federal energy regulatory committee complaint										8.80%							8.70%
Regulatory liabilities																										38,000,000	44,000,000				38,000,000
Smart grid incremental cost																										11,000,000
Business Combination, Integration Related Costs																										5,000,000	2,000,000
Site contingency, recovery from third party of environmental remediation cost																																$ 1,000,000	$ 5,000,000
Regulatory Liabilities																										$ 222,000,000	244,000,000				222,000,000
Deferred costs, noncurrent																																					$ 8,000,000		$ 16,000,000
Rate cap imposed on public utility subsidiary																										15.00%
Deferred purchased power costs																														$ 306,000,000
Environmental costs recognized, recovery credited to expense																										$ 73,000,000	65,000,000
Baltimore Gas and Electric Company [Member] \| FERC Transmission Complaint [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public Utilities, Approved Return on Equity, Percentage				10.00%													10.80%
Customer refund liability																																			$ 14,000,000
Baltimore Gas and Electric Company [Member] \| Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										0	0				0
Baltimore Gas and Electric Company [Member] \| Over Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																										19,000,000	28,000,000				19,000,000
Regulatory Liabilities																										18,000,000	7,000,000				18,000,000
Baltimore Gas and Electric Company [Member] \| Over Recovered Decoupling Gas Revenue [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										1,000,000	12,000,000				1,000,000
Baltimore Gas and Electric Company [Member] \| Over Recovered Decoupling Electric Revenue [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																											7,000,000
Baltimore Gas and Electric Company [Member] \| Under-Recovered Electric Revenue Decoupling [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets																										30,000,000					30,000,000
Baltimore Gas and Electric Company [Member] \| Waldorf Project [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Capacity of natural gas fired combined cycle generation plant (in MW) \| MW																					700
Initial term of proposed contract																					20 years
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Minimum purchase obligation																																				$ 25,000,000
Maximum purchase obligation																																				$ 35,000,000
Business Combination, Integration Related Costs																										25,000,000	11,000,000
Exelon Generation Co L L C [Member] \| Conowingo [Member]
Regulatory Matters Additional Narrative Information [Line Items]
License costs																										23,000,000
Exelon Generation Co L L C [Member] \| Muddy Run [Member]
Regulatory Matters Additional Narrative Information [Line Items]
License costs																										22,000,000
Commonwealth Edison and Baltimore Gas and Electric Company [Member] \| Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory liabilities																										94,000,000					94,000,000
Energy Efficiency And Demand Response Programs [Member] \| PECO Energy Co [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Cumulative consumption reduction targets \| MWh		1,962,659
Over-Recovered Electric Transmission Cost [Member] \| PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										3,000,000	3,000,000				3,000,000
Over Recovered Electric Energy And Transmission Costs [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										14,000,000					14,000,000
DSP Program costs [Member] \| PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										35,000,000	39,000,000				35,000,000
OverRecoveredNaturalGasSupply [Member] \| PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										22,000,000	16,000,000				22,000,000
OverRecoveredNaturalGasSupply [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities																										5,000,000	$ 7,000,000				5,000,000
Stride Program [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Captial and OM estimates current year																										113,000,000					113,000,000
Regulatory liabilities																										$ 1,000,000					$ 1,000,000

Regulatory Matters - Estimated Commitments related to PJM Agreements (Details) $ in Millions	Dec. 31, 2015 USD ($)
Other Commitments [Line Items]
Total	$ 3.5
Construction Expansion Plans [Member] \| Commonwealth Edison Co [Member]
Other Commitments [Line Items]
Total	297.0
2015	204.0
2016	61.0
2017	26.0
2018	6.0
2019	0.0
Construction Expansion Plans [Member] \| PECO Energy Co [Member]
Other Commitments [Line Items]
Total	67.0
2015	31.0
2016	24.0
2017	8.0
2018	4.0
2019	0.0
Construction Expansion Plans [Member] \| Baltimore Gas and Electric Company [Member]
Other Commitments [Line Items]
Total	373.0
2015	140.0
2016	112.0
2017	62.0
2018	46.0
2019	$ 13.0

Regulatory Matters - Purchase of Receivables Programs (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

^[1]

$ 229

$ 290

^[2]

(31)

(42)

198

248

^[1]

103

139

^[2]

(16)

(21)

$ 87

118

Purchase of Receivables, Discount Rate related to Implementation Costs

1.00%

^[1]

$ 67

^[2]

(7)

(8)

^[1]

^[2]

(8)

(13)

Public Utilities, General Disclosures [Line Items]

$ 51

$ 62

[1]	(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. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.
[2]	(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.

Regulatory Matters Annual Electric Distribution Filings (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Public Utilities, Requested Rate Increase (Decrease), Amount

$ (50)

$ 269

$ 353

Public Utilities, Approved Rate Increase (Decrease), Amount

(232)

(341)

Public Utilities, Approved Rate Increase (Decrease), Initial Revenue Requirement, Amount

160

Public Utilities, Approved Rate Increase (Decrease), Annual Reconciliation, Amount

$ (152)

$ 72

$ 181

Public Utilities, Approved Equity Capital Structure, Annual Reconciliation, Percentage

7.02%

7.04%

6.94%

Public Utilities, Approved Equity Capital Structure, Initial Revenue Requirement, Percentage

7.05%

7.06%

6.94%

Public Utilities, Approved Return on Equity, Initial Revenue Requirement, Percentage

9.14%

^[1]

9.25%

^[1]

8.72%

Public Utilities, Approved Return on Equity, Annual Reconciliation, Percentage

9.09%

^[1]

9.20%

^[1]

8.72%

[1]	(a) Includes a reduction of 5 basis points for a reliability performance metric penalty.

Mergers, Acquisitions and Dispositions - Narrative (Details) - USD ($)
$ / shares in Units, shares in Millions

2 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

20 Months Ended

Nov. 01, 2014

Dec. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Jun. 30, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2015

May 31, 2014

May 30, 2012

Junior Subordinated Notes, Noncurrent

$ 1,150,000,000

Forward Contract Indexed to Issuer's Equity, Indexed Shares

Business Acquisition, Transaction Costs

$ 923,000,000

$ 1,445,000,000

$ 923,000,000

$ 1,445,000,000

$ 923,000,000

$ 1,445,000,000

Total acquisition costs

40,000,000

386,000,000

$ 0

259,000,000

80,000,000

179,000,000

121,000,000

Bridge loan

$ 3,200,000,000.0

$ 7,200,000,000.0

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

6,702,000,000

$ 7,401,000,000

6,514,000,000

$ 8,830,000,000

7,255,000,000

$ 6,912,000,000

$ 6,024,000,000

$ 7,237,000,000

29,447,000,000

27,429,000,000

24,888,000,000

2,310,000,000

1,176,000,000

2,456,000,000

Derivative, Loss on Derivative

309,000,000

^[1]

629,000,000

638,000,000

693,000,000

18,000,000

993,000,000

522,000,000

90,000,000

^[2]

2,250,000,000

1,820,000,000

1,729,000,000

$ 64,000,000

44,000,000

Net present value of settlement amount

96,000,000

220,000,000

(38,000,000)

430,000,000

Cost of Reimbursable Expense

40,000,000

Payments of Merger Related Costs, Financing Activities

138,000,000

Payments of Debt Restructuring Costs

^[3]

22,000,000

New Jersey Board Of Public Utilities [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

62,000,000

Delaware Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

40,000,000

Maryland Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

66,000,000

District of Columbia Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

78,000,000

Energy Efficiency Program [Member] | New Jersey Board Of Public Utilities [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

15,000,000

Energy Efficiency Program [Member] | Delaware Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

2,000,000

Energy Efficiency Program [Member] | Maryland Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

43,000,000

Workforce Development [Member] | Delaware Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

2,000,000

Workforce Development [Member] | District of Columbia Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

5,000,000

Green Sustainability Fund [Member] | Maryland Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

14,000,000

Rate Bill Credits [Member] | District of Columbia Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

26,000,000

OneTimeBillCredit [Member] | District of Columbia Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

14,000,000

LowIncomeAssistance [Member] | District of Columbia Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

16,000,000

Charitable Contributions [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

53,000,000

Charitable Contributions [Member] | District of Columbia Public Service Commission [Member]

Business Acquisition, Preacquisition Contingency, Amount of Settlement

19,000,000

578,000,000

627,000,000

578,000,000

627,000,000

578,000,000

627,000,000

Total acquisition costs

40,000,000

386,000,000

25,000,000

11,000,000

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

386,000,000

4,294,000,000

4,768,000,000

4,232,000,000

5,840,000,000

4,802,000,000

4,412,000,000

3,789,000,000

4,390,000,000

19,135,000,000

17,393,000,000

15,630,000,000

1,313,000,000

769,000,000

761,000,000

(42,000,000)

154,000,000

377,000,000

398,000,000

443,000,000

(91,000,000)

771,000,000

340,000,000

(185,000,000)

1,340,000,000

1,019,000,000

1,060,000,000

Expected pre-tax proceeds

44,000,000

1,800,000,000

Expected after-tax proceeds

1,400,000,000

Development costs expensed

82,000,000

(61,000,000)

(107,000,000)

22,000,000

13,000,000

10,000,000

9,000,000

8,000,000

9,000,000

8,000,000

9,000,000

8,000,000

5,000,000

2,000,000

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

746,000,000

725,000,000

628,000,000

1,036,000,000

761,000,000

697,000,000

653,000,000

1,054,000,000

3,135,000,000

3,165,000,000

3,065,000,000

288,000,000

211,000,000

210,000,000

74,000,000

51,000,000

44,000,000

106,000,000

52,000,000

46,000,000

16,000,000

85,000,000

288,000,000

211,000,000

210,000,000

Maximum loss contingency

$ 1,700,000.0

(9,000,000)

25,000,000

48,000,000

237,000,000

324,000,000

237,000,000

324,000,000

237,000,000

324,000,000

10,000,000

4,000,000

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

1,196,000,000

1,376,000,000

1,148,000,000

1,185,000,000

1,079,000,000

1,222,000,000

1,128,000,000

1,134,000,000

4,905,000,000

4,564,000,000

4,464,000,000

426,000,000

408,000,000

249,000,000

87,000,000

149,000,000

99,000,000

90,000,000

73,000,000

126,000,000

111,000,000

98,000,000

426,000,000

408,000,000

249,000,000

34,000,000

78,000,000

(8,000,000)

20,000,000

21,000,000

20,000,000

21,000,000

20,000,000

$ 21,000,000

5,000,000

2,000,000

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

645,000,000

740,000,000

661,000,000

985,000,000

750,000,000

693,000,000

656,000,000

993,000,000

3,032,000,000

3,094,000,000

3,100,000,000

378,000,000

352,000,000

395,000,000

$ 79,000,000

$ 90,000,000

$ 70,000,000

$ 139,000,000

$ 98,000,000

$ 81,000,000

$ 84,000,000

$ 89,000,000

378,000,000

352,000,000

395,000,000

$ (13,000,000)

$ 0

$ 13,000,000

Pepco Holdings [Member]

Payments to acquire businesses

Share price

$ 27.25

$ 6,900,000,000

Pepco Holdings [Member] | Minimum [Member]

Pepco Holdings [Member] | Maximum [Member]

Business exit costs

259,000,000

Other long-term investments

$ 180,000,000

180,000,000

$ 180,000,000

Business exit costs

293,000,000

Intergrys Energy Group Inc [Member] | Exelon Generation Co L L C [Member]

Total consideration transferred

$ 332,000,000

Bargain purchase gain (after-tax)

28,000,000

Derivative, Loss on Derivative

$ 108,000,000

Significant Acquisitions and Disposals [Line Items]

$ 7,000,000

$ 5,000,000

[1]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NEExNTZFREE4NkYwMUZCQUZDQTExMjI1RThCRDM3QzcM}
[3]	(e)See Note 14—Debt and Credit Agreements and 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.

Mergers, Acquisitions and Dispositions - Summary of Integrys Energy Group Acquisition (Details) - Exelon Generation Co L L C [Member] - Intergrys Energy Group Inc [Member] $ in Millions	Nov. 01, 2014 USD ($)
Business Acquisition [Line Items]
Total consideration transferred	$ 332
Working capital assets	390
Mark-to-market derivative assets	184
Unamortized energy contracts	115
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	50
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	(196)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative Liabilities	(57)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	(110)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	(16)
Total net assets	360
Bargain purchase gain (after-tax)	$ 28

Mergers, Acquisitions and Dispositions - Costs Recognized after Closing of Merger (Details) $ in Millions	12 Months Ended
	Dec. 31, 2013 USD ($) $ / Customer
Business Acquisition [Line Items]
Rate credit per residential customer (in usd per customer) \| $ / Customer	100
Charitable contributions, per year \| $	$ 7
Period for charitable contributions	10 years
Baltimore Gas and Electric Company [Member]
Business Acquisition [Line Items]
Rate credit per residential customer (in usd per customer) \| $ / Customer	100
Charitable contributions, per year \| $	$ 7
Period for charitable contributions	10 years
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Rate credit per residential customer (in usd per customer) \| $ / Customer	100
Charitable contributions, per year \| $	$ 7
Period for charitable contributions	10 years

Mergers, Acquisitions and Dispositions - Summary of Asset Divestitures (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($) MW	Dec. 31, 2014 USD ($)	Dec. 31, 2013 USD ($)
Long Lived Assets Held-for-sale [Line Items]
Gain (Loss) on Sale of Assets and Asset Impairment Charges \| $	$ 18	$ 437	$ 13
Fore River [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	100.00%
Net Generation Capacity	726,000,000
West Valley [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	100.00%
Net Generation Capacity	185,000,000
Keystone [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	41.98%
Net Generation Capacity	714,000,000
Conemaugh [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	31.28%
Net Generation Capacity	532,000,000
Safe Harbor [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	66.70%
Net Generation Capacity	278,000,000
Quail Run [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	100.00%
Net Generation Capacity	488,000,000
Exelon Generation Co L L C [Member]
Long Lived Assets Held-for-sale [Line Items]
Gain (Loss) on Sale of Assets and Asset Impairment Charges \| $	$ 12	437	$ 13
Gain on Sale of Investments \| $		$ 412

Mergers, Acquisitions and Dispositions - Summary of Major Classes of Assets and Liabilities Held for Sale (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2014

Dec. 31, 2015

Total assets held for sale

$ 147

$ 4

1,539

2,376

Electricity Generation Plant, Non-Nuclear [Member]

931

842

Significant Acquisitions and Disposals [Line Items]

Total assets held for sale

^[1]

143

Inventory

147

Total liabilities held for sale

$ 4

^[2]

Asset impairment charges

$ 50

[1]	The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income for the year ended December 31, 2014. See Note 8 — Impairment of Long-Lived Assets for further information.
[2]	Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Investment in Constellation Energy Nuclear Group, LLC - Narrative (Details) - USD ($)
$ in Millions

2 Months Ended

3 Months Ended

12 Months Ended

20 Months Ended

Apr. 01, 2014

Dec. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2015

Jun. 09, 2015

Schedule of Equity Method Investments [Line Items]

49.99%

$ 9,206

6,702

$ 7,401

$ 6,514

$ 8,830

$ 7,255

$ 6,912

$ 6,024

$ 7,237

29,447

$ 27,429

$ 24,888

Required purchases of power from CENG's nuclear plants not sold to third parties

$ (2,684)

^[1]

(2,624)

(2,684)

^[1]

$ (2,624)

(2,684)

^[1]

(2,040)

^[1]

(2,624)

85.00%

Parental guarantee provided

$ 9

$ 75

Constellation Energy Nuclear Group [Member]

$ 80

179

$ 121

Schedule of Equity Method Investments [Line Items]

Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]

$ 1,500

Schedule of Equity Method Investments [Line Items]

Due to affiliate

245

Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]

Schedule of Equity Method Investments [Line Items]

$ 165

Schedule of Equity Method Investments [Line Items]

Cash distribution paid to member

50.01%

$ 2,474

645

625

49.99%

Total equity investment earnings (losses) - CENG

$ 6,832

6,832

$ 6,832

386

4,294

$ 4,768

$ 4,232

$ 5,840

4,802

$ 4,412

$ 3,789

4,390

19,135

17,393

15,630

Allocation of federal tax benefit under tax sharing agreement

(36)

^[1]

(63)

(36)

^[1]

$ (63)

(36)

^[1]

214

^[1]

(63)

$ 55

Required purchases of power from CENG's nuclear plants not sold to third parties

85.00%

Subsequent purchases of power from CENG's nuclear plants not sold to third parties

50.01%

Parental guarantee provided

$ 749

779

1,423

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

Schedule of Equity Method Investments [Line Items]

Remeasurement gain from derecognition of equity method investment

$ 261

Business combination, step acquisition, equity interest in acquiree, fair value

136

Business acquisition, preexisting relationship, gain (loss) recognized

132

Parental guarantee provided

$ 275

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]

Schedule of Equity Method Investments [Line Items]

509

218

$ 56

Investment in CENG

1,900

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]

$ 116

Schedule of Equity Method Investments [Line Items]

Due from affiliates

$ 400

$ 300

300

$ 300

Interest rate on loan to CENG

5.25%

Allocation of federal tax benefit under tax sharing agreement

$ 152

Reduction to net income attributable to noncontrolling interest

Net Income (Loss) Attributable to Parent

(11)

407

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]

Schedule of Equity Method Investments [Line Items]

Due to affiliate

$ 205

Exelon Generation Co L L C [Member] | EDFI [Member] | Constellation Energy Nuclear Group [Member]

Schedule of Equity Method Investments [Line Items]

Electricite De France LLC [Member]

$ 488

$ 137

Schedule of Equity Method Investments [Line Items]

Required purchases of power from CENG's nuclear plants not sold to third parties

15.00%

Subsequent purchases of power from CENG's nuclear plants not sold to third parties

49.99%

Electricite De France LLC [Member] | Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]

Schedule of Equity Method Investments [Line Items]

Constellation Energy Group LLC [Member]

$ 145

Schedule of Equity Method Investments [Line Items]

Interest rate on distribution

8.50%

Constellation Energy Group LLC [Member] | EDFI [Member]

Schedule of Equity Method Investments [Line Items]

Cash distribution paid to member

$ 400

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

Investment in Constellation Energy Nuclear Group, LLC - Schedule of Assets and Liabilities of CENG (Details) - Exelon Generation Co L L C [Member] - Constellation Energy Nuclear Group [Member] $ in Millions	Apr. 01, 2014 USD ($)
Business Acquisition [Line Items]
Current assets	$ 499
Nuclear decommissioning trust fund	1,955
Property, plant and equipment	3,073
Nuclear fuel	482
Other assets	10
Total assets	6,019
Current liabilities	237
Asset retirement obligation	1,816
Pension and other employee benefit obligations	281
Unamortized energy contract liabilities	171
Other liabilities	114
Total liabilities	2,619
Total net assets	$ 3,400

Accounts Receivable - Schedule of Estimated Unbilled Revenues (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Accounts, Notes, Loans and Financing Receivable [Line Items]

$ 1,203

$ 1,381

^[1]

(284)

(311)

Accounts, Notes, Loans and Financing Receivable [Line Items]

^[2]

732

823

^[1]

(77)

(60)

Accounts, Notes, Loans and Financing Receivable [Line Items]

218

204

^[1]

(75)

(84)

Accounts, Notes, Loans and Financing Receivable [Line Items]

105

140

Current financing receivable allowance for credit losses

^[1],[3]

(83)

(100)

Accounts, Notes, Loans and Financing Receivable [Line Items]

148

214

^[1],[4]

(49)

$ (67)

$ 19

[1]	Includes the allowance for uncollectible accounts on customer and other accounts receivable.
[2]	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.
[3]	the non-current allowance for uncollectible accounts of $8 million at both December 31, 2015 and 2014, related to PECO’s current installment plan receivables described below.
[4]	At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income.

