View Filing Data

Rate-regulated utility revenues

Operating revenues

$ 16,324

$ 18,395

$ 16,637

15,036

11,052

10,792

13,869

9,876

9,467

1,166

1,176

1,325

31,360

29,447

27,429

Competitive businesses purchased power and fuel

8,817

10,007

9,369

Purchased power and fuel

3,823

3,077

3,103

531

531

10,048

8,322

8,568

3,936

2,450

2,314

1,576

1,200

1,154

28,200

25,056

25,039

(24)

(7)

Gain on consolidation and acquisition of businesses

(48)

437

289

3,112

4,409

3,096

(1,495)

(992)

(1,024)

(41)

413

(46)

455

(1,123)

(1,079)

(610)

1,989

3,330

2,486

1,989

3,330

2,486

Net Income (Loss) Attributable to Noncontrolling Interest

761

1,073

666

(19)

197

1,204

2,250

1,820

Pension and non-pension postretirement benefit plans:

1,134

2,269

1,623

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

(20)

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

(48)

(46)

(30)

Actuarial loss reclassified to periodic cost, net of tax

184

220

147

Other Comprehensive (Income) Loss, Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax

181

497

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

$ 0

(2)

(9)

148

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

(4)

(3)

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

(21)

(9)

Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax

(116)

Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest

(36)

^[1]

(644)

1,168

2,310

1,176

Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest

(19)

197

Average shares of common stock outstanding:

$ 1,098

$ 2,329

$ 979

Basic

924

890

860

Diluted

927

893

864

Earnings per average common share:

Basic (in usd per share)

$ 1.23

$ 2.55

$ 1.89

Diluted (in usd per share)

1.22

2.54

1.88

Dividends per common share (in usd per share)

$ 1.264

$ 1.24

Predecessor [Member]

$ 0

Operating revenues

$ 16,312

$ 18,386

16,614

1,439

749

779

17,751

19,135

17,393

Purchased power and fuel

8,818

10,007

9,368

557

557

4,978

4,688

4,943

663

620

623

1,879

1,054

967

506

489

465

16,856

16,872

16,923

(20)

Gain on consolidation and acquisition of businesses

(59)

437

289

836

2,275

1,176

(325)

(322)

(303)

(39)

(43)

(53)

401

(60)

406

Income (Loss) Attributable to Noncontrolling Interest

(425)

(32)

184

873

1,850

1,226

290

502

207

Net income attributable to membership interest

558

1,340

1,019

496

1,372

835

Pension and non-pension postretirement benefit plans:

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

(25)

(8)

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

(2)

132

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

(4)

(3)

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

(21)

(9)

Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax

(1)

Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest

(27)

^[1]

(250)

567

1,313

769

Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest

(32)

184

505

1,345

585

5,239

4,901

4,560

5,254

4,905

4,564

176

1,411

1,301

1,001

1,303

1,372

1,263

227

195

166

775

707

687

293

296

293

4,056

3,889

3,586

1,205

1,017

980

(448)

(319)

(308)

(13)

(65)

(526)

(311)

(304)

679

706

676

301

280

268

Pension and non-pension postretirement benefit plans:

378

426

408

378

426

408

2,524

2,485

2,446

462

545

646

2,994

3,032

3,094

287

220

194

598

735

740

162

235

327

665

684

767

146

110

270

260

236

164

160

159

2,292

2,404

2,522

702

630

572

(111)

(102)

(101)

(12)

(115)

(109)

(106)

587

521

466

149

143

114

438

378

352

Pension and non-pension postretirement benefit plans:

438

378

352

438

378

352

2,603

2,490

2,460

609

631

680

3,233

3,135

3,165

604

498

382

528

602

733

162

205

302

605

565

614

132

118

103

423

366

371

229

224

221

2,683

2,578

2,726

550

558

439

(87)

(83)

(90)

(16)

(82)

(81)

(88)

468

477

351

174

189

140

Dividends, Preferred Stock

294

288

211

Pension and non-pension postretirement benefit plans:

286

275

198

Comprehensive Income (Loss), Net of Tax, Including Portion Attributable to Noncontrolling Interest

294

288

211

Comprehensive Income (Loss), Net of Tax, Attributable to Noncontrolling Interest

286

275

198

1,096

4,770

4,614

165

194

1,153

4,935

4,808

471

1,986

1,940

117

294

1,156

1,183

152

624

526

105

455

437

1,048

4,308

4,203

105

673

605

(65)