Accounts Receivable - Narrative (Details) $ in Millions	Dec. 31, 2015 USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	$ 15
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	15
Risk Level, Low [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	1
Risk Level, Medium [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	3
Risk Level, High [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	$ 11

Property, Plant and Equipment - Summary of Property, Plant and Equipment (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

$ 73,814

$ 66,912

^[1]

16,375

14,742

Nuclear fuel - work in progress

57,439

52,170

1,266

1,003

Buildings under capital lease

Original cost basis for buildings

Plant Held for Future Use Amount

Accumulated depreciation for buildings

Accumulated amortization of nuclear fuel

2,861

2,673

Electric Transmission and Distribution Equipment [Member]

Electric Transmission and Distribution Equipment [Member] | Maximum [Member]

$ 32,546

30,157

Electric Transmission and Distribution Equipment [Member] | Minimum [Member]

90 years

Electric Generation Equipment [Member]

5 years

Electric Generation Equipment [Member] | Maximum [Member]

$ 25,615

22,911

Electric Generation Equipment [Member] | Minimum [Member]

56 years

Gas Distribution Equipment [Member]

1 year

Gas Distribution Equipment [Member] | Maximum [Member]

$ 3,864

3,505

Gas Distribution Equipment [Member] | Minimum [Member]

90 years

Common Electric And Gas T And D Equipment [Member]

5 years

Common Electric And Gas T And D Equipment [Member] | Maximum [Member]

$ 1,149

1,169

Common Electric And Gas T And D Equipment [Member] | Minimum [Member]

50 years

5 years

Nuclear Fuel [Member]

Nuclear Fuel [Member] | Maximum [Member]

^[2]

$ 6,384

5,947

Nuclear Fuel [Member] | Minimum [Member]

^[2]

8 years

Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

^[2]

1 year

Other Capitalized Property Plant and Equipment [Member]

$ 3,075

2,167

Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]

^[3]

$ 1,181

1,056

Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]

^[3]

50 years

^[3]

5 years

$ 34,482

30,640

^[4]

8,639

7,612

Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member]

25,843

23,028

Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | Maximum [Member]

$ 25,615

22,911

Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | Minimum [Member]

56 years

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

1 year

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

^[5]

$ 6,384

5,947

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

^[5]

8 years

Exelon Generation Co L L C [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

^[5]

1 year

Exelon Generation Co L L C [Member] | Other Capitalized Property Plant and Equipment [Member]

$ 2,017

1,404

Exelon Generation Co L L C [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]

^[6]

$ 466

378

Exelon Generation Co L L C [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]

^[6]

31 years

^[6]

6 years

$ 21,212

19,225

3,710

3,432

Buildings under capital lease

17,502

15,793

Original cost basis for buildings

Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member]

Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member]

$ 20,576

18,884

Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member]

80 years

Commonwealth Edison Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

5 years

Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member]

$ 572

276

Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]

^[7]

$ 64

Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]

^[7]

50 years

^[7]

39 years

$ 10,242

9,718

3,101

2,917

PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member]

7,141

6,801

PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member]

$ 7,230

6,886

PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member]

65 years

PECO Energy Co [Member] | Gas Distribution Equipment [Member]

5 years

PECO Energy Co [Member] | Gas Distribution Equipment [Member] | Maximum [Member]

$ 2,206

2,039

PECO Energy Co [Member] | Gas Distribution Equipment [Member] | Minimum [Member]

70 years

PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member]

5 years

PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member]

$ 631

618

PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member]

50 years

PECO Energy Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

5 years

PECO Energy Co [Member] | Other Capitalized Property Plant and Equipment [Member]

$ 154

154

^[8]

50 years

^[8]

$ 21

9,613

9,072

3,016

2,868

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

6,597

6,204

Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member]

$ 6,663

6,339

Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member]

90 years

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

5 years

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

$ 1,951

1,761

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

90 years

Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member]

5 years

Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member]

$ 655

623

Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member]

40 years

Baltimore Gas and Electric Company [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]

5 years

Baltimore Gas and Electric Company [Member] | Other Capitalized Property Plant and Equipment [Member]

$ 312

317

^[9]

20 years

Capital Leases Net Investment In Direct Financing Leases [Line Items]

^[9]

$ 32

[1]	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively
[2]	Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively.
[3]	Includes Generation’s buildings under capital lease with a net carrying value of $13 million and $15 million at December 31, 2015 and 2014, respectively. The original cost basis of the buildings was $52 million, and total accumulated amortization was $39 million and $37 million, as of December 31, 2015 and 2014, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at December 31, 2015 and 2014, of $7 million and $8 million, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $266 million and $242 million related to oil and gas production activities at Generation
[4]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million and $2,673 million as of December 31, 2015 and 2014, respectively
[5]	Includes nuclear fuel that is in the fabrication and installation phase of $1,266 million and $1,003 million at December 31, 2015 and 2014, respectively
[6]	Includes buildings under capital lease with a net carrying value of $13 million and $15 million at December 31, 2015 and 2014, respectively. The original cost basis of the buildings was $52 million, and total accumulated amortization was $39 million and $37 million, as of December 31, 2015 and 2014, respectively. These balances also include capitalized acquisition, development and exploration costs of $266 million and $242 million related to oil and gas production activities at Generation at December 31, 2015 and 2014, respectively.
[7]	Includes buildings under capital lease with a net carrying value at December 31, 2015 and 2014 of $7 million and $8 million, respectively. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million and $0.3 million as of December 31, 2015 and 2014, respectively
[8]	Represents land held for future use and non-utility property
[9]	Represents land held for future use and non-utility property

Property, Plant and Equipment - Annual Depreciation Provisions as Percentage of Average Service Life (Details)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.83%	2.93%	2.91%
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.47%	3.50%	3.35%
Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.17%	2.13%	2.06%
Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	7.79%	7.32%	7.53%
PECO Energy Co [Member] \| Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.39%	2.55%	2.73%
PECO Energy Co [Member] \| Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	1.87%	1.84%	1.79%
PECO Energy Co [Member] \| Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	5.16%	5.16%	6.65%
Baltimore Gas and Electric Company [Member] \| Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.62%	2.96%	2.91%
Baltimore Gas and Electric Company [Member] \| Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.50%	2.47%	2.36%
Baltimore Gas and Electric Company [Member] \| Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	10.35%	9.49%	8.45%

Property, Plant and Equipment - Narrative (Details)	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.47%	3.50%	3.35%
Exelon Generation Co L L C [Member] \| Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.50%	3.50%	3.35%
Commonwealth Edison Co [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.03%	3.05%	2.97%

Impairment of Long-lived Assets - Narrative (Details) - USD ($)

12 Months Ended

May 31, 2014

Feb. 26, 2014

Sep. 30, 2013

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2000

Oct. 31, 2000

Impairment charges

$ 24,000,000

Estimated residual value of leased assets

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

1,170,000,000

$ 1,144,000,000

$ 1,423,000,000

639,000,000

685,000,000

$ 1,600,000,000

Capital lease net investment in direct financing leases prepayments received

$ 1,200,000,000.0

Proceeds from termination of direct financing lease investment

$ 335,000,000

335,000,000

Capital leases net investment in direct financing leases writeoff

$ 336,000,000

Pre Tax Loss

1,000,000

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Carrying amount of long lived assets to be written down

$ 151,000,000

$ 75,000,000

1,000,000,000

Fair value of impaired assets

65,000,000

32,000,000

556,000,000

Impairment charges

$ 86,000,000

$ 43,000,000

450,000,000

Utilities Operating Expense, Impairments

111,000,000

Exelon Generation Co L L C [Member] | Interest Expense [Member]

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

445,000,000

419,000,000

411,000,000

Capital Leases Net Investment In Direct Financing Leases [Line Items]

8,000,000

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Constellation Energy Group LLC [Member]

^[1],[2]

113,000,000

118,000,000

$ 129,000,000

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Impairment charges

$ 5,000,000

$ 124,000,000

[1]	.
[2]	Includes interest expense to affiliates.
[3]	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.

Impairment of Long-lived Assets - Components of Net Investment in Long-term Leases (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Oct. 31, 2000
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Estimated residual value of leased assets	$ 639	$ 685	$ 1,600
Less: unearned income	287	324
Net investment in long-term leases	$ 352	$ 361

Jointly Owned Electric Utility Plant - Ownership Interests in Jointly Owned Electric Plants and Transmission Facilities (Details)
$ in Millions

12 Months Ended

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Jointly Owned Utility Plant Footnote [Abstract]

Jointly Owned Utility Plant Footnote [Abstract]

500,000

Salem [Member]

Jointly Owned Utility Plant Footnote [Abstract]

500,000

Conemaugh [Member]

Jointly Owned Utility Plant Footnote [Abstract]

500,000

Pennsylvania [Member]

Miles of transmission voltage lines | mi

127

Transmission line capacity | V

500,000

Delaware And New Jersey [Member]

Jointly Owned Utility Plant Footnote [Abstract]

Miles of transmission voltage lines | mi

131

500,000

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Quad Cities [Member]

44.24%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Generation

75.00%

$ 1,035

^[1]

$ 995

^[2]

309

^[1]

266

^[2]

Jointly Owned Utility Plant Footnote [Abstract]

Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Peach Bottom [Member]

$ 1,035

^[1]

995

^[2]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Generation

50.00%

$ 1,345

^[1]

1,095

^[2]

368

^[1]

343

^[2]

Jointly Owned Utility Plant Footnote [Abstract]

133

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

$ 1,345

^[1]

1,095

^[2]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[3]

PSEG Nuclear

^[3]

42.59%

^[2],[3]

$ 566

531

^[2],[3]

167

150

Jointly Owned Utility Plant Footnote [Abstract]

^[3]

Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Salem [Member]

^[2],[3]

566

531

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Jointly Owned Utility Plant Footnote [Abstract]

Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Wyman [Member]

$ 3

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

FP&L

5.89%

^[1],[2]

$ 3

^[1],[2]

Jointly Owned Utility Plant Footnote [Abstract]

Exelon Generation Co L L C [Member] | Other Service [Member] | Other Locations [Member]

^[1],[2]

$ 3

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1]

^[1]

44.24%

^[1],[2]

$ 1

^[1],[2]

Jointly Owned Utility Plant Footnote [Abstract]

^[1]

PECO Energy Co [Member] | Salem [Member]

^[1],[2]

$ 1

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Conemaugh [Member]

42.55%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Pennsylvania [Member]

20.70%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Delaware And New Jersey [Member]

22.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

PECO Energy Co [Member] | Electric Transmission [Member] | Pennsylvania [Member]

42.55%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[4]

First Energy

^[2],[4]

$ 15

^[2],[4]

Jointly Owned Utility Plant Footnote [Abstract]

^[4]

PECO Energy Co [Member] | Electric Transmission [Member] | Delaware And New Jersey [Member]

^[2],[4]

$ 15

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[5]

PSEG

^[5]

42.55%

^[2],[5]

$ 65

^[2],[5]

Jointly Owned Utility Plant Footnote [Abstract]

^[5]

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

^[2],[5]

$ 65

$ 64

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

10.56%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

7.00%

[1]	Excludes asset retirement costs.
[2]	.
[3]	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2015 and 2014.
[4]	PECO owns a 42.55% share in 131 miles of 500kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.
[5]	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.

Intangible Assets - Schedule of Goodwill (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Goodwill, Impairment Loss

$ 0

Goodwill [Roll Forward]

Goodwill, Gross

4,655

$ 4,655

$ 4,608

Goodwill, Impaired, Accumulated Impairment Loss

1,983

Goodwill, beginning balance

2,672

2,625

Goodwill, ending balance

2,672

Goodwill, Impairment Loss

^[1]

Goodwill [Roll Forward]

Goodwill, Gross

^[1]

4,608

Goodwill, Impaired, Accumulated Impairment Loss

1,983

Goodwill, beginning balance

2,625

Goodwill, ending balance

2,625

Goodwill, Impairment Loss

Goodwill [Roll Forward]

Goodwill, Gross

$ 0

Goodwill, beginning balance

Goodwill from business combination

Goodwill, ending balance

$ 47

[1]	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

Intangible Assets - Narrative (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Finite lived intangible assets gross

$ 2,585

Current alternative or renewable energy credits

$ 7

Current alternative or renewable energy credits

251

191

Alternative Or Renewable Energy Credits Noncurrent

Current alternative or renewable energy credits

Unamortized Energy Contracts [Member]

Unamortized Energy Contracts [Member] | Commonwealth Edison Co [Member]

^[1]

135

430

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[1]

Unamortized Energy Contracts [Member] | PECO Energy Co [Member]

^[1]

135

507

Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member]

^[1]

$ 0

Finite lived intangible assets gross

^[2],[3]

$ 1,499

Constellation Energy Group LLC [Member] | Trade Names [Member]

Finite lived intangible assets gross

Useful life

10 years

^[3]

$ 243

[1]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $44 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $3 million, $0 million, $2 million, $3 million and $4 million for 2016, 2017, 2018, 2019 and 2020, respectively.
[3]	On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.

Intangible Assets - Schedule of Other Intangible Assets (Details)
$ in Millions

1 Months Ended

12 Months Ended

Sep. 30, 2011

Dec. 31, 2010

Feb. 28, 2003

USD ($)

Dec. 31, 2015

USD ($)

$ 2,585

(1,830)

755

Finite-Lived Intangible Assets, Amortization Expense, Year Two

(46)

(50)

(79)

(77)

Other miscellaneous unamortized energy contracts

(82)

$ 44

Licensing Agreements [Member]

^[1],[2]

10 years

^[1]

$ 95

^[1]

(6)

^[1]

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[1]

(10)

^[1]

(10)

^[1]

(10)

^[1]

(10)

^[1]

$ (10)

Chicago payment made to city

$ 60

Period for payment

10 years

City of Chicago payment made to 3rd party

$ (2)

City of Chicago payment received

Reduction of amortization expense

$ (2)

Commonwealth Edison Co [Member] | Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member]

^[2],[3]

21 years 9 months 18 days

^[3]

$ 100

^[3]

(83)

^[3]

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[3]

(3)

^[3]

(3)

^[3]

(3)

^[3]

(4)

Commonwealth Edison Co [Member] | Intangible Asset Two Thousand Three Chicago Settlement Agreement [Member]

^[3]

$ (4)

^[2],[4]

17 years 10 months 24 days

^[4]

$ 62

^[4]

(44)

^[4]

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[4]

(4)

^[4]

(4)

^[4]

(4)

^[4]

(3)

^[4]

(3)

Finite-Lived Intangible Assets, Amortization Expense, Year Two

(3)

(2)

(3)

Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member]

$ (4)

Wind turbine supply megawatt | MW

735

Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[2],[5],[6]

18 years

^[5],[6]

$ 224

^[5],[6]

(69)

^[5],[6]

155

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[5],[6]

(14)

^[5],[6]

(14)

^[5],[6]

(14)

^[5],[6]

(14)

Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member]

^[5],[6]

$ (10)

Wind turbine supply megawatt | MW

242

Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[2],[6],[7]

25 years

^[6],[7]

$ 190

^[6],[7]

(20)

^[6],[7]

170

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[6],[7]

(8)

^[6],[7]

(8)

^[6],[7]

(8)

^[6],[7]

(8)

Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member]

^[6],[7]

$ (8)

^[2],[6],[8]

1 year 6 months

^[6],[8]

$ 1,499

^[6],[8]

(1,473)

^[6],[8]

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[6],[8]

(33)

^[6],[8]

(21)

^[6],[8]

(11)

^[6],[8]

(8)

Constellation Energy Group LLC [Member] | Trade Names [Member]

^[6],[8]

$ (10)

^[2],[8]

10 years

^[8]

$ 243

^[8]

(103)

^[8]

140

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[8]

(23)

^[8]

(23)

^[8]

(23)

^[8]

(23)

Constellation Energy Group LLC [Member] | Customer Relationships [Member]

^[8]

$ (23)

^[2],[8],[9]

12 years 4 months 24 days

^[8],[9]

$ 214

^[8],[9]

(76)

^[8],[9]

138

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[8],[9]

(18)

^[8],[9]

(18)

^[8],[9]

(18)

^[8],[9]

(17)

CENG [Member] | Unamortized Energy Contracts [Member]

^[8],[9]

$ (17)

^[2],[6],[10]

1 year 8 months 12 days

^[6],[10]

$ (97)

^[6],[10]

^[6],[10]

(49)

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[6],[10]

(11)

^[6],[10]

(15)

^[6],[10]

(18)

^[6],[10]

(15)

Integrys [Member] | Unamortized Energy Contracts [Member]

^[6],[10]

$ (8)

^[2],[6],[10]

2 years 4 months 24 days

^[6],[11]

$ 5

^[6],[11]

^[6],[11]

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[6],[11]

(5)

^[6],[11]

(1)

^[6],[11]

(1)

^[6],[11]

Integrys [Member] | Customer Relationships [Member]

^[6],[11]

$ 0

^[2],[9],[11]

10 years

^[9],[11]

$ 50

^[9],[11]

(6)

^[9],[11]

Finite-Lived Intangible Assets, Amortization Expense, Year Two

^[9],[11]

(5)

^[9],[11]

(5)

^[9],[11]

(5)

^[9],[11]

(5)

Other Intangible Assets [Member]

^[9],[11]

(5)

Other Intangible Assets [Member] | Customer Relationships [Member]

(1)

^[8],[9]

$ 12

[1]	(a)On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.
[2]	Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.
[3]	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.
[4]	In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago’s behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in Other deferred credits and other liabilities, and other long-term liabilities on Exelon's and ComEd's Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.
[5]	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.
[6]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $44 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $3 million, $0 million, $2 million, $3 million and $4 million for 2016, 2017, 2018, 2019 and 2020, respectively.
[7]	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 242 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.
[8]	On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.
[9]	(h)Excludes $12 million of other miscellaneous customer relationships that have been acquired. The estimated amortization for these miscellaneous customer relationships is $1 million in each of the years from 2016 to 2020.
[10]	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.
[11]	See Note 4—Mergers, Acquisitions, and Dispositions for additional information.

Intangible Assets - Summary of Amortization Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Unamortized Energy Contracts [Member]

$ 7

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[1]

135

430

Unamortized Energy Contracts [Member] | Commonwealth Edison Co [Member]

^[1]

$ 22

135

507

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[1]

$ 0

[1]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

Fair Value of Financial Assets and Liabilities - Narrative (Details)	Dec. 31, 2015 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward Power Basis	$ 2.91
Forward Gas Basis	$ 0.27

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Cash collateral excluded

$ 201,000,000

$ 172,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

^[1]

248,000,000

293,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

(7,000,000)

^[2],[3]

(15,000,000)

^[4],[5]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Derivative assets, fair value

857,000,000

^[2],[3]

893,000,000

^[4],[5]

Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

^[3],[6]

^[5]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member]

^[3],[6]

^[5]

Forward gas price assets

1.18

^[3],[6]

1.52

^[7]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

^[3],[6]

117

^[5],[7]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[3],[6]

120

^[5],[7]

Forward gas price assets

$ 8.95

^[3],[6]

14.02

^[7]

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

Forward gas price assets

$ 8.14

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Volatility percentage

5.00%

^[3]

8.00%

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Volatility percentage

152.00%

^[3]

257.00%

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]

$ (247,000,000)

^[2]

$ (207,000,000)

^[4]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Forward heat rate

8.00%

^[8]

8.00%

^[9]

Marketability Reserve

3.50%

Renewable factor

87.00%

86.00%

Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Forward heat rate

9.00%

^[8]

9.00%

^[9]

Marketability Reserve

7.00%

8.00%

Renewable factor

128.00%

126.00%

[1]	(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
[2]	The fair values do not include cash collateral posted on level three positions of $201 million as of December 31, 2015.
[3]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[4]	The fair values do not include cash collateral posted on level three positions of $172 million as of December 31, 2014
[5]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[6]	he
[7]	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 $97 and $8.14, respectively and would be approximately $76 for power proprietary trading.
[8]	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.
[9]	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 - Narrative (Details)
MWh in Thousands, $ in Millions

12 Months Ended

Dec. 31, 2015

USD ($)

MWh

Dec. 31, 2014

USD ($)

MWh

Dec. 31, 2013

USD ($)

MWh

Jun. 30, 2015

USD ($)

Estimated percentage of natural gas purchases hedged

30.00%

Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound

$ 1,774

$ 1,491

Ineffective portion recognized in income

Notional amount of interest rate swaps acquired from merger

2,400

374

403

Derivative, collateral, right to reclaim cash

205

234

Cash collateral held

Letters of credit held

Net Asset Liability Position After Contractual Right Of Offset

Designated as Hedging Instrument [Member]

Notional amount of preissuance interest rate cash flow hedge derivatives

738

Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

195

$ 464

Designated as Hedging Instrument [Member] | PHI Merger [Member]

Derivative, Gain (Loss) on Derivative, Net

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]

800

1,450

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member]

Interest Rate Swap [Member] | Derivative [Member]

500

Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member] | Cash Flow Hedging [Member]

800

Interest Rate Contract [Member] | Not Designated as Hedging Instrument [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax

Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]

Notional amount of preissuance interest rate cash flow hedge derivatives

400

Net receivable from electric utility

Credit exposure under off system sales

Incremental collateral for loss of investment grade credit rating

$ 35

Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness, Net

$ 4

Proprietary trading activities volume | MWh

10,571

8,762

12,958

Hypothetical increase in interest rates associated with variable-rate debt

50.00%

$ 150

$ 105

Derivative, collateral, right to reclaim cash

182

214

Letters of credit posted

497

672

Cash collateral held

Letters of credit held

Cash collateral posted

1,497

Incremental collateral for loss of investment grade credit rating

2,000

2,400

Net Asset Liability Position After Contractual Right Of Offset

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

7,096

6,813

1,673

1,540

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

4,907

4,947

Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member]

Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income

195

$ 683

Exelon Generation Co L L C [Member] | Derivative [Member]

Derivative, collateral, right to reclaim cash

1,267

Exelon Generation Co L L C [Member] | Derivative [Member] | Other Solar Projects [Member]

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]

550

Exelon Generation Co L L C [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]

Notional amount of interest rate swaps acquired from merger

189

Exelon Generation Co L L C [Member] | Foreign Exchange Contract [Member]

$ 30

Term of contract

20 years

$ 224

187

Net receivable from electric utility

Cash collateral held

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]

^[1]

224

^[1]

187

^[2]

^[1]

$ 20

^[2]

Net receivable from electric utility

Incremental collateral for loss of investment grade credit rating

$ 25

Minimum [Member]

Expected generation hedged in next twelve months

90.00%

Expected generation hedged in year two

60.00%

Expected generation hedged in year three

28.00%

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

Estimated percentage of natural gas purchases hedged

10.00%

Maximum [Member]

Expected generation hedged in next twelve months

93.00%

Expected generation hedged in year two

63.00%

Expected generation hedged in year three

31.00%

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

Estimated percentage of natural gas purchases hedged

20.00%

Debt Instrument, Face Amount

$ 3,300

$ 4,200

Senior Notes [Member] | Exelon Generation Co L L C [Member]

Debt Instrument, Face Amount

$ 750

[1]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[2]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Interest Rate Swap [Member] | Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

$ 15

Mark-to-market derivative liabilities (current liabilities)

(8)

Mark-to-market derivative liabilities (noncurrent liabilities)

(8)

(114)

Interest Rate Derivative Fair Value Of Derivative Net

(16)

(113)

(90)

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(8)

Mark-to-market derivative liabilities (noncurrent liabilities)

(8)

(3)

Interest Rate Derivative Fair Value Of Derivative Net

(16)

(2)

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(2)

Mark-to-market derivative liabilities (noncurrent liabilities)

(1)

Interest Rate Derivative Fair Value Of Derivative Net

(3)

(2)

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Proprietary Trading [Member]

Mark-to-market derivative assets (noncurrent assets)

^[1]

^[2]

^[1]

^[2]

Mark-to-market derivative liabilities (current liabilities)

^[1]

^[2]

(9)

^[1]

(14)

^[2]

Mark-to-market derivative liabilities (noncurrent liabilities)

(3)

^[1]

(9)

^[2]

Interest Rate Derivative Fair Value Of Derivative Net

(12)

^[1]

(23)

^[2]

^[1]

^[2]

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Collateral And Netting [Member]

Mark-to-market derivative assets (noncurrent assets)

(5)

^[3]

(22)

^[4]

(1)

^[3]

(7)

^[4]

Mark-to-market derivative liabilities (current liabilities)

(6)

^[3]

(29)

^[4]

^[3]

^[4]

Mark-to-market derivative liabilities (noncurrent liabilities)

^[3]

^[4]

Interest Rate Derivative Fair Value Of Derivative Net

^[3]

^[4]

^[3]

^[4]

Other Segments [Member] | Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

Mark-to-market derivative liabilities (noncurrent liabilities)

(111)

Interest Rate Derivative Fair Value Of Derivative Net

(111)

(106)

Other Segments [Member] | Interest Rate Swap [Member] | Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

Mark-to-market derivative liabilities (noncurrent liabilities)

(101)

Interest Rate Derivative Fair Value Of Derivative Net

(101)

(100)

Other Segments [Member] | Interest Rate Swap [Member] | Collateral And Netting [Member]

Mark-to-market derivative assets (noncurrent assets)

^[3]

^[3]

(19)

Mark-to-market derivative liabilities (current liabilities)

^[3]

(19)

^[3]

Mark-to-market derivative liabilities (noncurrent liabilities)

^[3]

Interest Rate Derivative Fair Value Of Derivative Net

^[3]

^[3]

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

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

(8)

Mark-to-market derivative liabilities (noncurrent liabilities)

(8)

(4)

Interest Rate Derivative Fair Value Of Derivative Net

(16)

(12)

(16)

(4)

Designated as Hedging Instrument [Member] | Other Segments [Member]

Mark-to-market derivative liabilities (current liabilities)

Designated as Hedging Instrument [Member] | Other Segments [Member] | Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

Mark-to-market derivative liabilities (current liabilities)

Mark-to-market derivative liabilities (noncurrent liabilities)

(29)

Interest Rate Derivative Fair Value Of Derivative Net

(29)

$ 25

$ (6)

[1]	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.
[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]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246MzVENkZDQ0ZEODdBMDc2NzU3MUMxMjI1RThCMzEwMDYM}
[4]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NENEMjJCRjRDMzEyNTE4NUUyNjIxMjI1RThCMzBFMjEM}

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness, Net

$ 4

Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member]

Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member]

$ (9)

$ (3)

Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member]

(24)

Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

^[1]

(6)

Gain (Loss) on Fair Value Hedges Recognized in Earnings

^[1]

(1)

(16)

$ (15)

$ 1

$ (17)

[1]	For the years ended December 31, 2015 and 2014, the loss on Generation swaps included $(1) million and $(17) million realized in earnings, respectively, with an immaterial amount and $4 million excluded from hedge effectiveness testing, respectively.

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Mark-to-market derivative assets (noncurrent assets)

$ 1,365

$ 1,279

758

773

Mark-to-market derivative liabilities (current liabilities)

(205)

(234)

Mark-to-market derivative liabilities (noncurrent liabilities)

(374)

(403)

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

(3)

Total cash collateral received net of cash collateral posted

1,406

Mark-to-market derivative assets (noncurrent assets)

1,365

1,276

733

771

Mark-to-market derivative liabilities (current liabilities)

(182)

(214)

Mark-to-market derivative liabilities (noncurrent liabilities)

(150)

(105)

Mark-to-market derivative liabilities (current liabilities)

(23)

(20)

Mark-to-market derivative liabilities (noncurrent liabilities)

(224)

(187)

Proprietary Trading [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

108

456

Mark-to-market derivative liabilities (current liabilities)

130

512

(94)

(468)

Mark-to-market derivative liabilities (noncurrent liabilities)

(33)

(64)

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

(127)

(532)

(20)

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

Mark-to-market derivative assets (noncurrent assets)

(3,994)

^[1]

(4,184)

^[2]

(1,163)

^[1]

(1,112)

^[2]

Mark-to-market derivative liabilities (current liabilities)

(5,157)

^[1]

(5,296)

^[2]

4,827

^[1]

5,200

^[2]

Mark-to-market derivative liabilities (noncurrent liabilities)

1,564

^[1]

1,502

^[2]

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

6,391

^[1]

6,702

^[2]

1,234

^[1]

1,406

^[2]

Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

1,350

1,264

719

765

Mark-to-market derivative liabilities (current liabilities)

2,069

2,029

(197)

(235)

Mark-to-market derivative liabilities (noncurrent liabilities)

(366)

(289)

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

(563)

(524)

1,506

1,505

Derivative [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

1,350

^[3]

1,264

^[4]

719

^[3]

765

^[4]

Mark-to-market derivative liabilities (current liabilities)

2,069

^[3]

2,029

^[4]

(174)

^[3]

(215)

^[4]

Mark-to-market derivative liabilities (noncurrent liabilities)

(142)

^[3]

(102)

^[4]

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

(316)

^[3]

(317)

^[4]

1,753

^[3]

1,712

^[4]

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

Mark-to-market derivative assets (noncurrent assets)

5,236

4,992

1,860

1,821

Mark-to-market derivative liabilities (current liabilities)

7,096

6,813

(4,907)

(4,947)

Mark-to-market derivative liabilities (noncurrent liabilities)

(1,673)

(1,540)

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

(6,580)

(6,487)

516

326

Current assets collateral offset

(352)

(416)

Noncurrent assets collateral offset

(180)

(171)

Current liabilities collateral offset

(480)

(599)

Collateral Amount Offset Against Fair Value Of Derivative Current Noncurrent Liability

(222)

(220)

Total cash collateral received net of cash collateral posted

1,234

Designated as Hedging Instrument [Member] | Commonwealth Edison Co [Member]

Mark-to-market derivative assets (noncurrent assets)

^[5]

^[6]

Mark-to-market derivative liabilities (current liabilities)

^[5]

(23)

^[5]

(20)

^[6]

Mark-to-market derivative liabilities (noncurrent liabilities)

(224)

^[5]

(187)

^[6]

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

(247)

^[5]

(207)

^[6]

(247)

^[5]

(207)

^[6]

Total Cash Flow Hedges [Member]

Effective portion of changes in fair value

(12)

(31)

Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]

Effective portion of changes in fair value

$ (8)

$ (15)

[1]	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.
[2]	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.
[3]	Current and noncurrent assets are shown net of collateral of $352 million and $180 million, respectively, and current and noncurrent liabilities are shown net of collateral of $480 million and $222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,234 million at December 31, 2015.
[4]	Current and noncurrent assets are shown net of collateral of $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.
[5]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[6]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	$ 4	$ 78
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Reclassifications from accumulated OCI to net income	18,395	16,637	$ 14,277
Ineffective portion recognized in income	17	18
Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Reclassifications from accumulated OCI to net income	18,386	16,614	14,207
Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Accumulated OCI derivative gain - Beginning Balance	(28)	120
Effective portion of changes in fair value	(12)	(31)
Accumulated OCI derivative gain - Ending Balance	(19)	(28)	120
Total Cash Flow Hedges [Member] \| Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Accumulated OCI derivative gain - Beginning Balance	(18)
Effective portion of changes in fair value	(8)	(15)
Accumulated OCI derivative gain - Ending Balance	(21)	(18)
Energy Related Hedges [Member] \| Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Accumulated OCI derivative gain - Beginning Balance		114
Accumulated OCI derivative gain - Ending Balance			$ 114
Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax	10
Other, net [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Total Cash Flow Hedges [Member] \| Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0
Other, net [Member] \| Operating Revenue [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	16
Interest Expense [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Total Cash Flow Hedges [Member] \| Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	7
Interest Expense [Member] \| Operating Revenue [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	7
Operating Revenue [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Total Cash Flow Hedges [Member] \| Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	(2)	(117)
Operating Revenue [Member] \| Operating Revenue One [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	$ (2)
Operating Revenue [Member] \| Operating Revenue [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion		$ (117)

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Change in fair value of commodity positions	$ 49	$ (92)	$ (5)
Reclassification to realized at settlement	58	(2)	(1)
Net mark-to market gains (losses)	357	(693)	507
Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	404	(607)	460
Reclassification to realized at settlement		8	53
Net mark-to market gains (losses)		(599)	513
Operating Revenue [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	0	0	7
Intersegment Eliminations [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	(6)
Reclassification to realized at settlement	0	0	13
Net mark-to market gains (losses)	0	0	7
Intersegment Eliminations [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Interest Rate Swap [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	107	(94)	(6)
Interest Rate Swap [Member] \| Intersegment Eliminations [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	0	0	0
Other Segments [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	0	0	0
Other Segments [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	36	(100)	0
Reclassification to realized at settlement	64	0	0
Net mark-to market gains (losses)	100	(100)	0
Other Segments [Member] \| Interest Rate Swap [Member] \| Interest Expense [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	100	(100)	0
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value of commodity positions	404	(607)	466
Reclassification to realized at settlement	(154)	8	40
Net mark-to market gains (losses)	250	(599)	506
Exelon Generation Co L L C [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	0	0	0
Exelon Generation Co L L C [Member] \| Purchased Power [Member]
Derivative [Line Items]
Change in fair value of commodity positions	13	8	(5)
Reclassification to realized at settlement	(6)	(2)	(1)
Net mark-to market gains (losses)	257	(593)	500
Exelon Generation Co L L C [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	759	(413)	286
Reclassification to realized at settlement	(563)	231	(64)
Net mark-to market gains (losses)	196	(182)	222
Exelon Generation Co L L C [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in fair value of commodity positions	(355)	(194)	180
Reclassification to realized at settlement	409	(223)	104
Net mark-to market gains (losses)	54	(417)	284
Exelon Generation Co L L C [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	13	10	(1)
Reclassification to realized at settlement	(6)	(2)	(1)
Net mark-to market gains (losses)	203	(174)	220
Exelon Generation Co L L C [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	54	(417)	284
Exelon Generation Co L L C [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	(2)	(4)
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	0	(2)	(4)
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Purchased Power [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	7	6	(6)
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	7	8	(2)
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	0	0	0
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Interest Expense [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	$ 0	$ (2)	$ (4)

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Net mark-to-market gains (losses)	$ (8)	$ (26)	$ (39)
Change in fair value	8	1	1
Reclassification to realized at settlement	(10)	3	(3)
Operating Revenue [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	(6)	(30)	(37)
Change in fair value	8	(1)	(22)
Reclassification to realized at settlement	(14)	(29)	(15)
Interest Rate Swap [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	$ (2)	$ 4	$ (2)

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member] $ in Millions	Dec. 31, 2015 USD ($)
Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Investment grade	$ 1,397
Non-investment grade	67
Internally rated—investment grade	521
Internally rated—non-investment grade	77
Total	2,062
Credit Collateral [Member]
Derivative [Line Items]
Investment grade	50
Non-investment grade	25
Internally rated—investment grade	0
Internally rated—non-investment grade	7
Total	82
Net Exposure [Member]
Derivative [Line Items]
Investment grade	1,347
Non-investment grade	42
Internally rated—investment grade	521
Internally rated—non-investment grade	70
Total	1,980
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	1
Non-investment grade	0
Internally rated—investment grade	0
Internally rated—non-investment grade	0
Total	1
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	432
Non-investment grade	0
Internally rated—investment grade	0
Internally rated—non-investment grade	0
Total	$ 432

Derivative Financial Instruments - Net Credit Exposure by Type of Counterparty (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Cash collateral held	$ 13
Letters of credit held	69
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash collateral held	21	$ 77
Letters of credit held	78	$ 24
Exelon Generation Co L L C [Member] \| Net Exposure [Member]
Derivative [Line Items]
Financial institutions	187
Investor-owned utilities, marketers, power producers	886
Energy cooperatives and municipalities	872
Other	35
Total	$ 1,980

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

Dec. 31, 2015

Dec. 31, 2014

Derivative Asset, Fair Value, Gross Liability

^[1]

$ (932)

$ (1,433)

Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements

^[2]

684

1,140

Commercial Paper [Member]

^[3]

$ (248)

$ (293)

[1]	(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.
[2]	(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
[3]	(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) - USD ($)

Dec. 31, 2015

Dec. 31, 2014

May 30, 2014

Mar. 28, 2014

^[1],[2]

Dec. 31, 2013

^[1],[2]

$ 8,150,000,000

$ 8,300,000,000

504,000,000

$ 424,000,000

^[3]

$ 8,425,000,000

Average Interest Rate on Commercial Paper Borrowings

0.88%

0.53%

0.35%

Exelon Corporate [Member] | Commercial Paper [Member]

^[1],[2]

$ 500,000,000

Exelon Corporate [Member] | Revolving Credit Facility [Member]

$ 0

500,000,000

^[3]

$ 500,000,000

^[1],[2]

Bilateral letters of credit

275,000,000

200,000,000

Exelon Generation Co L L C [Member] | Commercial Paper [Member]

^[1],[2]

5,450,000,000

5,600,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 0

0.49%

0.32%

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

^[3]

$ 5,725,000,000

Average Interest Rate on Commercial Paper Borrowings

0.89%

0.50%

0.37%

Commonwealth Edison Co [Member] | Commercial Paper [Member]

^[1],[2]

$ 1,000,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 294,000,000

$ 304,000,000

0.53%

0.33%

Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]

PECO Energy Co [Member] | Commercial Paper [Member]

$ 1,000,000,000

^[3]

$ 1,000,000,000

^[1],[2]

$ 600,000,000

PECO Energy Co [Member] | Revolving Credit Facility [Member]

$ 0

$ 600,000,000

^[3]

600,000,000

^[1],[2]

Average Interest Rate on Commercial Paper Borrowings

0.87%

0.61%

0.31%

Baltimore Gas and Electric Company [Member] | Commercial Paper [Member]

^[1],[2]

$ 600,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 210,000,000

$ 120,000,000

0.48%

0.29%

Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]

^[3]

$ 600,000,000

[1]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[2]	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generation as of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effective program size.
[3]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($)

Dec. 31, 2015

Dec. 31, 2014

May 30, 2014

^[4],[5]

Mar. 28, 2014

^[4],[5]

$ 0

^[1]

1,478,000,000

6,947,000,000

^[2]

6,341,000,000

^[1]

26,000,000

474,000,000

^[2]

474,000,000

^[1]

1,449,000,000

4,276,000,000

Credit facility agreements with minority and community banks

^[2]

4,174,000,000

50,000,000

Bilateral letters of credit

7,000,000

275,000,000

$ 200,000,000

^[1]

2,000,000

998,000,000

Credit facility agreements with minority and community banks

^[2]

704,000,000

34,000,000

14,000,000

^[1]

1,000,000

599,000,000

Credit facility agreements with minority and community banks

^[2]

599,000,000

34,000,000

21,000,000

^[1]

600,000,000

Credit facility agreements with minority and community banks

^[2]

390,000,000

5,000,000

2,000,000

Revolving Credit Facility [Member] | Exelon Corporate [Member]

^[3]

8,425,000,000

Revolving Credit Facility [Member] | Exelon Generation Co L L C [Member]

500,000,000

^[3]

$ 500,000,000

Revolving Credit Facility [Member] | Commonwealth Edison Co [Member]

^[3]

5,725,000,000

Revolving Credit Facility [Member] | PECO Energy Co [Member]

1,000,000,000

^[3]

$ 1,000,000,000

Revolving Credit Facility [Member] | Baltimore Gas and Electric Company [Member]

600,000,000

^[3]

$ 600,000,000

^[3]

$ 600,000,000

[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
[2]	Excludes $275 million bilateral credit facilities that do not back Generation’s commercial paper program
[3]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[4]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[5]	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generation as of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effective program size.

Debt and Credit Agreements - Summary of Short-term Borrowing Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Average borrowings	$ 461	$ 415	$ 203
Maximum borrowings outstanding	$ 684	$ 597	$ 446
Average interest rates, computed on a daily basis	0.53%	0.33%	0.40%
Average interest rates at year end	0.89%	0.50%	0.37%
Exelon Corporate [Member]
Short-term Debt [Line Items]
Average borrowings	$ 499	$ 571	$ 254
Maximum borrowings outstanding	$ 739	$ 1,164	$ 682
Average interest rates, computed on a daily basis	0.53%	0.32%	0.37%
Average interest rates at year end	0.88%	0.53%	0.35%
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Average borrowings	$ 1	$ 93	$ 42
Maximum borrowings outstanding	$ 50	$ 552	$ 291
Average interest rates, computed on a daily basis	0.49%	0.32%	0.32%
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 37	$ 64	$ 35
Maximum borrowings outstanding	$ 210	$ 180	$ 135
Average interest rates, computed on a daily basis	0.48%	0.29%	0.31%
Average interest rates at year end	0.87%	0.61%	0.31%

Debt and Credit Agreements - Narrative (Details)
$ / shares in Units, shares in Millions

1 Months Ended

12 Months Ended

Dec. 02, 2015

USD ($)

Sep. 30, 2013

USD ($)

Jun. 30, 2014

USD ($)

$ / shares

Sep. 30, 2012

USD ($)

Jul. 31, 2011

USD ($)

Dec. 31, 2015

USD ($)

Jan. 05, 2016

USD ($)

Oct. 30, 2015

USD ($)

Jun. 30, 2015

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Sep. 18, 2014

USD ($)

May 31, 2014

USD ($)

May 30, 2014

USD ($)

^[3],[4]

Mar. 28, 2014

USD ($)

^[3],[4]

Feb. 06, 2014

USD ($)

Dec. 31, 2011

USD ($)

Oct. 31, 2011

USD ($)

Jun. 30, 2011

USD ($)

^[1]

$ 1,478,000,000

Bridge loan

$ 3,200,000,000.0

$ 7,200,000,000.0

25,113,000,000

$ 20,864,000,000

Collateral amount of debt

25,761,000,000

Redemption of debt

44,000,000

2,400,000,000

Debt Instrument, Fee Amount

$ 5,000,000

Payments of Debt Issuance Costs

4,000,000

Write off of Deferred Debt Issuance Cost

9,000,000

Redemption Premium

9,000,000

Designated as Hedging Instrument [Member]

Notional amount of preissuance interest rate cash flow hedge derivatives

738,000,000

9,803,000,000

7,071,000,000

Junior Subordinated Debt [Member]

3,300,000,000

$ 4,200,000,000

Redemption of debt

868,000,000

Equity units issued | shares

$ 1,150,000,000.00

$ 1,150,000,000

1,150,000,000

Conversion price | $ / shares

$ 50

Proceeds from issuance of subordinated long-term debt

$ 1,110,000,000

Underwriting fee

35,000,000

$ 131,000,000

Maximum [Member]

0.065%

0.00165

Line of credit facility, maximum borrowing capacity

^[2]

$ 8,425,000,000

^[1]

$ 2,000,000

0.075%

0.01075

$ 6,567,000,000

5,977,000,000

6,773,000,000

Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

1,000,000,000

^[2]

$ 1,000,000,000

^[1]

$ 26,000,000

0.275%

0.01275

$ 5,853,000,000

3,916,000,000

5,853,000,000

$ 1,900,000,000

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

Exelon Corporate [Member] | Revolving Credit Facility [Member]

1,150,000,000

Line of credit facility, maximum borrowing capacity

500,000,000

^[2]

$ 500,000,000

^[1]

$ 1,449,000,000

0.275%

0.01275

$ 8,919,000,000

8,134,000,000

8,919,000,000

Exelon Generation Co L L C [Member] | ExGen Texas Power [Member] | Interest Rate Swap [Member]

2.34%

Exelon Generation Co L L C [Member] | ExgenRenewablesI425June62021[Member] | Interest Rate Swap [Member]

$ 505,000,000

2.03%

Exelon Generation Co L L C [Member] | Constellation Solar Horizons Financing [Member]

$ 240,000,000

Non-recourse debt, commitment

$ 29,000,000

$ 38,000,000

Generation capacity of portfolio | MW

Non-recourse debt, hedge percentage

32,000,000

75.00%

Exelon Generation Co L L C [Member] | Senior Notes [Member]

5,971,000,000

5,771,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Continetal Wind [Member]

750,000,000

Line of credit facility, maximum borrowing capacity

$ 131,000,000

99,000,000

6.00%

Generation capacity of portfolio | MW

$ 613,000,000

667

Aggregate bank commitments under unsecured revolving credit facilities

$ 10,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExGen Texas Power [Member]

572,000,000

4.75%

$ 675,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExgenRenewablesI425June62021[Member]

666,000,000

4.25%

$ 300,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member]

258,000,000

Non-recourse debt, commitment

69,000,000

$ 646,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Sacramento PV Energy [Member]

574,000,000

Generation capacity of portfolio | MW

$ 30,000,000

33,000,000

Non-recourse debt, hedge percentage

$ 41,000,000

75.00%

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Denver International Airport [Member]

$ 7,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Holyoke [Member]

7,000,000

$ 11,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Upstream Gas Property [Member]

10,000,000

Non-recourse debt, commitment

$ 85,000,000

Non-recourse debt, commitment increase available

$ 500,000,000

Exelon Generation Co L L C [Member] | Sumitomo Bank [Member]

68,000,000

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member] | Subsequent Event [Member]

$ 100,000,000

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

$ 150,000,000

Line of credit facility, maximum borrowing capacity

^[2]

5,725,000,000

^[1]

$ 1,000,000

0.00%

0.009

$ 2,600,000,000

2,250,000,000

2,784,000,000

PECO Energy Co [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

600,000,000

^[2]

$ 600,000,000

^[1]

$ 0

0.00%

0.01

$ 1,870,000,000

$ 1,945,000,000

2,128,000,000

Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

^[2]

$ 600,000,000

[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
[2]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[3]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[4]	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generation as of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effective program size.

Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details)
$ in Millions

12 Months Ended

Dec. 31, 2015

USD ($)

$ 1,478

^[1]

2.50 to 1

2.50

$ 1,449

^[1]

3.00 to 1

3.00

$ 2

^[1]

2.00 to 1

2.00

$ 1

^[1]

2.00 to 1

2.00

$ 0

^[1]

2.00 to 1

2.00

[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.