(280)

(269)

(4)

(69)

(192)

(225)

481

380

Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Noncontrolling Interest

163

138

Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest

318

242

Net income attributable to membership interest

327

242

327

242

Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic cost, net of tax

(12)

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

(1)

^[1]

(12)

337

230

$ 3,506

3,643

486

925

1,144

515

354

3,549

(1)

(195)

(151)

(58)

Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Noncontrolling Interest

$ 0

Income (Loss) from Continuing Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest

(61)

Net Income (Loss) Attributable to Noncontrolling Interest

(61)

Net income attributable to membership interest

(61)

(61)

Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic cost, net of tax

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

$ (61)

1,122

1,132

1,081

148

164

194

1,277

1,302

1,282

154

369

555

536

104

422

303

266

157

148

122

1,236

1,137

1,075

165

207

(50)

(48)

(37)

(40)

(38)

125

169

(9)

104

Pension and non-pension postretirement benefit plans:

(9)

104

(9)

104

2,181

2,124

2,050

2,186

2,129

2,055

295

411

719

735

607

435

386

295

256

212

377

376

369

2,020

1,790

1,706

174

385

349

(127)

(124)

(115)

(91)

(96)

(85)

289

264

102

187

171

Pension and non-pension postretirement benefit plans:

187

171

187

171

1,254

1,291

1,206

1,257

1,295

1,210

Cost Of Goods And Services Energy Commodities And Services From Affiliate

614

708

664

410

268

247

165

175

155

1,251

1,161

1,073

134

137

(62)

(64)

(53)

(61)

(46)

(4)

(42)

Pension and non-pension postretirement benefit plans:

(42)

$ (42)