Debt and Credit Agreements - Summary of Interest Coverage Ratios (Details)	Dec. 31, 2015
Debt Instrument [Line Items]
Interest coverage ratio	977.00%
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1231.00%
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Interest coverage ratio	725.00%
PECO Energy Co [Member]
Debt Instrument [Line Items]
Interest coverage ratio	894.00%
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1066.00%

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) - USD ($)

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Jun. 30, 2014

3.95%

$ 25,113,000,000

$ 20,864,000,000

Long-term debt (including amounts due within one year) (a)

(63,000,000)

(37,000,000)

275,000,000

333,000,000

Fair value hedge carrying value adjustment, net

4,000,000

(1,500,000,000)

(1,802,000,000)

23,645,000,000

19,212,000,000

^[1]

641,000,000

648,000,000

^[2]

$ (180,000,000)

(150,000,000)

^[1]

6.35%

PECO Trust Three Affiliate [Member]

^[1]

$ 206,000,000

206,000,000

^[1]

7.38%

PECO Trust Four Affiliate [Member]

^[1]

$ 81,000,000

81,000,000

^[1]

5.75%

BGE Trust Member [Member]

^[1]

$ 103,000,000

103,000,000

^[1]

6.20%

Junior Subordinated Debt [Member]

^[1]

$ 258,000,000

258,000,000

6.50%

$ 1,150,000,000

1,150,000,000

$ 1,150,000,000.00

Secured Debt [Member]

^[3]

1.20%

^[3]

6.45%

^[3]

$ 9,019,000,000

8,079,000,000

Unsecured Debt [Member]

2.80%

6.35%

Rate Stabilization Bonds [Member]

$ 1,750,000,000

1,750,000,000

5.72%

5.82%

$ 120,000,000

195,000,000

1.55%

7.60%

Notes Payable to Banks [Member]

$ 9,803,000,000

7,071,000,000

3.15%

3.35%

Pollution Control Notes [Member]

$ 127,000,000

70,000,000

2.70%

Non Recourse Fixed Rate [Member]

$ 435,000,000

2.293%

6.00%

Non Recourse Variable Rate [Member]

$ 1,162,000,000

1,166,000,000

2.418%

5.00%

Notes Payable, Other Payables [Member]

$ 1,058,000,000

1,101,000,000

^[4]

1.43%

^[4]

7.825%

^[4],[5]

$ 314,000,000

174,000,000

Capital Lease Obligations [Member]

^[2]

(7,000,000)

Capital lease obligations, noncurrent

29,000,000

32,000,000

4,000,000

4,000,000

5,000,000

4,000,000

8,000,000

Software License Arrangement [Member]

contract Payments Junior Subordinate Debt [Member]

$ 111,000,000

2.50%

$ 64,000,000

108,000,000

8,919,000,000

8,134,000,000

Long-term debt (including amounts due within one year) (a)

(17,000,000)

(14,000,000)

127,000,000

146,000,000

(90,000,000)

(614,000,000)

7,936,000,000

6,639,000,000

Debt and Capital Lease Obligations

933,000,000

943,000,000

8,869,000,000

7,582,000,000

Capital lease obligations, noncurrent

21,000,000

24,000,000

4,000,000

4,000,000

5,000,000

4,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member]

^[6]

$ (70,000,000)

(70,000,000)

2.00%

7.60%

Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member]

$ 5,971,000,000

5,771,000,000

3.15%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member]

70,000,000

2.50%

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member]

$ 435,000,000

2.293%

6.00%

Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member]

$ 1,162,000,000

1,166,000,000

2.418%

5.00%

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member]

$ 1,058,000,000

1,101,000,000

1.43%

^[7]

7.825%

^[7],[8]

$ 166,000,000

26,000,000

100,000,000

6,567,000,000

5,977,000,000

(20,000,000)

(19,000,000)

(665,000,000)

(260,000,000)

5,844,000,000

5,665,000,000

205,000,000

Debt and Capital Lease Obligations

206,000,000

5,844,000,000

5,665,000,000

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

^[9]

$ (38,000,000)

(33,000,000)

^[10]

6.35%

$ 206,000,000

205,000,000

Commonwealth Edison Co [Member] | Notes Payable to Banks [Member]

^[9]

$ (1,000,000)

(1,000,000)

^[11]

6.95%

^[11]

7.4865%

Commonwealth Edison Co [Member] | Capital Lease Obligations [Member]

^[11]

$ 148,000,000

148,000,000

Capital lease obligations, noncurrent

8,000,000

Due in 2020

$ 1,000,000

Commonwealth Edison Co [Member] | First Mortgage Bonds [Member]

^[12]

1.95%

^[12]

6.45%

^[12]

$ 6,419,000,000

5,829,000,000

2,600,000,000

2,250,000,000

(5,000,000)

(4,000,000)

2,280,000,000

2,232,000,000

184,000,000

Debt and Capital Lease Obligations

(300,000,000)

2,280,000,000

2,232,000,000

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

^[13]

$ (15,000,000)

(14,000,000)

^[14]

7.38%

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

^[14]

$ 81,000,000

81,000,000

^[14]

5.75%

PECO Energy Co [Member] | First Mortgage Bonds [Member]

^[14]

$ 103,000,000

103,000,000

^[15]

1.20%

^[15]

5.95%

^[15]

$ 2,600,000,000

2,250,000,000

1,870,000,000

1,945,000,000

Long-term debt (including amounts due within one year) (a)

(3,000,000)

1,932,000,000

1,480,000,000

1,857,000,000

252,000,000

258,000,000

(378,000,000)

(75,000,000)

1,480,000,000

1,857,000,000

Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member]

^[16]

$ (9,000,000)

(10,000,000)

^[17]

6.20%

252,000,000

$ 258,000,000

258,000,000

Baltimore Gas and Electric Company [Member] | Unsecured Debt [Member]

^[16]

$ (6,000,000)

(6,000,000)

2.80%

6.35%

Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds [Member]

$ 1,750,000,000

1,750,000,000

5.72%

5.82%

$ 120,000,000

$ 195,000,000

[1]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[2]	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.
[3]	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s assets are subject to the liens of their respective mortgage indentures.
[4]	Includes capital lease obligations of $29 million and $32 million at December 31, 2015 and 2014, respectively. Lease payments of $4 million, $4 million, $4 million, $5 million, $4 million, and $8 million will be made in 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.
[5]	Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2 - Variable Interest Entities for additional information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.
[6]	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.
[7]	Includes Generation’s capital lease obligations of $21 million and $24 million at December 31, 2015 and 2014, respectively. Generation will make lease payments of $4 million, $4 million, $4 million, $5 million and $4 million in 2016, 2017, 2018, 2019, 2020, respectively. The capital lease matures in 2020.
[8]	Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2 - Variable Interest Entities for additional information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2015, $100 million was outstanding.
[9]	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.
[10]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
[11]	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2015 and 2014, respectively. Lease payments of less than $1 million will be made from 2016 through expiration at 2053.
[12]	Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.
[13]	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.
[14]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[15]	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
[16]	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.
[17]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

$ 1,487

1,841

1,393

973

3,311

^[1]

16,756

25,761

BGE Trust Member [Member]

^[2]

641

$ 641

^[2]

258

PECO Financing Trusts [Member]

^[2]

206

^[2]

184

805

673

1,911

5,387

8,919

933

943

665

425

840

300

500

^[3]

4,043

6,773

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

205

206

300

500

^[4]

1,984

2,784

184

378

^[5]

1,708

2,128

Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member]

$ 252

252

$ 252

[1]	Includes $648 million due to ComEd, PECO and BGE financing trusts.
[2]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[3]	Includes $206 million due to ComEd financing trust.
[4]	Includes $184 million due to PECO financing trusts.
[5]	ncludes $258 million due to BGE financing trust.

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Income taxes	$ 1,073	$ 666	$ 1,044
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Income taxes	502	207	615
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Income taxes	280	268	152
PECO Energy Co [Member]
Income Taxes [Line Items]
Income taxes	143	114	162
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current	0	0	0
Income taxes	189	140	134
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Current	407	121	744
Deferred	566	576	140
Investment Tax Credit	22	20	15
Internal Revenue Service (IRS) [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current	546	360	250
Deferred	16	(35)	360
Investment Tax Credit	19	16	11
Internal Revenue Service (IRS) [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current	(80)	(171)	160
Deferred	310	395	(27)
Investment Tax Credit	2	2	2
Internal Revenue Service (IRS) [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current	64	28	126
Deferred	69	87	23
Investment Tax Credit	0	0	1
Internal Revenue Service (IRS) [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current	25	24	9
Deferred	126	90	100
Investment Tax Credit	1	1	1
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Current	(86)	42	181
Deferred	208	(53)	(6)
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current	(90)	35	50
Deferred	49	(137)	(34)
State and Local Jurisdiction [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current	7	7	50
Deferred	45	39	(29)
State and Local Jurisdiction [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current	(10)	(2)	16
Deferred	20	1	(2)
State and Local Jurisdiction [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Deferred	$ 39	$ 27	$ 26

Income Taxes - Reconciliation to Effective Tax Rate (Details)

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

State income taxes, net of Federal income tax benefit

35.00%

^[1]

3.70%

1.30%

4.80%

^[1]

0.40%

(2.40%)

(3.70%)

^[1]

(0.70%)

(2.00%)

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.00%)

(0.10%)

^[1]

(0.90%)

(1.10%)

(1.90%)

^[1]

(1.50%)

(1.90%)

(2.10%)

^[1]

(1.40%)

(2.60%)

(0.10%)

(1.90%)

(2.40%)

(1.60%)

^[1]

0.30%

(1.80%)

(0.00%)

0.20%

0.30%

32.20%

26.80%

37.60%

^[1]

State income taxes, net of Federal income tax benefit

35.00%

^[1]

1.00%

(1.90%)

1.80%

^[1]

0.80%

(4.80%)

(6.10%)

^[1]

(1.30%)

(4.10%)

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.00%)

^[1]

(1.50%)

(2.00%)

(3.00%)

^[1]

(0.00%)

(3.40%)

^[1]

(2.40%)

(5.30%)

(0.20%)

(3.40%)

(4.80%)

(0.00%)

^[1]

0.50%

(3.70%)

(0.00%)

1.10%

(0.40%)

27.10%

16.90%

36.70%

^[1]

State income taxes, net of Federal income tax benefit

35.00%

4.90%

4.50%

3.40%

(0.00%)

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.00%)

(0.20%)

(0.70%)

(0.30%)

(0.60%)

(0.10%)

(0.00%)

(0.00%)

(0.80%)

0.00%

(0.20%)

(0.30%)

39.70%

39.60%

37.90%

State income taxes, net of Federal income tax benefit

35.00%

1.00%

(0.10%)

1.60%

(0.00%)

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.00%)

(0.10%)

(8.70%)

(10.40%)

(0.00%)

(0.00%)

(0.00%)

(7.10%)

0.00%

(0.20%)

(0.10%)

0.30%

27.40%

24.50%

29.10%

State income taxes, net of Federal income tax benefit

35.00%

^[2]

5.30%

5.00%

4.90%

^[2]

(0.00%)

^[2]

(0.00%)

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(0.20%)

^[2]

(0.10%)

(0.30%)

(0.00%)

^[2]

(0.70%)

0.20%

(0.00%)

^[2]

(0.00%)

(0.00%)

(0.20%)

^[2]

0.00%

(0.00%)

0.20%

0.90%

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member]

39.60%

39.90%

39.00%

^[2]

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QzQzNkQ0QjY1NjJBRURBNTg3NjQxMjI1RThCMzFDMkMM}
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QTM3RjVDOEFBRTExN0QzNDRCRUQxMjI1RThCRDk5NTcM}

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Operating Loss Carryforwards [Line Items]
Plant basis differences	$ (13,393)	$ (12,143)
Accrual based contracts	(136)	(178)
Derivatives and other financial instruments	(203)	(46)
Deferred pension and postretirement obligation	1,801	1,914
Nuclear decommissioning activities	(592)	(726)
Deferred debt refinancing costs	133	112
Regulatory assets and liabilities	(1,706)	(1,824)
Tax loss carryforward	103	111
Tax credit carryforward	327	97
Investment in CENG	(595)	(563)
Other, net	1,112	1,029
Deferred income tax liabilities (net)	13,149	12,217
Unamortized investment tax credits	(622)	(555)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(13,771)	(12,772)
Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(4,269)	(3,834)
Accrual based contracts	(136)	(178)
Derivatives and other financial instruments	(181)	(79)
Deferred pension and postretirement obligation	(371)	(390)
Nuclear decommissioning activities	(592)	(726)
Deferred debt refinancing costs	48	57
Regulatory assets and liabilities	0	0
Tax loss carryforward	56	48
Tax credit carryforward	374	143
Investment in CENG	(595)	(563)
Other, net	425	346
Deferred income tax liabilities (net)	5,241	5,176
Unamortized investment tax credits	(598)	(528)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(5,839)	(5,704)
Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(4,424)	(3,945)
Accrual based contracts	0	0
Derivatives and other financial instruments	(4)	(4)
Deferred pension and postretirement obligation	(505)	(543)
Nuclear decommissioning activities	0	0
Deferred debt refinancing costs	(15)	(18)
Regulatory assets and liabilities	(219)	(286)
Tax loss carryforward	0	0
Tax credit carryforward	0	0
Investment in CENG	0	0
Other, net	270	255
Deferred income tax liabilities (net)	4,897	4,541
Unamortized investment tax credits	(17)	(20)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(4,914)	(4,561)
PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(2,901)	(2,749)
Accrual based contracts	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(9)	2
Nuclear decommissioning activities	0	0
Deferred debt refinancing costs	(1)	(2)
Regulatory assets and liabilities	16	27
Tax loss carryforward	0	11
Tax credit carryforward	0	0
Investment in CENG	0	0
Other, net	105	111
Deferred income tax liabilities (net)	2,790	2,600
Unamortized investment tax credits	(2)	(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(2,792)	(2,602)
Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,821)	(1,660)
Accrual based contracts	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	(47)	(53)
Nuclear decommissioning activities	0	0
Deferred debt refinancing costs	(4)	(4)
Regulatory assets and liabilities	(264)	(258)
Tax loss carryforward	33	39
Tax credit carryforward	0	0
Investment in CENG	0	0
Other, net	27	30
Deferred income tax liabilities (net)	2,076	1,906
Unamortized investment tax credits	(5)	(5)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$ (2,081)	$ (1,911)

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details)
$ in Millions

Dec. 31, 2015

USD ($)

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Exelon Generation Co L L C [Member]

$ 416

^[1]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Commonwealth Edison Co [Member]

415

^[1]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | PECO Energy Co [Member]

^[1]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Baltimore Gas and Electric Company [Member]

^[1]

State and Local Jurisdiction [Member]

^[1]

State net operating losses and other credit carryforwards

2,086

^[2]

117

State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member]

State net operating losses and other credit carryforwards

1,259

^[3]

State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member]

State net operating losses and other credit carryforwards

State and Local Jurisdiction [Member] | PECO Energy Co [Member]

State net operating losses and other credit carryforwards

State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member]

State net operating losses and other credit carryforwards

618

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 1

[1]	Exelon’s and Generation's state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 201
[2]	6
[3]	6

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	$ 1,829	$ 2,175	$ 1,024
Increases based on tax positions related to current year	108	15	19
Changes to tax positions that only affect timing	(705)	(255)	649
Increases based on tax positions prior to current year	79	18	493
Decreases based on tax positions prior to current year	(116)	(1)	(6)
Decrease from settlements with taxing authorities	(31)	(35)
Decreases from expiration of statute of limitations	(86)	(88)	(4)
Unrecognized tax benefits - ending balance	1,078	1,829	2,175
Exelon Generation Co L L C [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	1,357	1,415	876
Increases based on tax positions related to current year	0	15	19
Changes to tax positions that only affect timing	(659)	33	36
Increases based on tax positions prior to current year	65	18	493
Decreases based on tax positions prior to current year	(112)	(2)	(5)
Decrease from settlements with taxing authorities	(31)	(34)
Decreases from expiration of statute of limitations	(86)	(88)	(4)
Unrecognized tax benefits - ending balance	534	1,357	1,415
Commonwealth Edison Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	149	324	67
Increases based on tax positions related to current year	0	0	0
Changes to tax positions that only affect timing	(7)	(175)	257
Increases based on tax positions prior to current year	0	0	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0
Decreases from expiration of statute of limitations	0	0	0
Unrecognized tax benefits - ending balance	142	149	324
PECO Energy Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	44	44	44
Increases based on tax positions related to current year	0	0	0
Changes to tax positions that only affect timing	(44)	0	0
Increases based on tax positions prior to current year	0	0	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0
Decreases from expiration of statute of limitations	0	0	0
Unrecognized tax benefits - ending balance	0	44	44
Baltimore Gas and Electric Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	0	0	0
Increases based on tax positions related to current year	106	0	0
Changes to tax positions that only affect timing	0	0	0
Increases based on tax positions prior to current year	14	0	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0
Decreases from expiration of statute of limitations	0	0	0
Unrecognized tax benefits - ending balance	$ 120	$ 0	$ 0

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Mar. 31, 2015	Dec. 31, 1999
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits		$ 540	$ 1,129
Unrecognized Tax Benefits		116	1	$ 6
Deferred gain on sale of property						$ 1,200
IRS asserted penalties for understatement of tax		90
Expected non-cash charge to earnings	$ 265
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position		760
Potential interest expense from a successful IRS challenge of the like-kind exchange position		280
Taxes accrued		293	305		$ 65
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits		112	2	5
Taxes accrued		186	248
Allocation of federal tax benefit under tax sharing agreement	77		55
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits		0	0	0
Taxes accrued		23	42
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits		0	0	0
Deferred gain on sale of property					$ 35
Expected non-cash charge to earnings	172
Noncash contributions from parent	$ 172
Taxes accrued		63	59
Intercompany Non Cash Allocation Of Tax Benefit		202	273	0
PECO Energy Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits		0	0	$ 0
Taxes accrued		4	3
Allocation of federal tax benefit under tax sharing agreement			$ 25
Maximum [Member]
Income Taxes [Line Items]
Cash tax benefit (detriment) as a result of repair costs deduction		$ 120

Income Taxes - Summary of Interest Receivable (Payable) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	$ (288)	$ (310)
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	80	40
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	(210)	(203)
PECO Energy Co [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	3	3
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	$ (1)	$ (1)

Income Taxes - Summary of Interest Expense (Income) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	$ (13)	$ (36)	$ 391
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	(31)	(50)	17
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	7	6	281
PECO Energy Co [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	0	0	(1)
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	$ 0	$ 1	$ 0

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Net increase (decrease) resulting from updates to estimated future cash flows

$ 8

$ 16

Nuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

6,961

^[1]

4,855

Net increase (decrease) resulting from updates to estimated future cash flows

387

334

901

Costs incurred to decommission retired plants

(3)

(7)

^[1]

8,246

6,961

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 7

CENG [Member]

Consolidation of CENG

^[2]

$ 1,760

[1]	Includes $7 million and $8 million as the current portion of the ARO at December 31, 2015 and 2014, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
[2]	(a)Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

Asset Retirement Obligations - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligations [Line Items]
Nuclear decommissioning annual recovery current	$ 24,000,000
Percent of additional decommissioning shortfall with recourse	50.00%
Nuclear decommissioning trust funds	$ 10,342,000,000	$ 10,537,000,000
Minimum [Member]
Asset Retirement Obligations [Line Items]
Years after cessation of plant operations	20 years
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Increase (decrease) in asset retirement obligation		2,100,000,000
AssetRetirementObligationPeriodIncreaseSiteSecurity	$ 630,000,000
Net increase (decrease) resulting from updates to estimated future cash flows	8,000,000	16,000,000
Shortfall of decommissioning funds with recourse	$ 50,000,000
Percent of additional decommissioning shortfall with recourse	5.00%
Nuclear decommissioning trust funds	$ 10,342,000,000	10,537,000,000
Zion Station spent nuclear fuel obligation	84,000,000
ZionSolutions rent payable	1
EnergySolutions letter of credit	$ 200,000,000
Assumed annual after-tax return on NDT funds	2.00%
Assumed annual after-tax return on NDT funds for former PECO units	3.00%
Annual average accretion of the ARO	5.00%
Number of years used in present value measurement	30 years
Estimated annual after tax return on nuclear decommissioning funds lower bound	6.10%
Estimated annual after tax return on nuclear decommissioning funds upper bound	6.30%
Historical five-year annual average after-tax return on NDT funds	7.00%
AssetRetirementObligationPeriodIncreaseSNF	$ 285,000,000
Exelon Generation Co L L C [Member] \| Minimum [Member]
Asset Retirement Obligations [Line Items]
Years after cessation of plant operations	10 years
Exelon Generation Co L L C [Member] \| Maximum [Member]
Asset Retirement Obligations [Line Items]
Years after cessation of plant operations	70 years
Nuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Net increase (decrease) resulting from updates to estimated future cash flows	$ 901,000,000	$ 19,000,000
Nuclear Plant [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Increase (decrease) in asset retirement obligation	$ 1,300,000,000

Asset Retirement Obligations - Unrealized Gain on NDT Funds (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[1]

$ (282)

$ 180

$ 406

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[2],[3]

(197)

134

146

Unrealized Gain Loss Investment Income Pledged Assets

$ 7

$ 29

$ 7

[1]	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
[2]	Excludes $7 million, $29 million and $7 million of net unrealized gains related to the Zion Station pledged assets in 2015, 2014 and 2013, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	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.

Asset Retirement Obligations - Pledged Assets and Payables to ZionSolutions (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Carrying value of Zion Station pledged assets

$ 206

$ 319

Carrying value of Zion Station pledged assets

206

319

Payable to Zion Solutions

^[1]

189

292

Current portion of payable to Zion Solutions

^[2]

137

Withdrawals by Zion Solutions to pay decommissioning costs

^[3]

$ 786

$ 666

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

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase (decrease) resulting from updates to estimated future cash flows

$ 346

^[1]

$ 351

^[2]

(10)

(1)

^[3]

^[4]

(5)

(6)

^[5]

(4)

^[6]

(2)

(20)

^[1]

355

346

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase (decrease) resulting from updates to estimated future cash flows

Reduction to operating and maintenance expense due to updates to estimated future cash flows

(2)

Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase (decrease) resulting from updates to estimated future cash flows

194

^[1]

201

^[2]

(12)

(2)

^[3]

^[4]

(3)

^[5]

(4)

^[6]

(2)

(20)

^[1]

197

194

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Reduction to operating and maintenance expense due to updates to estimated future cash flows

Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase (decrease) resulting from updates to estimated future cash flows

104

^[1]

101

^[2]

^[3]

^[4]

(2)

^[5]

^[6]

^[1]

113

104

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase (decrease) resulting from updates to estimated future cash flows

^[1]

^[2]

(4)

^[3]

^[4]

(1)

^[5]

^[6]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Net increase (decrease) resulting from updates to estimated future cash flows

^[1]

^[2]

(1)

^[3]

^[4]

^[5]

^[6]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

$ 18

[1]	Excludes $1 million, $1 million, $1 million and $1 million as the current portion of the ARO at December 31, 2014 for Generation, ComEd, PECO and BGE, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.
[2]	During the year ended December 31, 2015, Generation recorded a decrease of $(2) million in Operating and maintenance expense. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2015. During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014.
[3]	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.
[4]	For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
[5]	Represents AROs related to generating stations classified as held for sale. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.
[6]	Reflects a reduction to the ARO resulting primarily from the sales of Schuylkill generating station in 2015 and Keystone and Conemaugh generating stations in 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.

Implications of Potential Early Plant Retirements Implications of Potential Early Plant Retirements (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	$ 1,104	$ 1,024
Property, plant and equipment, net	57,439	52,170
Quad Cities [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	50
Nuclear Fuel, Net of Amortization	218
Construction work in progress	11
Asset Retirement Obligation	(698)
Property, plant and equipment, net	1,030
Clinton [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	57
Nuclear Fuel, Net of Amortization	107
Construction work in progress	9
Asset Retirement Obligation	(401)
Property, plant and equipment, net	579
Ginna [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	29
Nuclear Fuel, Net of Amortization	60
Construction work in progress	11
Asset Retirement Obligation	(644)
Property, plant and equipment, net	127
Nuclear Plant [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	136
Nuclear Fuel, Net of Amortization	385
Construction work in progress	31
Asset Retirement Obligation	(1,743)
Property, plant and equipment, net	1,736
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	880	847
Property, plant and equipment, net	$ 25,843	$ 23,028

Retirement Benefits - Narrative (Details) - USD ($)

1 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2014

Apr. 30, 2014

Mar. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Defined benefit plan, amounts recognized In regulatory liabilities, before tax

$ 11,000,000

Effect of federal subsidy on net periodic postretirement benefit costs under the Prescription Drug Act

$ 0

Expected other postretirement benefit plan contributions

250,000,000

$ 35,000,000

Projected Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Funded status of the pension and other postretirement benefit obligations

81.00%

Accumulated Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Funded status of the pension and other postretirement benefit obligations

85.00%

87.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected other postretirement benefit plan contributions

$ 134,000,000

13,000,000

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

30,000,000

2,000,000

Expected other postretirement benefit plan contributions

3,000,000

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

28,000,000

1,000,000

Expected other postretirement benefit plan contributions

1,000,000

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

31,000,000

1,000,000

Expected other postretirement benefit plan contributions

$ 18,000,000

Exelon Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Regulatory asset increase (decrease) due to updated valuation adjustment

48,000,000

Constellation Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

AOCI valuation adjustment

27,000,000

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

7.00%

7.50%

Increase (decrease) in pension obligation

3.94%

^[2]

4.80%

^[3]

3.92%

^[4]

$ 361,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 1,153,000,000

Healthcare cost trend on covered charges

7.00%

Pension Plan, Defined Benefit [Member] | Exelon Generation Co L L C [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 9,000,000

Pension Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Benefit obligation increase (decrease) reflecting actual census data

45,000,000

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

6.46%

6.50%

^[1]

6.59%

^[1]

6.45%

^[1]

Increase (decrease) in pension obligation

3.92%

^[2]

4.90%

^[3]

4.00%

^[4]

$ 117,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 217,000,000

Healthcare cost trend on covered charges

6.71%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Benefit obligation increase (decrease) reflecting actual census data

$ 57,000,000

Non-Qualified Pension Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 21,000,000

[1]	Not applicable to pension and other postretirement benefit plans that do not have plan asset
[2]	)The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2015. Discount rates for CENG's legacy pension and OPEB plans ranged from 3.68%-4.14% and 4.32%-4.43%, respectivel
[3]	The discount rates above represent the initial discount rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2014. 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 of the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.
[4]	The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these remeasurement

Retirement Benefits - Summary of Changes in Benefit Obligations (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Net benefit obligation at beginning of year

$ 18,256

$ 15,459

326

293

$ 317

Interest cost

710

749

650

Actuarial (gain) loss

(582)

2,095

Plan amendments

594

Curtailments

(8)

^[1]

(34)

(30)

Net benefit obligation at end of year

(923)

(896)

17,753

18,256

15,459

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

Net benefit obligation at beginning of year

4,197

4,451

119

117

162

Interest cost

167

186

194

Actuarial (gain) loss

(341)

502

Plan amendments

(23)

(1,012)

142

Curtailments

^[1]

Net benefit obligation at end of year

(223)

(231)

$ 3,938

$ 4,197

$ 4,451

[1]	_______________________ (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.

Retirement Benefits - Summary of Changes in Plan Assets (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Actual return on plan assets

$ 14,874

$ 13,571

(32)

1,443

Employer contributions

462

332

(923)

(896)

454

^[1]

(34)

(30)

Other Postretirement Benefit Plan, Defined Benefit [Member]

14,347

14,874

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Actual return on plan assets

2,430

2,238

Employer contributions

291

(223)

(231)

^[1]

$ 2,293

$ 2,430

[1]	_______________________ (a)On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.

Retirement Benefits - Balance Sheet locations of Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	$ 21	$ 16
Pension obligations	3,385	3,366
Non-pension postretirement benefit obligations	0	0
Unfunded status (net benefit obligation less net plan assets)	3,406	3,382
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	27	25
Pension obligations	0	0
Non-pension postretirement benefit obligations	1,618	1,742
Unfunded status (net benefit obligation less net plan assets)	$ 1,645	$ 1,767

Retirement Benefits - Projected Benefit Obligations and Accumulated Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Projected Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 17,753	$ 18,256
Fair value of net plan assets	14,347	14,874
Accumulated Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	17,753	18,256
Fair value of net plan assets	14,347	14,874
Accumulated benefit obligation	$ 16,792	$ 17,191

Retirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 326	$ 293	$ 317
Interest cost	710	749	650
Expected return on assets	(1,026)	(994)	(1,015)
Prior service cost (credit)	13	14	14
Actuarial loss	571	420	562
Settlement charges	2	2	9
Net periodic benefit cost	596	484	537
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	119	117	162
Interest cost	167	186	194
Expected return on assets	(151)	(154)	(132)
Prior service cost (credit)	(174)	(122)	(19)
Actuarial loss	80	50	83
Settlement charges	0	0	0
Net periodic benefit cost	$ 41	$ 77	$ 288

Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets (Liabilities) related to Retirement Plans (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Current year actuarial loss (gain)

$ 476

$ 1,639

$ (1,169)

Amortization of actuarial loss

(571)

(420)

(562)

Current year prior service (credit) cost

Amortization of prior service (cost) credit

(13)

(14)

Total recognized in AOCI and regulatory assets (liabilities)

(2)

(8)

^[1]

(110)

1,203

(1,753)

Defined benefit plan, amounts recognized in OCI, before tax

788

1,071

Defined benefit plan, amounts recognized in regulatory assets, before tax

415

682

Other Postretirement Benefit Plan, Defined Benefit [Member]

Current year actuarial loss (gain)

(194)

561

(628)

Amortization of actuarial loss

(80)

(50)

(83)

Current year prior service (credit) cost

(23)

(1,012)

Amortization of prior service (cost) credit

174

122

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

(123)

(379)

(677)

Defined benefit plan, amounts recognized in OCI, before tax

162

352

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 60

$ 217

$ 325

[1]

)Of the $110 million gain related to pension benefits, $64 million and $46 million were recognized in AOCI and regulatory assets, respectively, during 2015. Of the $123 million gain related to other postretirement benefits, $63 million and $60 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2015. Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets, respectively, during 2013.

Retirement Benefits - Gross Accumulated Other Comprehensive Loss and Regulatory Assets (Liabilities) not Recognized as Components of Periodic Benefit Cost (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Prior service cost (credit)

$ 36

$ 49

Actuarial loss

7,310

7,407

Benefits included in accumulated other comprehensive income

^[1]

7,346

7,456

4,246

4,310

Benefits included in regulatory assets

3,100

3,146

Other Postretirement Benefit Plan, Defined Benefit [Member]

Prior service cost (credit)

(812)

(963)

Actuarial loss

711

985

Benefits included in accumulated other comprehensive income

^[1]

(101)

$ 22

(63)

Benefits included in regulatory assets

$ (38)

[1]

)Of the $7,346 million related to pension benefits, $4,246 million and $3,100 million are included in AOCI and regulatory assets, respectively, at December 31, 2015. Of the $(101) million related to other postretirement benefits, $(63) million and $(38) million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2015. Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. The $22 million related to other postretirement benefits is included in regulatory assets (liabilities) at December 31, 2014.

Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets expected to be Amortized as Components of Periodic Benefit Cost (Details)
$ in Millions

12 Months Ended

Dec. 31, 2015

USD ($)

Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year

$ (125)

Benefits included in accumulated other comprehensive income

(64)

Benefits included in regulatory assets

(61)

Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)

Defined Benefit Plan, Future Amortization of Gain (Loss)

501

Benefits included in accumulated other comprehensive income

514

^[1]

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax

290

Pension Plan, Defined Benefit [Member] | Regulatory Assets [Member]

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax

224

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)

(175)

Defined Benefit Plan, Future Amortization of Gain (Loss)

Benefits included in accumulated other comprehensive income

$ (125)

^[1]

[1]

___________________ (a)Of the $514 million related to pension benefits at December 31, 2015, $290 million and $224 million are expected to be amortized from AOCI and regulatory assets in 2016, respectively. Of the $(125) million related to other postretirement benefits at December 31, 2015, $(64) million and $(61) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2016, respectively.

Retirement Benefits - Assumptions Used in Calculations (Details)

1 Months Ended

12 Months Ended

Apr. 30, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

4.29%

3.94%

4.80%

3.94%

^[1]

4.80%

^[2]

3.92%

^[3]

Pension Plan, Defined Benefit [Member] | Remeasurement [Member]

^[4]

7.00%

7.50%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

6.59%

4.21%

Pension Plan, Defined Benefit [Member] | First Five Years [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

3.25%

Pension Plan, Defined Benefit [Member] | Thereafter [Member]

3.25%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

3.75%

Other Postretirement Benefit Plan, Defined Benefit [Member]

3.75%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

4.29%

3.92%

4.90%

3.92%

^[1]

4.90%

^[2]

4.00%

^[3]

Health care cost trend rate

6.46%

6.50%

^[4]

6.59%

^[4]

6.45%

^[4]

6.00%

6.50%

Ultimate health care cost trend rate

5.00%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

4.30%

4.66%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Minimum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

4.32%

4.09%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

4.43%

4.55%

CENG Legacy Benefit Plans [Member] | Remeasurement [Member] | Minimum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

3.68%

3.60%

CENG Legacy Benefit Plans [Member] | Remeasurement [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

4.14%

4.30%

[1]	)The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2015. Discount rates for CENG's legacy pension and OPEB plans ranged from 3.68%-4.14% and 4.32%-4.43%, respectivel
[2]	The discount rates above represent the initial discount rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2014. 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 of the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.
[3]	The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these remeasurement
[4]	Not applicable to pension and other postretirement benefit plans that do not have plan asset

Retirement Benefits - Effects of One Percentage Point Change in Assumed Health Care Cost Trend Rates (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015 USD ($)
Compensation and Retirement Disclosure [Abstract]
Effect of a one percentage point increase in assumed healthcare cost trend on 2010 total service and interest cost components	$ 12
Effect of a one percentage point increase in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010	100
Effect of a one percentage point decrease in assumed healthcare cost trend on 2010 total service and interest cost components	(9)
Effect of a one percentage point decrease in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010	$ (89)

Retirement Benefits - Contributions made to Pension and Other Postretirement Benefit Plans (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Pension and non-pension postretirement benefit contributions

$ 502

$ 617

$ 422

250

148

103

Pension and non-pension postretirement benefit contributions

462

^[1]

332

339

Other Postretirement Benefit Plan, Defined Benefit [Member]

250

Pension and non-pension postretirement benefit contributions

291

^[2]

Pension and non-pension postretirement benefit contributions

245

297

149

134

Exelon Generation Co L L C [Member] | Pension Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

231

^[1]

173

119

Exelon Generation Co L L C [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

124

^[2]

Exelon Corporate [Member] | Pension Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

^[1]

Pension and non-pension postretirement benefit contributions

150

248

122

Commonwealth Edison Co [Member] | Pension Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

143

^[1]

122

118

Commonwealth Edison Co [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

125

^[2]

Pension and non-pension postretirement benefit contributions

PECO Energy Co [Member] | Pension Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

^[1]

PECO Energy Co [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

^[2]

Pension and non-pension postretirement benefit contributions

Baltimore Gas and Electric Company [Member] | Pension Plan, Defined Benefit [Member]

^[3]

Pension and non-pension postretirement benefit contributions

^[1]

Baltimore Gas and Electric Company [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

^[2]

Business Services Company [Member] | Pension Plan, Defined Benefit [Member]

^[4]

Pension and non-pension postretirement benefit contributions

^[1]

Business Services Company [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Pension and non-pension postretirement benefit contributions

^[2]

$ 5

^[2]

Constellation Legacy Benefit Plans [Member]

Pension and non-pension postretirement benefit contributions

^[1]

$ 36

$ 43

Remeasurement [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

6.59%

4.21%

Remeasurement [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

4.30%

4.66%

Remeasurement [Member] | Maximum [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan Assumptions Used Calculating Net Periodic Benefit Cost Discount Rate Design Changes

4.43%

4.55%

[1]	Includes $5 million, $9 million, and $72 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2015, 2014, and 2013, respectively.
[2]	_________________________(a)Exelon's and Generation's pension contributions include $36 million and $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG for the years ended December 31, 2015 and 2014, respectively.
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246OTgxRUZBRTQwMEE3OERGNjRCMzUxMjI1RThCRDY3N0QM}
[4]	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.

Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2015 USD ($)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	$ 1,153
2016	997
2017	1,009
2018	1,036
2019	1,071
2020 through 2024	5,923
Total estimated future benefit payments through 2025	11,189
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	217
2016	223
2017	228
2018	235
2019	244
2020 through 2024	1,341
Total estimated future benefit payments through 2025	$ 2,488

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 637

$ 561

$ 825

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

269

250

347

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

206

162

309

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[1]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 66

$ 67

$ 55

[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.

Retirement Benefits - Pension and Other Postretirement Benefit Plan Target Asset Allocations (Details)

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Other Postretirement Benefit Plan, Defined Benefit [Member]

100.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

43.00%

42.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

35.00%

33.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Equity Securities [Member] | Pension Plan, Defined Benefit [Member]

39.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Fixed Income Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

32.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

26.00%

Fixed Income Securities [Member] | Pension Plan, Defined Benefit [Member]

27.00%

34.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

37.00%

Alternative Investments [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

34.00%

37.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

35.00%

Alternative Investments [Member] | Pension Plan, Defined Benefit [Member]

^[1]

30.00%

24.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

31.00%

^[1]

31.00%

30.00%

[1]	Alternative investments include private equity, hedge funds, real estate, and private credit.

Retirement Benefits - Reconciliation of Level 3 Assets and Liabilities measured at Fair Value for Pension and Other Postretirement Benefit Plans (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

$ 14,874

$ 13,571

454

Other Postretirement Benefit Plan, Defined Benefit [Member]

14,347

14,874

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

2,430

2,238

Fair Value, Inputs, Level 3 [Member]

2,293

2,430

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

3,251

2,470

279

731

847

(123)

(60)

^[1]

(423)

(301)

^[2]

Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

3,513

3,251

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

226

115

200

111

(13)

^[1]

(62)

(1)

Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

373

226

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

785

706

(39)

104

(57)

(25)

^[1]

(2)

(1)

^[2]

(30)

Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

795

785

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

138

^[1]

Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

139

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

900

806

112

186

169

^[1]

(222)

(203)

^[2]

Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

924

900

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

(2)

^[1]

(1)

Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

685

544

116

112

(54)

(19)

^[1]

(107)

(60)

^[2]

Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

725

685

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

116

109

(7)

^[1]

(62)

Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

131

116

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

272

(14)

125

227

(7)

(3)

^[1]

(8)

^[2]

Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

368

272

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

^[1]

Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

^[1]

^[2]

Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

^[1]

Private Placement [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

607

371

(19)

200

265

(5)

(13)

^[1]

(84)

(37)

^[2],[3]

Private Placement [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

699

607

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Relating to assets still held at the reporting date

110

(7)

109

(4)

^[1]

Hedge Fund Investments [Member] | Fair Value, Inputs, Level 3 [Member]

$ 103

110

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 43

[1]	Represents cash settlements only.
[2]	As of January 1, 2015 and January 1, 2014, hedge fund investments that contained redemption restrictions limiting Exelon’s ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2014, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $43 million in 2014.
[3]	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.

Retirement Benefits - Summary of Defined Contribution Savings Plan (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 148

$ 103

$ 85

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[2]

$ 7

CENG [Member]

Employer contributions

$ 9

$ 5

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246OTgxRUZBRTQwMEE3OERGNjRCMzUxMjI1RThCRDY3N0QM}
[2]	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.

Contingently Redeemable Noncontrolling Interest Contingently Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		$ 1,548
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	$ 28	0
Temporary Equity, Other Changes	(4)
Exelon Generation Co L L C [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	32	$ 116
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	28
Temporary Equity, Other Changes	$ (4)

Shareholder Equity Schedule of Common Stock Authorided and Outstanding (Details) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 12.50
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	919,924,742	859,833,343
Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Common stock, shares authorized	250,000,000
Common Stock, Shares, Outstanding	127,016,973	127,016,947
PECO Energy Co [Member]
Class of Stock [Line Items]
Common stock, shares authorized	500,000,000
Common Stock, Shares, Outstanding	170,478,507	170,478,507
Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Common stock, shares authorized	175,000,000
Common Stock, Shares, Outstanding	1,000	1,000

Shareholder Equity Shareholder Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2015	Jun. 30, 2015	Dec. 31, 2014
Schedule of Capitalization, Equity [Line Items]
Shares Issued, Price Per Share		$ 35
Junior Subordinated Notes, Noncurrent		$ 1,150
Treasury stock, at cost	$ 2,327		$ 2,327
Treasury Stock, Number of Shares Held	35,000,000
Forward Contract Indexed to Issuer's Equity, Indexed Shares		23,000,000
Sale of Stock, Price Per Share		$ 32.48
Temporary Equity, Share Subscriptions		57,500,000
Baltimore Gas and Electric Company [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized	6,500,000

Shareholder Equity Preferred and Preference Securities (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 190	$ 190
Preferred Stock, Shares Outstanding	1,900,000	1,900,000
Preferred Stock, Shares Authorized	6,500,000
Preference Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share		$ 100
Preferred Stock, Shares Authorized		6,500,000
Series 6.97% Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.97%
Series 6.97% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 50	$ 50
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	500,000	500,000
Series 6.7% Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.70%
Series 6.7% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 40	$ 40
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	400,000	400,000
Series 6.99% Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	6.99%
Series 6.99% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 60	$ 60
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	600,000	600,000
Series 7.125% Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Dividend Rate, Percentage	7.125%
Series 7.125% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 40
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	400,000	400,000
Preferred Stock [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	100,000,000	100,000,000
Preferred Stock [Member] \| Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized	850,000	850,000
Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Par or Stated Value Per Share	$ 100
Cumulative Preferred Stock [Member] \| Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Authorized		6,810,451

- Schedule of Common Stock Authorized and Outstanding (Details) - shares	Dec. 31, 2015	Dec. 31, 2014
Class of Stock [Line Items]
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	919,924,742	859,833,343
Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Common stock, shares authorized	250,000,000
Common Stock, Shares, Outstanding	127,016,973	127,016,947
PECO Energy Co [Member]
Class of Stock [Line Items]
Common stock, shares authorized	500,000,000
Common Stock, Shares, Outstanding	170,478,507	170,478,507
Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Common stock, shares authorized	175,000,000
Common Stock, Shares, Outstanding	1,000	1,000

Stock-Based Compensation Plans - Narrative (Details)

12 Months Ended

Dec. 31, 2015

USD ($)

warrant

$ / shares

Dec. 31, 2014

USD ($)

warrant

$ / shares

Dec. 31, 2013

USD ($)

$ / shares

Dec. 31, 2012

Jun. 30, 2015

USD ($)

$ / shares

Common Stock Narrative Information [Line Items]

Common stock shares reserved for warrant conversion | shares

$ 119,000,000

$ 127,000,000

$ 118,000,000

^[1]

24,478

Equity offering | shares

57,500,000

Price per share (in usd per share) | $ / shares

$ 35

Junior Subordinated Notes, Noncurrent

$ 1,150,000,000

Forward Contract Indexed to Issuer's Equity, Indexed Shares | shares

23,000,000

Treasury Stock, Number of Shares Held | shares

35,000,000

Treasury stock, at cost

$ 2,327,000,000

2,327,000,000

Expiration period

10 years

Obligations of outstanding restricted stock not settled

$ 97,000,000

85,000,000

Settlement of restricted stock

75,000,000

43,000,000

28,000,000

Unrecognized compensation costs of nonvested restricted stock

56,000,000

Weighted average grant date fair value of performance shares (in usd per share)

35.88

28.75

31.55

Settlement of performance shares

46,000,000

27,000,000

26,000,000

Settlement of performance shares in cash

29,000,000

13,000,000

12,000,000

Unrecognized compensation costs of performance based shares

$ 27,000,000

Weighted-average period of recognition of unrecognized compensation costs of performance based shares

1 year 4 months 24 days

Common Stock Narrative Information [Line Items]

Warrants outstanding | warrant

$ 6,000,000

$ 7,000,000

9,000,000

^[1]

73,434

73,533

Common stock shares reserved for warrant conversion | shares

24,511

Performance Shares [Member]

Common Stock Narrative Information [Line Items]

Percentage to be settled as common stock

$ 41,000,000

$ 59,000,000

$ 48,000,000

Mix of awards

67.00%

50.00%

Percentage to be settled as cash

50.00%

Percentage to be settled as cash if ownership requirements are met

100.00%

Weighted average grant date fair value (in usd per share) | $ / shares

$ 35.88

Nonvested Stock Option [Member]

Common Stock Narrative Information [Line Items]

Unrecognized compensation costs

$ 0

Employee Stock Option [Member]

Common Stock Narrative Information [Line Items]

Restricted Stock [Member]

$ 1,000,000

$ 2,000,000

$ 3,000,000

Requisite service period

4 years

Common Stock Narrative Information [Line Items]

Mix of awards

33.00%

Weighted-average period of recognition of unrecognized compensation costs

2 years

Weighted average grant date fair value (in usd per share) | $ / shares

$ 36.55

$ 28.71

$ 31.06

Restricted Stock Units (RSUs) [Member]

Common Stock Narrative Information [Line Items]

Stock Compensation Plan [Member]

$ 71,000,000

$ 61,000,000

Common Stock Narrative Information [Line Items]

Common Stock Narrative Information [Line Items]

$ 6,000,000

$ 5,000,000

$ 6,000,000

Minimum [Member]

Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value

$ 1,870,000,000

Minimum [Member] | Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

3 years

Maximum [Member] | Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

5 years

LTIP [Member]

Common Stock Narrative Information [Line Items]

Shares authorized | shares

16,000,000

2013 Plan [Member] | Performance Shares [Member]

Common Stock Narrative Information [Line Items]

Vesting period

3 years

2012 Plan [Member] | Performance Shares [Member]

Common Stock Narrative Information [Line Items]

Vesting period

3 years

Performance period

1 year

Performance Share Transition Award [Member]

Common Stock Narrative Information [Line Items]

Percentage to be settled as common stock

50.00%

Percentage to be settled as cash

50.00%

Percentage to be settled as cash if ownership requirements are met

100.00%

Performance Share Transition Award [Member] | Performance Shares [Member]

Common Stock Narrative Information [Line Items]

Vesting period

1 year

Performance period

2 years

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QUY1RTYxOTI4NTg4NjNCODc2RTgxMjI1RThCREM3QzMM}

Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

$ 119

$ 127

$ 118

^[1]

$ (46)

$ (47)

$ (44)

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QUY1RTYxOTI4NTg4NjNCODc2RTgxMjI1RThCREM3QzMM}

Stock-Based Compensation Plans - Schedule of Pre-Tax Stock-based Compensation Expense (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

^[1]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 119

$ 127

$ 118

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

^[2]

$ 43

$ 60

$ 50

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QUY1RTYxOTI4NTg4NjNCODc2RTgxMjI1RThCREM3QzMM}
[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.