$ 40

$ 46

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

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash flows from operating activities
Net income	$ 1,204	$ 2,250	$ 1,820
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	5,576	3,987	3,868
Impairments of long-lived assets	306	36	687
Gain on consolidation and acquisition of businesses	0	0	(296)
(Gain) Loss on sales of assets	48	(18)	(437)
Deferred income taxes and amortization of investment tax credits	664	752	502
Net fair value changes related to derivatives	24	(367)	716
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(229)	131	(210)
Other non-cash operating activities	1,333	1,109	1,054
Changes in assets and liabilities:
Accounts receivable	(432)	240	(318)
Inventories	7	4	(380)
Accounts payable and accrued expenses	771	(121)	49
Increase (Decrease) in Premiums Receivable	66	(58)	(38)
Increase (Decrease) Cash Collateral from Counterparties	931	347	(1,719)
Income taxes	576	97	(143)
Pension and non-pension postretirement benefit contributions	(397)	(502)	(617)
Increase (Decrease) in Prepaid Taxes	(1,250)	0	0
Other assets and liabilities	(621)	(387)	(157)
Net cash flows provided by operating activities	8,445	7,616	4,457
Cash flows from investing activities
Capital expenditures	(8,553)	(7,624)	(6,077)
Proceeds from Sale and Collection of Lease Receivables	360	0	335
Proceeds from nuclear decommissioning trust fund sales	9,496	6,895	7,396
Investment in nuclear decommissioning trust funds	(9,738)	(7,147)	(7,551)
Acquisitions of businesses, net	(6,934)	(40)	(386)
Proceeds from sales of long-lived assets	61	147	1,719
Proceeds from sales of investments	0	0	7
Cash and restricted cash acquired from consolidations and acquisitions	0	0	140
Purchases of investments	0	0	(3)
Change in restricted cash	(42)	66	(104)
Distribution from CENG	0	0	13
Other investing activities	(153)	(119)	(88)
Net cash flows used in investing activities	(15,503)	(7,822)	(4,599)
Cash flows from financing activities
Repayments of Debt, Maturing in More than Three Months	(462)	0	0
Issuance of long-term debt	4,716	6,709	3,463
Retirement of long-term debt	(1,936)	(2,687)	(1,545)
Redemption of preference stock	(190)	0	0
Distribution to noncontrolling interest of consolidated VIE	0	0	(421)
Dividends paid on common stock	(1,166)	(1,105)	(1,065)
Proceeds from employee stock plans	(55)	(32)	(35)
Other financing activities	(85)	(99)	(178)
Proceeds from Noncontrolling Interests	372	32	0
Proceeds from (Repayments of) Short-term Debt	(353)	80	122
Proceeds from Issuance of Common Stock	0	1,868	0
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	240	0	0
Net cash flows provided by financing activities	1,191	4,830	411
(Decrease) Increase in cash and cash equivalents	(5,867)	4,624	269
Cash and cash equivalents at beginning of period	6,502	1,878	1,609
Cash and cash equivalents at end of period	635	6,502	1,878
Predecessor [Member]
Adjustments to reconcile net income to net cash flows provided by operating activities:
Impairments of long-lived assets		0
(Gain) Loss on sales of assets			0
Parent Company [Member]
Cash flows from operating activities
Net income	1,134	2,269	1,623
Adjustments to reconcile net income to net cash flows provided by operating activities:
Increase (Decrease) Due from Affiliates	1,390	(1,217)	(83)
Changes in assets and liabilities:
Net cash flows provided by operating activities	1,029	3,071	806
Cash flows from investing activities
Capital expenditures	0	0	1
Payments to Acquire Businesses, Net of Cash Acquired	6,962
Proceeds from Sale and Collection of Lease Receivables	0	0	335
Other investing activities	5	(55)	(126)
Net cash flows used in investing activities	(7,324)	(934)	57
Cash flows from financing activities
Issuance of long-term debt	1,800	4,200	1,150
Retirement of long-term debt	(46)	(2,263)	(23)
Dividends paid on common stock	(1,166)	(1,105)	(1,065)
Proceeds from employee stock plans	(55)	(32)	(35)
Other financing activities	(20)	(58)	(84)
Contribution from member	1,912	3,209	1,370
Proceeds from Issuance of Common Stock	0	1,868	0
Net cash flows provided by financing activities	623	2,674	13
(Decrease) Increase in cash and cash equivalents	(5,672)	4,811	876
Cash and cash equivalents at beginning of period	5,690	879	3
Cash and cash equivalents at end of period	18	5,690	879
Increase (Decrease) Due from Affiliates	1,390	(1,217)	(83)
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	558	1,340	1,019
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	3,519	2,589	2,519
Impairments of long-lived assets	243	12	663
Gain on consolidation and acquisition of businesses	0	0	(296)
(Gain) Loss on sales of assets	59	(12)	(437)
Deferred income taxes and amortization of investment tax credits	(269)	49	(198)
Net fair value changes related to derivatives	40	(249)	635
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments	(229)	131	(210)
Other non-cash operating activities	15	268	346
Increase (Decrease) Due from Affiliates	0	0	44
Changes in assets and liabilities:
Accounts receivable	(152)	194	(215)
Receivables from and payables to affiliates, net	(21)	15	15
Inventories	(4)	16	(359)
Accounts payable and accrued expenses	29	(149)	29
Increase (Decrease) in Premiums Receivable	66	(58)	(38)
Increase (Decrease) Cash Collateral from Counterparties	923	407	(1,748)
Income taxes	182	(18)	265
Pension and non-pension postretirement benefit contributions	(152)	(245)	(297)
Other assets and liabilities	(231)	(207)	57
Net cash flows provided by operating activities	4,444	4,199	1,826
Cash flows from investing activities
Capital expenditures	(3,078)	(3,841)	(3,012)
Proceeds from nuclear decommissioning trust fund sales	9,496	6,895	7,396
Investment in nuclear decommissioning trust funds	(9,738)	(7,147)	(7,551)
Acquisitions of businesses, net	(293)	(40)	(386)
Proceeds from sales of long-lived assets	37	147	1,719
Cash and restricted cash acquired from consolidations and acquisitions	0	0	140
Change in restricted cash	(35)	35	(87)
Distribution from CENG	0	0	13
Other investing activities	(240)	(118)	(43)
Net cash flows used in investing activities	(3,851)	(4,069)	(1,767)
Cash flows from financing activities
Repayments of Debt, Maturing in More than Three Months	(162)	0	0
Issuance of long-term debt	388	1,309	1,112
Retirement of long-term debt	(202)	(89)	(586)
Repayments of Related Party Debt	0	(550)	0
Increase (Decrease) in Due to Affiliates	(1,191)	1,252	0
Distribution to noncontrolling interest of consolidated VIE	0	0	(421)
Other financing activities	(19)	(6)	(67)
Distribution to member	(922)	(2,474)	(645)
Contribution from member	142	47	53
Proceeds from Noncontrolling Interests	372	32	0
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	620	0	17
Proceeds from Debt, Maturing in More than Three Months	240	0	0
Net cash flows provided by financing activities	(734)	(479)	(537)
(Decrease) Increase in cash and cash equivalents	(141)	(349)	(478)
Cash and cash equivalents at beginning of period	431	780	1,258
Cash and cash equivalents at end of period	290	431	780
Increase (Decrease) Due from Affiliates	0	0	44
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	378	426	408
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	775	707	687
Deferred income taxes and amortization of investment tax credits	439	353	433
Other non-cash operating activities	215	416	255
Changes in assets and liabilities:
Accounts receivable	(25)	(93)	(121)
Receivables from and payables to affiliates, net	3	(19)	(11)
Inventories	1	(40)	(16)
Accounts payable and accrued expenses	339	68	95
Increase (Decrease) Cash Collateral from Counterparties	7	(33)	2
Income taxes	306	192	(159)
Pension and non-pension postretirement benefit contributions	(38)	(150)	(248)
Other assets and liabilities	105	69	1
Net cash flows provided by operating activities	2,505	1,896	1,326
Cash flows from investing activities
Capital expenditures	(2,734)	(2,398)	(1,689)
Proceeds from sales of investments	0	0	7
Purchases of investments	0	0	(3)
Change in restricted cash	0	2	(2)
Other investing activities	49	34	32
Net cash flows used in investing activities	(2,685)	(2,362)	(1,655)
Cash flows from financing activities
Issuance of long-term debt	1,200	850	900
Retirement of long-term debt	(665)	(260)	(617)
Dividends paid on common stock	(369)	(299)	(307)
Other financing activities	(18)	(16)	(10)
Contributions from parent	315	202	273
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	(294)	(10)	120
Net cash flows provided by financing activities	169	467	359
(Decrease) Increase in cash and cash equivalents	(11)	1	30
Cash and cash equivalents at beginning of period	67	66	36
Cash and cash equivalents at end of period	56	67	66
PECO Energy Co [Member]
Cash flows from operating activities
Net income	438	378	352
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	270	260	236
Deferred income taxes and amortization of investment tax credits	78	90	88
Other non-cash operating activities	65	70	92
Increase (Decrease) Due from Affiliates	(131)	0	0
Changes in assets and liabilities:
Accounts receivable	(71)	37	(16)
Receivables from and payables to affiliates, net	6	3	(6)
Inventories	6	10	2
Accounts payable and accrued expenses	67	(25)	58
Income taxes	8	(9)	(57)
Pension and non-pension postretirement benefit contributions	(30)	(40)	(16)
Other assets and liabilities	(8)	(4)	(21)
Net cash flows provided by operating activities	829	770	712
Cash flows from investing activities
Capital expenditures	(686)	(601)	(661)
Change in restricted cash	(1)	(1)	0
Other investing activities	20	14	12
Net cash flows used in investing activities	(798)	(588)	(649)
Cash flows from financing activities
Issuance of long-term debt	300	350	300
Retirement of long-term debt	(300)	0	(250)
Dividends paid on common stock	(277)	(279)	(320)
Other financing activities	(4)	(4)	(4)
Contributions from parent	18	16	24
Net cash flows provided by financing activities	(263)	83	(250)
(Decrease) Increase in cash and cash equivalents	(232)	265	(187)
Cash and cash equivalents at beginning of period	295	30	217
Cash and cash equivalents at end of period	63	295	30
Increase (Decrease) Due from Affiliates	(131)	0	0
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	294	288	211
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	423	366	371
Impairments of long-lived assets	52	0	0