Stock-Based Compensation Plans - Components of Tax Benefits from Stock-based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Common Stock [Abstract]
Restricted stock units	$ 30	$ 17	$ 11
Performance share awards	18	11	11
Stock deferral plan	$ 0	$ 0	$ 1

Stock-Based Compensation Plans - Assumptions used in Calculating Fair Value of Options (Details)	12 Months Ended
	Dec. 31, 2012 $ / shares
Common Stock [Abstract]
Dividend yield	5.28%
Expected volatility	23.20%
Risk-free interest rate	1.30%
Expected life (years)	6 years 3 months
Weighted average grant date fair value (per share)	$ 4.18

Stock-Based Compensation Plans - Summary of Stock Option Activity (Details) - Employee Stock Option [Member] - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

18,830,967

(7,133)

(5,250)

(3,245,827)

15,572,757

Weighted Average Exercise Price (in usd per share)

$ 46.68

$ 46.85

Options Reinstated, Weighted Average Exercise Price (in usd per share)

21.25

Options Forfeited, Weighted Average Exercise Price (in usd per share)

39.81

Options Expired, Weighted Average Exercise Price (in usd per share)

$ 47.75

Shares Outstanding, Weighted Average Remaining Contractual Life

3 years 10 months 6 days

Shares Outstanding, Aggregate Intrinsic Value

$ 9

Exercisable at December 31, 2014

^[1]

15,490,507

Shares Exercisable, Weighted Average Exercise Price (in usd per share)

^[1]

$ 46.72

Shares Exercisable, Weighted Average Remaining Contractual Life

^[1]

3 years 10 months 2 days

Shares Exercisable, Aggregate Intrinsic Value

^[1]

$ 9

[1]	Includes stock options issued to retirement eligible employees.

Stock-Based Compensation Plans - Summary of Information of Stock Options Exercised (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Cash received for exercise price

Aggregate value

^[1]

$ 0

$ 3

$ 4

$ 0

$ 7

$ 19

[1]	Includes stock options issued to retirement eligible employees.

Stock-Based Compensation Plans - Summary of Nonvested Stock Option Activity (Details) - Nonvested Stock Option [Member] - $ / shares

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]

Beginning Balance

^[1]

432,035

Vested

(344,535)

Forfeited

(5,250)

Ending Balance

^[1]

82,250.00000

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

$ 39.81

$ 39.91

Vested, Weighted Average Exercise Price (in usd per share)

39.93

Forfeited, Weighted Average Exercise Price (in usd per share)

$ 39.81

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

279,000

746,140

[1]	Excludes 279,000 and 746,140 of stock options issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.

Stock-Based Compensation Plans - Summary of Nonvested Restrict Stock Unit Activity (Details) - Restricted Stock [Member] - $ / shares

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Beginning Balance

^[1]

3,758,218

Granted

2,132,856

Vested

(1,597,255)

Forfeited

(76,232)

Undistributed vested awards

^[2]

(654,333)

Ending Balance

^[1]

3,563,254

3,758,218

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

$ 31.27

Granted, Weighted Average Grant Date Fair Value (in usd per share)

36.55

$ 28.71

$ 31.06

Vested, Weighted Average Exercise Price (in usd per share)

32.88

Forfeited, Weighted Average Exercise Price (in usd per share)

33.06

Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)

^[2]

35.35

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

$ 32.92

$ 31.27

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

1,097,630

975,116

[1]	Excludes 1,097,630 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.
[2]	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2015.

Stock-Based Compensation Plans - Summary of Nonvested Performance Share Awards Activity (Details) - Performance Shares [Member] - $ / shares

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Beginning Balance

^[1]

2,696,097

Granted

1,556,273

Change in performance

(118,398)

Vested

(704,141)

Forfeited

(52,167)

Undistributed vested awards

^[2]

(820,505)

Ending Balance

^[1]

2,557,159

2,696,097

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

$ 31.88

$ 30.62

Granted, Weighted Average Grant Date Fair Value (in usd per share)

35.88

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Change in Performance, Weighted Average Grant Date Fair Value

35.88

Vested, Weighted Average Exercise Price (in usd per share)

32.80

Forfeited, Weighted Average Exercise Price (in usd per share)

32.25

Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)

^[2]

$ 33.95

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

1,817,883

1,535,791

[1]	Excludes 1,817,883 and 1,535,791 of performance share awards issued to retirement-eligible employees as of December 31, 2015 and 2014, respectively, as they are fully vested.
[2]	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2015.

Stock-Based Compensation Plans - Balance Sheet Classification of Obligations related to Outstanding Performance Share Awards Not Yet Settled (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Deferred credits and other liabilities

Current liabilities

^[1]

$ 28

^[2]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

$ 95

$ 97

[1]	Represents the current liability related to performance share awards expected to be settled in cash.
[2]	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share [Abstract]
Net income attributable to common shareholders									$ 2,269	$ 1,623	$ 1,719
Weighted average common shares outstanding—basic	921	913	863	862	861	861	860	858	890	860	856
Assumed exercise and/or distributions of stock-based awards									3	4	4
Weighted average common shares outstanding—diluted	924	915	866	867	868	863	864	861	893	864	860

Earnings Per Share and Equity - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger)	16,000,000	17,000,000	20,000,000
Treasury Stock, Shares held	35,000,000	35,000,000
Treasury stock, at cost	$ 2,327	$ 2,327
Pepco Holdings [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger)	3,000,000	1,000,000

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

^[1]

$ (2,684)

$ (2,040)

(136)

(528)

^[1]

196

(116)

^[1],[2]

(644)

^[1]

$ 727

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(2,624)

(2,684)

^[1]

(2,040)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(28)

120

(12)

(31)

^[1]

(117)

^[1],[2]

(148)

^[1]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

(19)

(28)

^[1]

120

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(1)

^[1]

Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(2,640)

^[1]

(2,260)

(100)

(498)

^[1]

175

118

^[1],[2]

(380)

^[1]

Accumulated Translation Adjustment [Member]

(2,565)

(2,640)

^[1]

(2,260)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(19)

^[1]

(10)

(21)

(9)

(21)

(9)

^[1]

Accumulated Equity Investment [Member]

(40)

(19)

^[1]

(10)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

108

(3)

^[1]

(119)

^[1],[2]

(3)

(108)

^[1]

(3)

^[1]

108

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(36)

214

(32)

(14)

^[1]

(236)

^[1],[2]

(27)

(250)

^[1]

(299)

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(63)

(36)

^[1]

214

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(18)

114

(8)

(15)

^[1]

(117)

^[1],[2]

(3)

(132)

^[1]

Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

(21)

(18)

^[1]

114

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(1)

(1)

^[1]

Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(19)

^[1]

(10)

(21)

(9)

^[1]

(21)

(9)

^[1]

Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]

(40)

(19)

^[1]

(10)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

108

(3)

^[1]

(119)

^[1],[2]

(3)

(108)

^[1]

(3)

^[1]

108

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

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

$ 1

^[1]

$ 1

^[1]

[1]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[2]	See next tables for details about these reclassifications.

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

2 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 7,255

$ 6,912

$ 6,024

$ 7,237

$ 29,447

$ 27,429

$ 24,888

Sale of equity method investment

(1,079)

(610)

(896)

Prior service costs

(46)

455

460

Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net

(20)

289

3,330

2,486

2,773

(1,073)

(666)

(1,044)

Reclassification out of Accumulated Other Comprehensive Income [Member]

309

^[1]

629

638

693

993

522

^[2]

2,250

1,820

1,729

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

Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]

^[3]

(196)

116

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

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

^[3]

(2)

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

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(26)

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

^[3]

(2)

^[3]

(35)

195

^[3]

(78)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Related Derivative [Member]

^[3]

(21)

117

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

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member]

^[3]

195

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

Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member]

^[3]

(11)

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

Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net

^[3]

193

^[3]

198

^[3]

(79)

^[3]

119

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

$ 386

4,294

4,768

4,232

5,840

4,802

4,412

3,789

4,390

19,135

17,393

15,630

Sale of equity method investment

(425)

(2)

(60)

406

355

Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net

(20)

289

(502)

(207)

(615)

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

$ (42)

$ 154

$ 377

$ 398

$ 443

$ (91)

$ 771

$ 340

$ (185)

1,340

1,019

$ 1,060

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

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[3]

(5)

236

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

^[3]

(9)

195

^[3]

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Related Derivative [Member]

^[3]

(5)

117

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

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

^[3]

195

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member]

^[3]

(11)

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

Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain (Loss), Net

^[3]

193

^[3]

198

^[3]

(79)

Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[3]

119

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

Prior service costs

^[3],[4]

Actuarial gains/losses

^[3],[4]

(361)

^[3]

(287)

(193)

^[3]

112

Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member]

^[3]

$ (175)

(118)

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

Actuarial gains/losses

^[3],[5]

$ (239)

[1]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NEExNTZFREE4NkYwMUZCQUZDQTExMjI1RThCRDM3QzcM}
[3]	Amounts in parenthesis represent a decrease in net income.
[4]	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 17 — Retirement Benefits for additional details).
[5]	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.

Changes in Accumulated Other Comprehensive Income - Components of Accumulated Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Prior service costs	$ 30	$ 19	$ 0
Actuarial loss reclassified to periodic cost, taxes	(140)	(93)	(133)
Pension and non-pension postretirement benefit plan valuation adjustment, taxes	62	317	(430)
Change in unrealized gain (loss) on cash flow hedges, taxes	(6)	96	166
Change in unrealized gain (loss) on equity investments taxes	1	73	(71)
Other comprehensive income, income taxes	(53)	412	(468)
Exelon Generation Co L L C [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gain (loss) on cash flow hedges, taxes	2	84	262
Change in unrealized gain (loss) on equity investments taxes	1	73	(72)
Other comprehensive income, income taxes	$ 3	$ 157	$ 190

Commitments and Contingencies - Narrative (Details)

1 Months Ended

3 Months Ended

12 Months Ended

Jan. 31, 2013

USD ($)

Oct. 31, 2007

USD ($)

May 31, 2006

Principle_responsible_party

Sep. 30, 2015

USD ($)

Dec. 31, 2015

USD ($)

MGPSite

reactor

claimant

Open_claim

Customer

Dec. 31, 2014

USD ($)

Dec. 31, 1999

Principle_responsible_party

May 30, 2012

USD ($)

Dec. 31, 2003

Nuclear insurance liability limit per incident

$ 18,300,000.0

Cost surcharge to Price-Anderson Act nuclear incident assessment

5.00%

Asbestos liability reserve

$ 9,206,000,000

95,000,000

$ 100,000,000

Probable contingency (liability)

$ 21,000,000

Open asbestos liability claims | Open_claim

228

Asbestos liability reserve related to anticipated claims

$ 74,000,000

Rossville ash site [Member]

Nuclear Insurance Premiums [Member]

Area of property | a

^[1]

$ 3,060,000,000

Nuclear financial protection pool value

$ 375,000,000

United States licensed nuclear reactors total | reactor

103

Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses

$ 13,100,000,000.0

Cost surcharge to Price-Anderson Act nuclear incident assessment

12730000000.00%

Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident

$ 19,000,000

Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident

2,700,000,000

Total retrospective premium obligation under insurance from a nuclear industry mutual insurance company

365,000,000

Mutual Replacement Power Cost Insurance Maximum Retrospective Premium Obligation

3,200,000,000

Cost of spent nuclear fuel disposal per kWh of net nuclear generation

0.001

Net nuclear fuel disposal fees

136,000,000

49,000,000

Department of Energy SNF one-time fee applicable to nuclear generation

277,000,000

DOE SNF one-time fee with interest

$ 1,021,000,000

13-week Treasury Rate used to calculate DOE SNF one-time fee

0.112%

Environmental loss contingencies

$ 6,832,000,000

Consent decree penalty

$ 1,000,000

$ 12,000,000

$ 13,000,000

Payments for operating leases

$ 14,000,000

Open asbestos liability claims | Open_claim

300

Exelon Generation Co L L C [Member] | Cotter Corporation [Member]

Total cost of remediation to be shared by PRPs

$ 60,000,000

DOJ potential settlement

90,000,000

Exelon Generation Co L L C [Member] | Rossville ash site [Member]

Estimate of possible loss

9,000,000

Exelon Generation Co L L C [Member] | Equity Method Investments [Member]

Purchase obligations, due within two years

21,000,000

Unrecorded Unconditional Purchase Obligation, Due within Three Years

7,000,000

Unrecorded Unconditional Purchase Obligation, Due within Four Years

Unrecorded Unconditional Purchase Obligation

327,000,000

Unrecorded unconditional purchase obligation, due in next 12 months

299,000,000

Other unrecorded amounts

20,000,000

Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]

Nuclear insurance liability limit per incident

13,500,000,000.0

Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

^[2]

3,060,000,000

Mutual Property Insurance Distribution To Members

18,500,000

Midwest Generation, LLC [Member]

Percentage agreed to reimburse related parties

50.00%

Total number of MGP sites | MGPSite

$ 224,000,000

Sites approved for clean-up | MGPSite

Sites under study/remediation | MGPSite

Minimum number of customers ComEd can be held liable to for power interruption | Customer

30,000

Commonwealth Edison Co [Member] | Accrual For MGP Investigation And Remediation [Member]

Increase (decrease) in accrual for environmental loss contingencies

$ 50,000,000

Total number of MGP sites | MGPSite

$ 209,000,000

Sites approved for clean-up | MGPSite

Sites under study/remediation | MGPSite

Total number of MGP sites | MGPSite

$ 262,000,000

Sites under study/remediation | MGPSite

Maximum estimated clean-up costs for all potentially responsible parties

$ 1,700,000.0

Number of claimants | claimant

454

Baltimore Gas and Electric Company [Member] | Deferrable Interest Subordinated Debentures [Member]

Baltimore Gas and Electric Company [Member] | Accrual For MGP Investigation And Remediation [Member]

6.20%

Increase (decrease) in accrual for environmental loss contingencies

$ 1,000,000

Baltimore Gas and Electric Company [Member] | Sixty-Eighth Street Dump [Member]

Number of parties jointly and severally liable In environmental protection agency action | Principle_responsible_party

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

[1]

[2]

Nuclear insurance premiums — 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.

Commitments and Contingencies - Schedule of Government Agreement Settlements (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2015

Schedule of Government Agreements [Line Items]

Nontrade Receivables, Current

$ 82

$ 76

Nontrade Receivables, Noncurrent

Accounts Payable, Other, Current

(5)

Schedule of Government Agreements [Line Items]

Spent Nuclear Fuel Storage Reimbursement

945

Spent Nuclear Fuel Storage Reimbursement Net Co Owners

$ 804

Department of Energy [Member] | Exelon Generation Co L L C [Member]

Schedule of Government Agreements [Line Items]

Spent Nuclear Fuel Storage Reimbursement

^[1]

Spent Nuclear Fuel Storage Reimbursement Net Co Owners

^[1],[2]

$ 49

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NDZFNjY1NjNDNkE4N0FEQUQwMUMxMjI1RThCRDQ0RjkM}
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246MDBDNEZCMjM3MzFBMTJCOTZFMDExMjI1RThCRDA3MEYM}

Commitments and Contingencies - Schedule of Energy Supply Procurement, Curtailment Services, REC and AEC Purchase Commitments (Details)	12 Months Ended
	Dec. 31, 2015
Commonwealth Edison Co [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Term of contract	20 years

Commitments and Contingencies - Schedule of Commercial Commitments (Details)
$ in Millions

Dec. 31, 2015

USD ($)

Percentage ownership of common stock

$ 9,206

5,424

$ 3,694

100.00%

Financial Standby Letter of Credit [Member]

$ 1,583

^[1]

1,565

^[1]

^[1]

^[1]

^[1]

^[1]

^[1]

809

^[2]

Performance Guarantee [Member]

733

^[2]

^[2]

^[2]

^[2]

^[2]

^[2]

Energy Contract Guarantee [Member]

628

^[3]

^[2]

^[2]

^[2]

^[2]

^[2]

628

^[2]

3,126

^[4]

Estimated total assumed for commercial transaction obligations

3,126

^[4]

^[4]

^[4]

^[4]

^[4]

^[4]

3,100

Nuclear Insurance Premiums [Member]

Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

3,060

^[5]

^[5]

^[5]

^[5]

^[5]

^[5]

3,060

^[5]

Estimated net exposure for commercial transaction obligations

500

Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]

262

250

Baltimore Gas and Electric Company [Member] | Surety Bond [Member]

^[6]

^[6]

^[6]

^[6]

^[6]

^[6]

^[6]

Baltimore Gas and Electric Company [Member] | Performance Guarantee [Member]

^[7]

^[7]

^[7]

^[7]

^[7]

^[7]

^[7]

Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member]

250

^[8]

^[8]

^[8]

^[8]

^[8]

^[8]

250

^[8]

250

PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]

209

178

PECO Energy Co [Member] | Surety Bond [Member]

^[9]

^[9]

^[9]

^[9]

^[9]

^[9]

^[9]

PECO Energy Co [Member] | Performance Guarantee [Member]

^[10]

^[10]

^[10]

^[10]

^[10]

^[10]

^[10]

PECO Energy Co [Member] | Trust Preferred Securities [Member]

178

^[11]

^[11]

^[11]

^[11]

^[11]

^[11]

178

^[11]

178

Commonwealth Edison Co [Member] | Financial Standby Letter of Credit [Member]

224

200

Commonwealth Edison Co [Member] | Surety Bond [Member]

^[12]

^[12]

^[12]

^[12]

^[12]

^[12]

^[12]

Commonwealth Edison Co [Member] | Performance Guarantee [Member]

^[13]

^[13]

^[13]

^[13]

^[13]

^[13]

^[13]

Commonwealth Edison Co [Member] | Trust Preferred Securities [Member]

200

^[14]

^[14]

^[14]

^[14]

^[14]

^[14]

200

^[14]

200

Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]

6,832

3,709

3,060

1,503

^[15]

Exelon Generation Co L L C [Member] | Surety Bond [Member]

1,485

^[15]

^[15]

^[15]

^[15]

^[15]

^[15]

Exelon Generation Co L L C [Member] | Energy Contract Guarantee [Member]

737

692

1,532

Estimated total assumed for commercial transaction obligations

1,532

^[16]

^[16]

^[16]

^[16]

^[16]

^[16]

1,500

Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]

Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

3,060

^[17]

^[17]

^[17]

^[17]

^[17]

^[17]

3,060

^[17]

Estimated net exposure for commercial transaction obligations

$ 300

Commonwealth Edison Three [Member] | Commonwealth Edison Co [Member]

Percentage ownership of common stock

100.00%

PECO Trust III and IV [Member] | PECO Energy Co [Member]

Percentage ownership of common stock

100.00%

[1]	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[2]	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[3]	ncludes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.
[4]	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.1 billion of guarantees issued by Exelon and Generation on behalf of its Constellation businesses to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.5 billion at December 31, 2015, which represents the total amount Exelon could be required to fund based on December 31, 2015 market prices.
[5]	Nuclear insurance premiums—Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site 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.
[6]	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[7]	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[8]	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.
[9]	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[10]	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[11]	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
[12]	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[13]	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[14]	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.
[15]	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
[16]	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.5 billion of guarantees issued by Generation on behalf of its Constellation businesses to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.3 billion at December 31, 2015, which represents the total amount Generation could be required to fund based on December 31, 2015 market prices.
[17]	Nuclear insurance premiums — 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.

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) - Equity Method Investments [Member] - Exelon Generation Co L L C [Member] $ in Millions	Dec. 31, 2015 USD ($)
Guarantor Obligations [Line Items]
2015	$ 299
2016	21
2017	7
2018	0
Total	$ 327

Commitments and Contingencies - Schedule of Minimum Future Operating Lease Payments (Details)
$ in Millions

12 Months Ended

Dec. 31, 2015

USD ($)

Operating Leases Future Minimum Payments Due [Line Items]

$ 133

109

702

1,174

^[1]

Operating Leases Future Minimum Payments Due [Line Items]

^[2]

^[2]

^[2]

^[2]

^[2]

655

^[2]

Exelon Generation Co L L C [Member] | Baltimore Headquarters [Member]

956

^[1],[2]

Operating Leases Future Minimum Payments Due [Line Items]

271

Operating Leases Future Minimum Payments Due [Line Items]

^[3]

^[3]

^[3]

^[3]

^[3]

^[3]

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

^[3]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

^[3]

^[3]

^[3]

^[3]

^[3]

^[3]

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

^[3]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

^[3],[4]

^[3],[4]

^[3],[4]

^[3],[4]

^[3],[4]

^[3],[4]

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

$ 65

^[3],[4]

Operating Leases Future Minimum Payments Due [Line Items]

Term of lease

20 years

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

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

$ 1

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246RjY0REJFRDkzMzlGREY0NDZBNjExMjI1RThCRDI3MDcM}
[2]	The Generation column above includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2015. Generation’s total commitments under the lease agreement are $4 million, $10 million, $11 million, $13 million, $14 million, and $271 million related to years 2016, 2017, 2018, 2019, 2020 and thereafter, respectively.
[3]	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, and BGE’s annual obligation for these arrangements, included in each of the years 2016—2020, was $2 million, $3 million, and $1 million respectively.
[4]	Includes all future lease payments on a 99 year real estate lease that expires in 2106.

Commitments and Contingencies - Schedule of Future Rental Expense under Operating Leases (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 922

$ 865

$ 806

Operating Leases Future Minimum Payments Due [Line Items]

Long Term Contract For Purchase Of Electric Power Capacity

^[1]

851

806

744

798

755

694

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Supplemental Financial Information Tables [Line Items]

$ 32

$ 12

$ 11

[1]

Commitments and Contingencies - Schedule of Environmental Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	$ 369	$ 347
Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	301	277
Exelon Generation Co L L C [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	63	63
Exelon Generation Co L L C [Member] \| Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	0	0
Commonwealth Edison Co [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	266	238
Commonwealth Edison Co [Member] \| Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	264	235
PECO Energy Co [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	37	45
PECO Energy Co [Member] \| Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	35	42
Baltimore Gas and Electric Company [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	3	1
Baltimore Gas and Electric Company [Member] \| Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	$ 2	$ 0

Supplemental Financial Information - Summary of Taxes other than Income (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

^[1]

$ 474

$ 456

$ 449

407

396

302

201

200

159

118

102

185

1,200

1,154

1,095

Supplemental Financial Information Tables [Line Items]

^[1]

105

250

240

205

118

489

465

389

Supplemental Financial Information Tables [Line Items]

^[1]

236

238

241

296

293

299

Supplemental Financial Information Tables [Line Items]

^[1]

133

128

129

160

159

158

Supplemental Financial Information Tables [Line Items]

^[1]

119

114

112

Supplemental Financial Information Tables [Line Items]

$ 224

$ 221

$ 213

[1]

Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Gain (Loss) on Sale of Derivatives

^[1]

$ (26)

Payments of Debt Restructuring Costs

^[2]

(22)

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[3]

232

$ 216

$ 256

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[3]

156

159

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

(282)

180

406

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

(197)

134

146

Regulatory offset to decommissioning trust fund-related activities

^[4]

(358)

(546)

(63)

360

346

Interest income related to uncertain income tax positions

(46)

455

460

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[3]

232

216

256

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[3]

156

159

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

(282)

180

406

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

(197)

134

146

Regulatory offset to decommissioning trust fund-related activities

^[4]

(358)

(546)

(63)

360

346

(1)

Interest income related to uncertain income tax positions

(1)

(9)

(60)

406

355

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[3]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[3]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[4]

Interest income related to uncertain income tax positions

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[3]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[3]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[4]

(1)

Interest income related to uncertain income tax positions

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[3]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[3]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[4]

^[5]

Interest income related to uncertain income tax positions

(1)

Supplemental Financial Information Tables [Line Items]

$ 18

$ 17

[1]	In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
[2]	(e)See Note 14—Debt and Credit Agreements and 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.
[3]	Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning trust funds.
[4]	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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
[5]	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.

Supplemental Financial Information - Summary of Depreciation, Amortization, Accretion and Depletion (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 2,227

$ 2,080

$ 1,893

170

191

212

^[1]

1,116

1,073

921

Total depreciation, amortization, accretion and depletion

^[2]

398

345

275

3,987

3,868

3,779

Supplemental Financial Information Tables [Line Items]

1,007

922

813

^[1]

1,116

1,073

921

Total depreciation, amortization, accretion and depletion

^[2]

397

345

275

2,589

2,519

2,559

Supplemental Financial Information Tables [Line Items]

635

588

545

119

^[1]

Total depreciation, amortization, accretion and depletion

^[2]

707

687

669

Supplemental Financial Information Tables [Line Items]

240

227

219

^[1]

Total depreciation, amortization, accretion and depletion

^[2]

260

236

228

Supplemental Financial Information Tables [Line Items]

289

288

264

^[1]

Total depreciation, amortization, accretion and depletion

^[2]

366

371

348

Unamortized Energy Contracts [Member]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[3]

135

430

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Commonwealth Edison Company [Member]

^[3]

135

507

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Commonwealth Edison Co [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | PECO Energy Co [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Baltimore Gas and Electric Company [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Supplemental Cash Flow Information [Line Items]

^[3]

$ 0

[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]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 930,000,000

$ 940,000,000

$ 866,000,000

Pension and non-pension postretirement benefit costs

342,000,000

314,000,000

112,000,000

637,000,000

560,000,000

825,000,000

20,000,000

(10,000,000)

120,000,000

156,000,000

101,000,000

10,000,000

5,000,000

9,000,000

97,000,000

91,000,000

120,000,000

(82,000,000)

(132,000,000)

(169,000,000)

Amortization of regulatory asset related to debt costs

21,000,000

122,000,000

104,000,000

7,000,000

11,000,000

12,000,000

73,000,000

65,000,000

66,000,000

(17,000,000)

(23,000,000)

(34,000,000)

44,000,000

144,000,000

53,000,000

(271,000,000)

58,000,000

53,000,000

18,000,000

23,000,000

29,000,000

11,000,000

(2,000,000)

(53,000,000)

1,109,000,000

1,054,000,000

718,000,000

387,000,000

157,000,000

(128,000,000)

885,000,000

72,000,000

(128,000,000)

96,000,000

220,000,000

(38,000,000)

Noncash Purchase Accounting Adjustment

421,000,000

3,400,000,000

Fair value of net assets recorded upon CENG consolidation

(131,000,000)

Non Cash Licensing Agreement

8,322,000,000

8,568,000,000

7,270,000,000

^[1]

95,000,000

Antelope Valle [Member]

Supplemental Cash Flow Information [Line Items]

Nuclear Fuel Project [Member]

170,000,000

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

^[2]

57,000,000

Capital Project [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

77,000,000

Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

70,000,000

Supplemental Cash Flow Information [Line Items]

348,000,000

322,000,000

291,000,000

Pension and non-pension postretirement benefit costs

476,000,000

227,000,000

(18,000,000)

269,000,000

249,000,000

345,000,000

(8,000,000)

20,000,000

(10,000,000)

22,000,000

14,000,000

10,000,000

9,000,000

5,000,000

9,000,000

(82,000,000)

(132,000,000)

(169,000,000)

Amortization of regulatory asset related to debt costs

21,000,000

122,000,000

104,000,000

(17,000,000)

(23,000,000)

(34,000,000)

44,000,000

15,000,000

12,000,000

10,000,000

23,000,000

29,000,000

6,000,000

5,000,000

268,000,000

346,000,000

270,000,000

207,000,000

(57,000,000)

85,000,000

885,000,000

72,000,000

(128,000,000)

82,000,000

(61,000,000)

(107,000,000)

Noncash Purchase Accounting Adjustment

63,000,000

3,400,000,000

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

4,688,000,000

4,943,000,000

3,960,000,000

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

^[2]

57,000,000

Exelon Generation Co L L C [Member] | Capital Project [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

77,000,000

Exelon Generation Co L L C [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

70,000,000

Supplemental Cash Flow Information [Line Items]

308,000,000

292,000,000

283,000,000

Pension and non-pension postretirement benefit costs

(265,000,000)

(6,000,000)

33,000,000

206,000,000

162,000,000

308,000,000

53,000,000

26,000,000

(15,000,000)

1,000,000

Amortization of regulatory asset related to debt costs

5,000,000

8,000,000

9,000,000

144,000,000

53,000,000

(271,000,000)

4,000,000

1,000,000

3,000,000

2,000,000

(4,000,000)

416,000,000

255,000,000

28,000,000

(69,000,000)

(1,000,000)

(171,000,000)

34,000,000

78,000,000

(8,000,000)

Issuance of equity units

202,000,000

273,000,000

176,000,000

Commonwealth Edison Co [Member] | Indemnification Agreement [Member]

1,372,000,000

1,263,000,000

1,211,000,000

Supplemental Cash Flow Information [Line Items]

7,000,000

5,000,000

Supplemental Cash Flow Information [Line Items]

94,000,000

95,000,000

Pension and non-pension postretirement benefit costs

64,000,000

85,000,000

70,000,000

39,000,000

36,000,000

43,000,000

30,000,000

52,000,000

61,000,000

Amortization of regulatory asset related to debt costs

2,000,000

3,000,000

2,000,000

(3,000,000)

(1,000,000)

70,000,000

92,000,000

108,000,000

4,000,000

21,000,000

(4,000,000)

(13,000,000)

13,000,000

Issuance of equity units

16,000,000

24,000,000

27,000,000

PECO Energy Co [Member] | Indemnification Agreement [Member]

684,000,000

767,000,000

647,000,000

Supplemental Cash Flow Information [Line Items]

Supplemental Cash Flow Information [Line Items]

120,000,000

111,000,000

130,000,000

Pension and non-pension postretirement benefit costs

73,000,000

(21,000,000)

42,000,000

65,000,000

64,000,000

56,000,000

15,000,000

64,000,000

44,000,000

^[3]

^[4]

Amortization of regulatory asset related to debt costs

^[5]

^[6]

73,000,000

65,000,000

66,000,000

^[7]

^[8]

2,000,000

(18,000,000)

(15,000,000)

137,000,000

180,000,000

153,000,000

173,000,000

158,000,000

72,000,000

4,000,000

Noncash Purchase Accounting Adjustment

(9,000,000)

25,000,000

48,000,000

Issuance of equity units

7,000,000

Baltimore Gas and Electric Company [Member] | Indemnification Agreement [Member]

565,000,000

614,000,000

551,000,000

Supplemental Cash Flow Information [Line Items]

Exelon Consolidations [Member]

^[9]

Supplemental Cash Flow Information [Line Items]

Constellation Energy Group Acquisition [Member]

$ (7,000,000)

$ 22,000,000

Supplemental Cash Flow Information [Line Items]

Constellation Energy Group Acquisition [Member] | Exelon Generation Co L L C [Member]

63,000,000

Supplemental Cash Flow Information [Line Items]

Constellation Energy Group Acquisition [Member] | Commonwealth Edison Co [Member]

63,000,000

Supplemental Cash Flow Information [Line Items]

Constellation Energy Group Acquisition [Member] | PECO Energy Co [Member]

Supplemental Cash Flow Information [Line Items]

Constellation Energy Group Acquisition [Member] | Baltimore Gas and Electric Company [Member]

Supplemental Cash Flow Information [Line Items]

Supplemental Financial Information Tables [Line Items]

$ 0

[1]	(f)Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See Note 14 — Debt and Credit Agreements for additional information.
[2]	(d)Relates to the nuclear fuel procurement contract for the purchase of fixed quantities of converted uranium, which was delivered to Generation in 2015. Generation is required to make payments starting September 28, 2018, with the final payment being due no later than September 30, 2020.
[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 16 — Asset Retirement Obligations 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 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
[5]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[6]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[7]	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 3 — Regulatory Matters for more information.
[8]	(d)Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.
[9]	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 20 — Stock-Based Compensation Plans for additional information.

Supplemental Financial Information - Narrative (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Gain (Loss) on Sale of Derivatives

^[1]

$ (26)

Amount included in capital expenditures

$ 74

Smart Grid Grant Reimbursements

Supplemental Financial Information Tables [Line Items]

Amount included in capital expenditures

Smart Grid Grant Reimbursements

Supplemental Financial Information Tables [Line Items]

Amount included in capital expenditures

Smart Grid Grant Reimbursements

$ 58

Reclassification out of Accumulated Other Comprehensive Income [Member]

Supplemental Financial Information Tables [Line Items]

Gain (Loss) on Sale of Derivatives

$ 26

[1]

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

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Mar. 31, 2015

Supplemental Balance Sheet Information [Line Items]

$ 96

$ 220

$ (38)

Net investment in leases (b)

112

352

361

639

544

^[1]

1,014

832

293

305

$ 65

915

240

133

113

^[2]

Supplemental Balance Sheet Information [Line Items]

2,376

1,539

Antelope Valle [Member]

170

Financing Trusts [Member]

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

^[3]

Bloom Energy [Member]

Supplemental Balance Sheet Information [Line Items]

Net Power [Member]

Other Equity Method Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

Sunnyside [Member]

Trust for Benefit of Employees [Member]

Supplemental Balance Sheet Information [Line Items]

Other Investments [Member]

^[4]

Supplemental Balance Sheet Information [Line Items]

Available-for-sale Securities, Noncurrent

Cost Method Investments

Supplemental Balance Sheet Information [Line Items]

(61)

(107)

Net investment in leases (b)

^[5]

210

104

^[1]

547

447

186

248

114

^[2]

Exelon Generation Co L L C [Member] | Financing Trusts [Member]

935

886

Supplemental Balance Sheet Information [Line Items]

Exelon Generation Co L L C [Member] | Bloom Energy [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

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

Supplemental Balance Sheet Information [Line Items]

Exelon Generation Co L L C [Member] | Other Equity Method Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Exelon Generation Co L L C [Member] | Sunnyside [Member]

Supplemental Balance Sheet Information [Line Items]

Exelon Generation Co L L C [Member] | Trust for Benefit of Employees [Member]

Supplemental Balance Sheet Information [Line Items]

Exelon Generation Co L L C [Member] | Other Investments [Member]

^[4]

Supplemental Balance Sheet Information [Line Items]

Available-for-sale Securities, Noncurrent

Cost Method Investments

Supplemental Balance Sheet Information [Line Items]

(8)

^[1]

183

153

443

102

Commonwealth Edison Co [Member] | Financing Trusts [Member]

706

331

Supplemental Balance Sheet Information [Line Items]

^[3]

Supplemental Balance Sheet Information [Line Items]

(13)

^[1]

PECO Energy Co [Member] | Financing Trusts [Member]

109

Supplemental Balance Sheet Information [Line Items]

PECO Energy Co [Member] | Trust for Benefit of Employees [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

^[4]

Supplemental Balance Sheet Information [Line Items]

(9)

$ 48

^[1]

Baltimore Gas and Electric Company [Member] | Financing Trusts [Member]

110

131

Supplemental Balance Sheet Information [Line Items]

Baltimore Gas and Electric Company [Member] | Trust for Benefit of Employees [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Exelon Consolidations [Member]

^[4]

Supplemental Balance Sheet Information [Line Items]

Net investment in leases (b)

^[5]

$ 358

$ 367

[1]	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
[2]	Includes $19 million for amounts accrued related to Antelope Valley as of December 31, 2014.
[3]	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.
[4]	(c)The Registrants’ investments in these marketable securities are recorded at fair market value.
[5]	Represents direct financing lease investments.

Segment Information - Narrative (Details)	12 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2015 Reportable_segment
Segment Reporting Information [Line Items]
Number of reportable segments	9
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	6

Segment Information - Analysis and Reconciliation to Consolidated Financial Statements (Details) - USD ($)
$ in Millions

2 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 7,255

$ 6,912

$ 6,024

$ 7,237

$ 29,447

$ 27,429

$ 24,888

Other Alternative Energy Sales Revenue

15,200

13,773

12,496

154

9,876

9,467

9,365

1,176

1,325

1,246

757

2,433

2,704

1,721

2,450

2,314

2,153

Equity in earnings (losses) of unconsolidated affiliates

^[1]

25,056

25,039

21,242

(7)

(20)

Income (loss) from continuing operations before income taxes

1,033

1,065

1,356

3,330

2,486

2,773

1,073

666

1,044

309

^[2]

629

638

693

993

522

^[3]

2,250

1,820

1,729

^[4]

$ 86,416

95,384

86,416

95,384

86,416

^[5]

474

456

449

7,624

6,077

5,395

PECO Energy Co Affiliate [Member]

Generation Midwest [Member]

^[6]

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

4,710

4,475

4,270

^[7]

15,944

14,533

13,862

^[7]

^[7]

^[7]

758

155

^[7]

2,433

2,705

1,721

^[7]

1,054

967

856

Equity in earnings (losses) of unconsolidated affiliates

^[1],[7]

16,872

16,923

13,976

^[7]

(8)

(20)

Income (loss) from continuing operations before income taxes

^[7]

365

356

357

^[7]

1,850

1,226

1,675

^[7]

502

207

615

^[7]

1,340

1,019

1,060

^[7]

44,951

46,529

44,951

46,529

44,951

^[7]

3,841

3,012

2,752

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

^[7]

4,905

4,564

4,464

707

687

669

Equity in earnings (losses) of unconsolidated affiliates

^[1]

3,889

3,586

3,510

Income (loss) from continuing operations before income taxes

332

321

579

706

676

401

280

268

152

426

408

249

25,358

26,532

25,358

26,532

25,358

2,398

1,689

1,433

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

2,486

2,448

2,500

546

646

600

260

236

228

Equity in earnings (losses) of unconsolidated affiliates

^[1]

2,404

2,522

2,434

Income (loss) from continuing operations before income taxes

114

113

115

521

466

557

143

114

162

378

352

395

9,860

10,367

9,860

10,367

9,860

601

661

537

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

^[8]

^[8]

2,490

2,460

2,405

^[8]

645

705

660

^[8]

^[8]

^[8]

366

371

348

Equity in earnings (losses) of unconsolidated affiliates

^[1],[8]

2,578

2,726

2,616

^[8]

Income (loss) from continuing operations before income taxes

^[8]

106

122

^[8]

477

351

344

^[8]

189

140

134

^[8]

288

211

210

^[8]

8,056

8,295

8,056

8,295

8,056

^[8]

719

620

587

Operating Segments [Member] | Generation Midwest [Member]

^[8]

Other Segments [Member] | Corporate and Other [Member]

^[9]

4,712

4,488

4,298

^[10]

^[10]

^[10]

^[10]

^[10]

^[10]

Equity in earnings (losses) of unconsolidated affiliates

^[1],[10]

1,444

1,353

1,324

^[10]

Income (loss) from continuing operations before income taxes

^[10]

123

169

183

^[10]

(219)

(227)

(191)

^[10]

(41)

(63)

(20)

^[10]

(177)

(164)

(171)

^[10]

9,711

15,389

9,711

15,389

9,711

^[10]

Intersegment Eliminations [Member]

^[10]

1,372

1,285

1,241

(744)

(760)

(1,366)

(5)

(4)

(15)

(26)

(14)

(1)

(1)

^[11]

Equity in earnings (losses) of unconsolidated affiliates

^[1]

(2,131)

(2,071)

(2,618)

Income (loss) from continuing operations before income taxes

(5)

(6)

(13)

(5)

(6)

(14)

(11,520)

(11,728)

(11,520)

(11,728)

(11,520)

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

(1,367)

(1,279)

(1,227)

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

745

762

^[7],[11]

1,367

^[7],[11]

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

^[11]

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

^[12]

^[11]

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

^[13]

^[8],[11]

Intersegment Eliminations [Member] | Generation Midwest [Member]

^[10],[11]

1,367

1,280

1,237

Intersegment Eliminations [Member] | Segment Elimination [Member]

(2)

(13)

(28)

^[11]

(2,127)

(2,067)

(2,607)

386

4,294

4,768

4,232

5,840

4,802

4,412

3,789

4,390

19,135

17,393

15,630

Equity in earnings (losses) of unconsolidated affiliates

749

779

1,423

(8)

Income (loss) from continuing operations before income taxes

1,850

1,226

1,675

502

207

615

(42)

154

377

398

443

(91)

771

340

(185)

1,340

1,019

1,060

^[14]

44,951

46,529

44,951

46,529

44,951

^[5]

105

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

3,841

3,012

2,752

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

^[15]

224

198

405

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

^[16]

502

387

455

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

^[17]

176

506

^[17]

1,196

1,376

1,148

1,185

1,079

1,222

1,128

1,134

4,905

4,564

4,464

280

268

152

149

126

111

426

408

249

25,358

26,532

25,358

26,532

25,358

^[5]

236

238

241

2,398

1,689

1,433

645

740

661

985

750

693

656

993

3,032

3,094

3,100

2,485

2,446

2,499

545

646

600

Income (loss) from continuing operations before income taxes

521

466

557

143

114

162

139

378

352

395

9,860

10,367

9,860

10,367

9,860

^[5]

133

128

129

601

661

537

746

725

628

1,036

761

697

653

1,054

3,135

3,165

3,065

2,490

2,460

2,405

631

680

647

Income (loss) from continuing operations before income taxes

477

351

344

189

140

134

$ 51

$ 44

$ 106

$ 46

$ 16

$ 85

288

211

210

^[18]

$ 8,056

$ 8,295

$ 8,056

8,295

8,056

^[5]

$ 719

$ 620

$ 587

[1]	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.
[2]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NEExNTZFREE4NkYwMUZCQUZDQTExMjI1RThCRDM3QzcM}
[4]	Exelon’s consolidated assets include $8,268 million and $8,159 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,264 million and $2,728 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[5]	Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[6]	The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.
[7]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended December 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $224 million and sales to BGE of $502 million in the Mid-Atlantic region, and sales to ComEd of $18 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 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.
[8]	(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[9]	(a)On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, beginning on April 1, 2014, CENG's revenues are included on a fully consolidated basis.
[10]	(c)For the years ended December 31, 2015, 2014 and 2013, utility taxes of $105 million, $89 million and $79 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $236 million, $238 million and $241 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $133 million, $128 million and $129 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2015, 2014 and 2013, utility taxes of $85 million, $86 million and $82 million are included in revenues and expenses for BGE, respectively.
[11]	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.
[12]	PECO provides energy to Generation for Generation’s own use.
[13]	BGE provides energy to Generation for Generation’s own use.
[14]	Generation’s consolidated assets include $8,235 million and $8,118 million at December 31, 2015 and 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,135 million and $2,512 million at December 31, 2015 and 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[15]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
[16]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[17]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
[18]	BGE’s consolidated assets include $26 million and $24 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $122 million and $197 million at December 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

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

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 7,255

$ 6,912

$ 6,024

$ 7,237

$ 29,447

$ 27,429

$ 24,888

Amortization of intangible assets related to commodity contracts

289

767

Net mark-to market gains (losses)

357

(693)

507

Generation Mid Atlantic [Member]

Generation Midwest [Member]

5,900

5,259

5,204

Generation New England [Member]

4,710

4,475

4,270

Generation New York [Member]

2,212

1,422

1,237

Generation ERCOT [Member]

985

843

714

Generation Other Regions [Member]

857

935

1,216

Generation Reportable Segments Total [Member]

^[1]

1,102

1,309

968

Generation All Other Segments [Member]

15,766

14,243

13,609

Net mark-to market gains (losses)

^[2]

3,369

3,150

2,021

257

(591)

504

Generation Total Consolidated Group [Member]

Scenario, Adjustment [Member] | Generation Reportable Segments Total [Member]

19,135

17,393

15,630

Scenario, Adjustment [Member] | Generation All Other Segments [Member]

(284)

(252)

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

284

252

Operating Segments [Member] | Generation Midwest [Member]

^[3]

5,974

5,414

5,261

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

^[3]

4,712

4,488

4,298

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

^[3]

2,217

1,468

1,279

Operating Segments [Member] | Generation ERCOT [Member]

^[3]

996

846

717

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

^[3]

863

938

1,223

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

^[1],[3]

1,182

1,379

1,084

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

^[3]

15,944

14,533

13,862

Net mark-to market gains (losses)

^[2],[3]

3,191

2,860

1,768

203

(174)

220

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

Operating Segments [Member] | Scenario, Adjustment [Member] | Generation Reportable Segments Total [Member]

^[3]

19,135

17,393

15,630

Operating Segments [Member] | Scenario, Adjustment [Member] | Generation All Other Segments [Member]

284

252

Intersegment Eliminations [Member]

(284)

(252)

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

^[4]

Intersegment Eliminations [Member] | Generation Midwest [Member]

(74)

(155)

(57)

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

(2)

(13)

(28)

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

(5)

(46)

(42)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

(11)

(3)

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

(6)

(3)

(7)

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

^[1]

(80)

(70)

(116)

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

(178)

(290)

(253)

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

^[2]

178

290

253

$ 0

[1]	(b)Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[2]	(c)Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $7 million increase to revenues, a $289 million decrease to revenues, and a $767 million decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2015, 2014, and 2013, respectively, unrealized mark-to-market gains of $203 million, losses of $174 million, and gains of $220 million for the years ended December 31, 2015, 2014, and 2013, respectively, and elimination of intersegment revenues.
[3]	(a)On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, beginning on April 1, 2014, CENG's revenues are included on a fully consolidated basis.
[4]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Related Party Transactions - Related Party Transactions included in Consolidated Income Statement (Details) - USD ($)
$ in Millions

2 Months Ended

3 Months Ended

12 Months Ended

Apr. 01, 2014

Dec. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 9

$ 23

$ 70

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 7,255

$ 6,912

$ 6,024

$ 7,237

29,447

27,429

24,888

531

1,256

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(20)

(7)

(20)

$ 1,105

1,065

1,249

Required purchases of power from CENG's nuclear plants not sold to third parties

85.00%

Purchase of nuclear output of CENG

50.01%

PECO Energy Co Affiliate [Member]

49.99%

Constellation Energy Nuclear Group Llc Affiliate [Member]

^[1]

$ 1

^[2]

^[3]

282

992

Keystone Fuels LLC Affiliate [Member]

Conemaugh Fuels LLC Affiliate [Member]

^[4]

138

144

SafeHarborWaterPowerCorp [Member]

^[4]

PECO Trust Three Affiliate [Member]

^[4]

PECO Trust Four Affiliate [Member]

BGE Capital Trust II [Member]

CENG Equity Investment Income Affiliate [Member]

^[5]

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

^[6]

(19)

^[6]

Other Affiliate [Member]

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(1)

Qualifying Facilities And Domestic Power Projects Affiliate [Member]

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(8)

$ 113

113

749

779

1,423

386

4,294

4,768

4,232

5,840

4,802

4,412

3,789

4,390

19,135

17,393

15,630

557

1,270

620

623

574

Income (Loss) from Equity Method Investments, Net of Dividends or Distributions

(20)

(8)

Cash distribution paid to member

2,474

645

625

Contribution from member

Required purchases of power from CENG's nuclear plants not sold to third parties

85.00%

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

49.99%

^[7]

^[7]

176

506

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

^[8]

^[9]

^[9]

224

198

405

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

^[8]

^[10]

^[10]

502

387

455

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member]

^[11]

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

^[12]

282

992

^[13]

614

618

571

Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]

^[14]

Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member]

Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member]

^[15]

138

144

Exelon Generation Co L L C [Member] | SafeHarborWaterPowerCorp [Member]

^[15]

Exelon Generation Co L L C [Member] | CENG Equity Investment Income Affiliate [Member]

Exelon Generation Co L L C [Member] | Other Affiliate [Member]

^[16]

(19)

Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member]

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

(8)

(1)

(8)

199

2,571

2,172

2,571

2,172

2,571

1,196

1,376

1,148

1,185

1,079

1,222

1,128

1,134

4,905

4,564

4,464

195

166

157

Non-cash contribution to equity

299

307

220

202

273

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

202

273

176

^[17]

2,389

2,172

2,389

2,172

2,389

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

^[18]

176

512

^[14]

195

166

157

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

^[14]

103

Commonwealth Edison Co [Member] | Other Affiliate [Member]

^[19]

188

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

^[19]

182

746

725

628

1,036

761

697

653

1,054

3,135

3,165

3,065

118

103

158

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

^[20]

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

^[21]

498

382

452

^[22]

118

103

Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]

^[22]

490

405

490

405

490

645

$ 740

$ 661

$ 985

750

$ 693

$ 656

$ 993

3,032

3,094

3,100

110

101

279

320

332

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[23]

490

405

490

405

490

^[24]

^[25]

220

194

392

PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]

PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

$ 1

$ 0

$ 1

^[26]

107

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

^[26]

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

Total payables to affiliates (current)

$ 6

[1]	The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.
[2]	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[3]	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA) not sold to third parties. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[4]	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
[5]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246ODNGMzQxQTRCMURCRDhFQkMxOEYxMjI1RThCRDNERDEM}
[6]	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC
[7]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
[8]	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
[9]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
[10]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[11]	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation 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 part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[12]	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA) not sold to third parties. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[13]	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[14]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[15]	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
[16]	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[17]	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.
[18]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments for additional information.
[19]	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.
[20]	BGE provides energy to Generation for Generation’s own use.
[21]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[22]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[23]	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.
[24]	PECO provides energy to Generation for Generation’s own use.
[25]	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.
[26]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Related Party Transactions - Related Party Transactions included in Consolidated Balance Sheet (Details) - USD ($)
$ in Millions

12 Months Ended

Apr. 01, 2014

Dec. 31, 2015

Dec. 31, 2014

$ (8)

Required purchases of power from CENG's nuclear plants not sold to third parties

$ 641

641

85.00%

Purchase of nuclear output of CENG

50.01%

49.99%

$ 8

205

PECO Trust Three Affiliate [Member]

PECO Trust Four Affiliate [Member]

BGE Capital Trust II [Member]

103

252

Total payables to affiliates (current)

113

(556)

Required purchases of power from CENG's nuclear plants not sold to third parties

2,577

2,880

85.00%

49.99%

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

104

107

^[1]

^[2]

2,172

2,389

Exelon Generation Co L L C [Member] | Other Affiliate [Member]

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

^[3]

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

^[2]

405

490

Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]

^[4]

Total payables to affiliates (current)

(1,252)

(556)

Long Term Debt To Affiliate

933

943

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

^[5]

^[6]

^[6]

Prepaid voluntary employee beneficiary association trust

^[7]

Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]

252

Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]

^[8]

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

^[7]

^[9]

405

490

Prepaid voluntary employee beneficiary association trust

184

^[10]

PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]

103

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[11]

405

490

PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]

^[12]

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

^[13]

199

Prepaid voluntary employee beneficiary association trust

2,172

2,571

^[14]

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

205

Commonwealth Edison Co [Member] | Voluntary Employee Beneficiary Association Trust [Member]

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

Commonwealth Edison Co [Member] | Other Affiliate [Member]

^[15]

188

Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member]

^[15]

182

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[16]

2,172

2,389

Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]

^[17]

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

Selected Quarterly Financial Information [Line Items]

^[18]

$ 39

$ 32

[1]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
[2]	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 16—Asset Retirement Obligations
[3]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
[4]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[5]	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.
[6]	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[7]	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
[8]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[9]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[10]	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.
[11]	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.
[12]	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.
[13]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[14]	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
[15]	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.
[16]	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.
[17]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments for additional information.
[18]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Quarterly Data (Unaudited) - Quarterly Operating Results (Details) - USD ($)
$ in Millions

2 Months Ended

3 Months Ended

12 Months Ended

Dec. 31, 2014

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 7,255

$ 6,912

$ 6,024

$ 7,237

$ 29,447

$ 27,429

$ 24,888

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

707

309

^[1]

629

638

693

993

522

^[2]

2,250

1,820

1,729

Reclassifications to Operating Income (Loss)

(1)

Unrecognized Tax Benefits, Interest on Income Taxes Accrued

265

Selected Quarterly Financial Information [Line Items]

$ 386

4,294

4,768

4,232

5,840

4,802

4,412

3,789

4,390

19,135

17,393

15,630

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

230

(105)

$ (42)

154

377

398

443

(91)

771

340

(185)

1,340

1,019

1,060

Reclassifications to Operating Income (Loss)

(1)

Selected Quarterly Financial Information [Line Items]

1,196

1,376

1,148

1,185

1,079

1,222

1,128

1,134

4,905

4,564

4,464

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

217

327

^[3]

243

^[3]

230

196

287

258

238

149

126

111

426

408

249

Reclassifications to Operating Income (Loss)

Unrecognized Tax Benefits, Interest on Income Taxes Accrued

172

Selected Quarterly Financial Information [Line Items]

645

740

661

985

750

693

656

993

3,032

3,094

3,100

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

128

154

124

223

156

133

134

149

139

378

352

395

Selected Quarterly Financial Information [Line Items]

746

725

628

1,036

761

697

653

1,054

3,135

3,165

3,065

Net Income (Loss), Including Portion Attributable to Noncontrolling Interest

144

110

204

113

102

169

$ 74

$ 51

$ 44

$ 106

$ 52

$ 46

$ 16

$ 85

$ 288

$ 211

$ 210

[1]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NEExNTZFREE4NkYwMUZCQUZDQTExMjI1RThCRDM3QzcM}
[3]	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income.

Quarterly Data (Unaudited) - Quarterly Per Share Information (Details) - $ / shares shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Abstract]
Weighted average common shares outstanding—basic	921	913	863	862	861	861	860	858	890	860	856
Earnings Per Share, Basic	$ 0.34	$ 0.69	$ 0.74	$ 0.80	$ 0.02	$ 1.15	$ 0.61	$ 0.10
Weighted average common shares outstanding—diluted	924	915	866	867	868	863	864	861	893	864	860
Earnings Per Share, Diluted	$ 0.33	$ 0.69	$ 0.74	$ 0.80	$ 0.02	$ 1.15	$ 0.60	$ 0.10	$ 2.54	$ 1.88	$ 2.00

The amount of net income (loss) for the period per each share of common stock or unit outstanding during the reporting period.

Quarterly Data (Unaudited) - Quarterly Composite Common Stock Prices and Dividends (Details) - USD ($)	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014
Quarterly Financial Data [Abstract]
High price	$ 31.37	$ 34.44	$ 34.98	$ 38.25	$ 38.93	$ 36.26	$ 37.73	$ 33.94
Low price	$ 25.09	$ 28.41	$ 31.28	$ 31.71	$ 33.07	$ 30.66	$ 33.11	$ 26.45
Close	$ 27.77	$ 29.7	$ 31.42	$ 33.61	$ 37.08	$ 34.09	$ 36.48	$ 33.56
Dividends	$ 0.31	$ 0.31	$ 0.31	$ 0.31	$ 0.31	$ 0.31	$ 0.31	$ 0.31

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Operations and Other Comprehensive Income (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

^[1]

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

^[2]

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Operating Expenses [Abstract]

$ 8,322

$ 8,568

$ 7,270

25,056

25,039

21,242

4,409

3,096

3,669

Equity in (losses) earnings of unconsolidated affiliates

(992)

(1,024)

(1,315)

(20)

(46)

455

460

(1,079)

(610)

(896)

3,330

2,486

2,773

1,073

666

1,044

Pension and non-pension postretirement benefit plans:

$ 309

$ 629

$ 638

$ 693

$ 18

$ 993

$ 522

$ 90

2,250

1,820

1,729

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

Actuarial loss reclassified to periodic cost, net of tax

220

147

208

Pension and non-pension postretirement benefit plans valuation adjustment, net of tax

(99)

(497)

669

Unrealized gain (loss) on cash flow hedges, net of taxes

(148)

(248)

Unrealized gain (loss) on marketable securities, net of taxes

Unrealized gain (loss) on equity investments, net of taxes

(3)

106

Unrealized gain (loss) on foreign currency translation, net of taxes

(21)

(9)

(10)

(116)

(644)

^[3]

727

2,310

1,176

2,456

Operating Expenses [Abstract]

(47)

(50)

(55)

Equity in (losses) earnings of unconsolidated affiliates

(168)

(237)

(116)

2,461

1,779

1,903

Interest income from affiliates, net

(43)

(2)

(78)

2,293

1,593

1,745

2,246

1,543

1,690

(23)

(80)

(29)

Pension and non-pension postretirement benefit plans:

2,269

1,623

1,719

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

Actuarial loss reclassified to periodic cost, net of tax

220

147

208

Transition obligation reclassified to periodic cost, net of tax

Pension and non-pension postretirement benefit plans valuation adjustment, net of tax

(99)

(497)

669

Unrealized gain (loss) on cash flow hedges, net of taxes

(148)

(248)

Unrealized gain (loss) on marketable securities, net of taxes

Unrealized gain (loss) on equity investments, net of taxes

(3)

106

Unrealized gain (loss) on foreign currency translation, net of taxes

(21)

(9)

(10)

(644)

727

$ 2,329

$ 979

$ 2,446

[1]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246NEExNTZFREE4NkYwMUZCQUZDQTExMjI1RThCRDM3QzcM}
[3]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Cash Flows (Details) - USD ($) $ in Millions		12 Months Ended
	Feb. 26, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net cash flows provided by operating activities		$ 7,616	$ 4,457	$ 6,343
Cash flows from investing activities
Proceeds from termination of direct financing lease investment	$ 335	0	335	0
Capital expenditures		(7,624)	(6,077)	(5,395)
Cash and restricted cash acquired from Constellation		0	140	0
Change in restricted cash		66	(104)	(43)
Other investing activities		(119)	(88)	112
Net cash flows used in investing activities		(7,822)	(4,599)	(5,394)
Cash flows from financing activities
Changes in short-term borrowings		80	122	332
Issuance of long-term debt		6,709	3,463	2,055
Retirement of long-term debt		(2,687)	(1,545)	(1,589)
Dividends paid on common stock		(1,105)	(1,065)	(1,249)
Proceeds from employee stock plans		32	35	47
Other financing activities		(67)	(178)	(119)
Net cash flows provided by (used in) financing activities		4,830	411	(826)
Increase in cash and cash equivalents		4,624	269	123
Cash and cash equivalents at beginning of period		1,878	1,609	1,486
Cash and cash equivalents at end of period		6,502	1,878	1,609
Exelon Corporate [Member]
Net cash flows provided by operating activities		3,071	806	1,053
Cash flows from investing activities
Proceeds from termination of direct financing lease investment		0	335	0
Changes in Exelon intercompany money pool		(1,217)	(83)	(60)
Note receivable from affiliates		550	0	484
Capital expenditures		0	1	0
Change in restricted cash		0	0	38
Investment in affiliates		(212)	(70)	(38)
Other investing activities		(55)	(126)	15
Net cash flows used in investing activities		(934)	57	439
Cash flows from financing activities
Changes in short-term borrowings		0	0	10
Issuance of long-term debt		4,200	1,150	0
Retirement of long-term debt		(2,263)	(23)	(450)
Dividends paid on common stock		(1,105)	(1,065)	(1,249)
Proceeds from employee stock plans		32	35	47
Other financing activities		(58)	(84)	(6)
Net cash flows provided by (used in) financing activities		2,674	13	(1,648)
Increase in cash and cash equivalents		4,811	876	(156)
Cash and cash equivalents at beginning of period		879	3	159
Cash and cash equivalents at end of period		$ 5,690	$ 879	$ 3

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet (Details) - USD ($)
$ in Millions

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

$ 6,502

$ 1,878

$ 1,609

$ 1,486

912

1,227

759

847

748

865

15,334

11,853

57,439

52,170

6,065

6,076

1,445

923

22,611

22,393

^[1]

95,384

86,416

Short-term Debt

533

460

1,500

1,802

2,883

3,048

100

238

2,376

1,539

369

310

842

931

9,118

8,762

23,645

19,212

4,201

4,550

3,385

3,366

1,618

1,742

1,491

2,147

34,658

33,668

^[1]

68,062

62,283

Treasury stock, at cost (35 shares at December 31, 2015 and 2014, respectively)

18,676

16,709

(2,327)

12,068

10,910

(2,624)

(2,684)

^[2]

(2,040)

^[2]

BGE preference stock not subject to mandatory redemption

25,793

22,608

193

95,384

86,416

5,690

879

$ 3

$ 159

272

209

1,478

818

241

254

7,706

2,206

3,072

3,186

Receivable from affiliates

26,119

26,670

Deferred income taxes

2,036

2,147

933

943

404

149

32,672

33,095

40,431

35,355

Short-term Debt

188

1,409

440

Pension and Other Postretirement Defined Benefit Plans, Current Liabilities

809

1,562

6,017

2,818

Payables to affiliates

182

7,520

7,638

Deferred income taxes

134

122

398

7,807

8,182

Commitments and Contingencies

14,633

12,744

Treasury stock, at cost (35 shares at December 31, 2015 and 2014, respectively)

18,678

16,709

(2,327)

12,068

10,910

(2,624)

(2,684)

BGE preference stock not subject to mandatory redemption

25,795

22,608

$ 40,431

$ 35,355

[1]

Exelon’s consolidated assets include $8,268 million and $8,159 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,264 million and $2,728 million at December 31, 2015 and December 31, 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.

[2]

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

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet - Phantom (Details) - $ / shares	Dec. 31, 2015	Dec. 31, 2014
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	919,924,742	859,833,343
Treasury Stock, Shares held	35,000,000	35,000,000
Exelon Corporate [Member]
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	860,000,000	857,000,000
Treasury Stock, Shares held	35,000,000	35,000,000

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Basis of Presentation - Narrative (Details) - Exelon Corporate [Member]	Dec. 31, 2015
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	100.00%
Commonwealth Edison Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	99.00%
Baltimore Gas and Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	100.00%
Baltimore Gas and Electric Company [Member] \| Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	0.00%
PECO Energy Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	100.00%
PECO Energy Co [Member] \| Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	0.00%

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Narrative (Details) - USD ($)

Dec. 31, 2015

May 30, 2014

^[3],[4]

Line of Credit Facility, Capacity Available for Trade Purchases

^[1]

$ 6,341,000,000

Line of Credit Facility, Capacity Available for Trade Purchases

^[1]

474,000,000

Revolving Credit Facility [Member] | Exelon Corporate [Member]

^[2]

8,425,000,000

$ 500,000,000

^[2]

$ 500,000,000

[1]	Excludes $275 million bilateral credit facilities that do not back Generation’s commercial paper program
[2]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[3]	Excludes additional credit facilities 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. The agreements for these facilities expired on October 16, 2015 and were renewed at the same amount through October 14, 2016. These facilities are solely utilized to issue letters of credit. As of December 31, 2015, letters of credit issued under these facilities totaled $7 million, $14 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[4]	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $275 million and $200 million bilateral agreements for Generation as of December 31, 2015 and 2014, respectively) that backstop the commercial paper program. See discussion and Credit Facilities table below for items affecting effective program size.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Outstanding Long-term Debt (Details) - USD ($)

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Jun. 30, 2014

$ 25,113,000,000

$ 20,864,000,000

(63,000,000)

(37,000,000)

$ 23,645,000,000

19,212,000,000

3.95%

Junior Subordinated Debt [Member]

^[1]

$ (180,000,000)

(150,000,000)

$ 1,150,000,000

1,150,000,000

$ 1,150,000,000.00

6.50%

$ 9,803,000,000

7,071,000,000

1.55%

contract Payments Junior Subordinate Debt [Member]

7.60%

$ 64,000,000

108,000,000

2.50%

$ 5,853,000,000

3,916,000,000

Fair value adjustment of consolidated subsidiary

(4,000,000)

1,000,000

275,000,000

333,000,000

(60,000,000)

(1,409,000,000)

6,017,000,000

2,818,000,000

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

(47,000,000)

(23,000,000)

$ 1,150,000,000

1,150,000,000

Exelon Corporate [Member] | Senior Notes [Member]

6.50%

Unsecured Long Term Debt

^[2]

$ 4,639,000,000

2,658,000,000

^[2]

1.55%

Exelon Corporate [Member] | contract Payments Junior Subordinate Debt [Member]

^[2]

7.60%

$ 64,000,000

$ 108,000,000

2.50%

[1]	Certain December 31, 2014 balances have been adjusted for the adoption of accounting guidance related to simplifying the presentation of debt costs. See Note 1 - Significant Accounting Policies for additional information.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmJiZTkxZGVlYTU0NDQzYzU5MmI5ODA2YTIzODFjMGRkfFRleHRTZWxlY3Rpb246QUM1QzUxNjBCNkEwMjA1MjMyMzgxMjI1RThCRDgwNEUM}

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Debt Maturities (Details)
$ in Millions

Dec. 31, 2015

USD ($)

$ 1,487

1,841

1,393

973

3,311

16,756

^[1]

25,761

569

1,450

3,789

$ 5,853

[1]	Includes $648 million due to ComEd, PECO and BGE financing trusts.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Related Party Transactions - Summary of Related Party Transactions (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Due to Affiliate, Current

$ (20)

$ 10

$ 8

Interest income from affiliates, net

Cash contributions received from affiliates

2,461

1,779

1,903

3,209

1,370

1,175

1,478

818

26,119

26,670

933

943

Exelon Corporate [Member] | Business Services Company [Member]

182

^[1]

^[1]

^[1]

226

262

Exelon Corporate [Member] | Exelon Energy Delivery Company LLC [Member]

^[1]

191

193

^[2]

1,079

958

834

Exelon Corporate [Member] | Exelon Ventures Company LLC [Member]

^[2]

14,163

13,590

Exelon Corporate [Member] | UII LLC [Member]

^[3]

926

1,076

(6)

(2)

Exelon Corporate [Member] | Exelon Transmission Company LLC [Member]

102

130

(8)

(7)

(5)

Exelon Corporate [Member] | ExelonEnterprise [Member]

(1)

Exelon Corporate [Member] | Exelon Generation Consolidated [Member]

1,371

(91)

$ 0

1,252

556

Exelon Corporate [Member] | Exelon Consolidations [Member]

11,637

12,720

Exelon Corporate [Member] | Exelon Generation Co L L C [Member]

(6)

Exelon Corporate [Member] | Commonwealth Edison Co [Member]

933

943

Due to Affiliate, Current

188

Exelon Corporate [Member] | PECO Energy Co [Member]

182

Exelon Corporate [Member] | Baltimore Gas and Electric Company [Member]

Exelon Corporate [Member] | VEBA [Member]

Allowance for Uncollectible Accounts [Member]

$ 7

$ 9

[1]	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.
[2]	Exelon Energy Delivery Company, LLC consists of ComEd, PECO and BGE.
[3]	Exelon Ventures Company, LLC primarily consisted of Generation

Schedule II - Valuation and Qualifying Accounts (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Movement in Valuation Allowances and Reserves [Roll Forward]

^[1]

$ 311

$ 272

$ 293

^[1]

113

175

121

^[1]

^[2]

^[2],[3]

^[1],[4]

167

205

179

Deferred Tax Valuation Allowance [Member]

^[1]

284

311

272

Movement in Valuation Allowances and Reserves [Roll Forward]

(27)

^[3]

Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[3]

Exelon Generation Co L L C [Member] | Allowance for Uncollectible Accounts [Member]

105

Movement in Valuation Allowances and Reserves [Roll Forward]

(16)

^[1]

Exelon Generation Co L L C [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

(27)

Exelon Generation Co L L C [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[1]

(1)

Commonwealth Edison Co [Member] | Allowance for Uncollectible Accounts [Member]

102

Movement in Valuation Allowances and Reserves [Roll Forward]

^[5]

^[6]

Commonwealth Edison Co [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Movement in Valuation Allowances and Reserves [Roll Forward]

Noncurrent portion of uncollectible installment plan receivables

PECO Energy Co [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[7]

100

107

^[7]

^[7],[8]

^[7],[9]

PECO Energy Co [Member] | Reserve for Obsolete Materials [Member]

^[7]

100

107

Movement in Valuation Allowances and Reserves [Roll Forward]

Movement in Valuation Allowances and Reserves [Roll Forward]

Baltimore Gas and Electric Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[10]

^[11]

Baltimore Gas and Electric Company [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Baltimore Gas and Electric Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]