Deferred income taxes and amortization of investment tax credits	118	165	116
Other non-cash operating activities	88	137	180
Changes in assets and liabilities:
Accounts receivable	(98)	84	46
Receivables from and payables to affiliates, net	3	(2)	(1)
Inventories	1	18	(6)
Accounts payable and accrued expenses	138	(3)	(75)
Increase (Decrease) Cash Collateral from Counterparties	0	(27)	27
Income taxes	18	(54)	45
Pension and non-pension postretirement benefit contributions	(49)	(17)	(16)
Other assets and liabilities	(43)	(173)	(158)
Net cash flows provided by operating activities	945	782	740
Cash flows from investing activities
Capital expenditures	(934)	(719)	(620)
Change in restricted cash	0	26	(22)
Other investing activities	24	18	20
Net cash flows used in investing activities	(910)	(675)	(622)
Cash flows from financing activities
Issuance of long-term debt	850	0	0
Retirement of long-term debt	(379)	(75)	(70)
Redemption of preference stock	(190)	0	0
Preferred Stock, Redemption Amount	190
Dividends paid on common stock	(179)	(158)	0
Other financing activities	(11)	(13)	13
Contributions from parent	61	7	0
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less	(165)	90	(15)
Dividends paid on preferred securities	(8)	(13)	(13)
Net cash flows provided by financing activities	(21)	(162)	(85)
(Decrease) Increase in cash and cash equivalents	14	(55)	33
Cash and cash equivalents at beginning of period	9	64	31
Cash and cash equivalents at end of period	23	9	64
Pepco Holdings LLC [Member] \| Predecessor [Member]
Cash flows from operating activities
Net income		327	242
Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest		(9)	0
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization		624	526
Impairments of long-lived assets			81
(Gain) Loss on sales of assets		(46)
Deferred income taxes and amortization of investment tax credits		134	303
Net fair value changes related to derivatives		0	0
Other non-cash operating activities		167	127
Changes in assets and liabilities:
Accounts receivable		(105)	(2)
Receivables from and payables to affiliates, net		0	0
Inventories		0	8
Accounts payable and accrued expenses		(41)	(31)
Increase (Decrease) Cash Collateral from Counterparties		0	1
Income taxes		8	(197)
Pension and non-pension postretirement benefit contributions		(21)	(18)
Other assets and liabilities		(99)	(186)
Net cash flows provided by operating activities		939	854
Cash flows from investing activities
Capital expenditures		(1,230)	(1,223)
Proceeds from sales of long-lived assets		54	0
Purchases of investments		0	0
Change in restricted cash		6	(12)
Other investing activities		9	9
Net cash flows used in investing activities		(1,161)	(1,226)
Cash flows from financing activities
Repayments of Debt, Maturing in More than Three Months		0	0
Issuance of long-term debt		558	766
Retirement of long-term debt		(430)	(462)
Increase (Decrease) in Due to Affiliates		0	0
Dividends paid on common stock		(275)	(272)
Proceeds from employee stock plans		(18)	(33)
Other financing activities		(26)	(11)
Distribution to member		0	0
Proceeds from (Repayments of) Short-term Debt		34	183
Proceeds from Issuance of Preferred Stock and Preference Stock		54	126
Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less		300	0
Net cash flows provided by financing activities		233	363
(Decrease) Increase in cash and cash equivalents		11	(9)
Cash and cash equivalents at beginning of period	26	15	24
Cash and cash equivalents at end of period		26	15
Proceeds from Issuance of Preferred Stock and Preference Stock		54	126
Pepco Holdings LLC [Member] \| Successor [Member]
Cash flows from financing activities
Cash and cash equivalents at end of period	170
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income	42	187	171
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	295	256	212
(Gain) Loss on sales of assets	(8)	(46)	0
Deferred income taxes and amortization of investment tax credits	153	150	175
Other non-cash operating activities	183	54	37
Changes in assets and liabilities:
Accounts receivable	(41)	(43)	7
Receivables from and payables to affiliates, net	44	0	(2)
Inventories	1	(5)	5
Accounts payable and accrued expenses	32	(21)	(37)
Income taxes	110	(46)	(14)
Pension and non-pension postretirement benefit contributions	(32)	(14)	(11)
Other assets and liabilities	(128)	(99)	(157)
Net cash flows provided by operating activities	651	373	386
Cash flows from investing activities
Capital expenditures	(586)	(544)	(567)
Acquisitions of businesses, net	(33)
Proceeds from sales of long-lived assets	12	54	9
Purchases of investments	(30)	0	0
Change in restricted cash	(31)	3	(3)
Other investing activities	(12)	10	1
Net cash flows used in investing activities	(647)	(477)	(560)
Cash flows from financing activities
Issuance of long-term debt	4	208	412
Retirement of long-term debt	(11)	(22)	(184)
Dividends paid on common stock	(136)	(146)	(86)
Other financing activities	(3)	(9)	(4)
Contributions from parent	187	112	80
Proceeds from (Repayments of) Short-term Debt	(41)	(40)	(47)
Net cash flows provided by financing activities	0	103	171
(Decrease) Increase in cash and cash equivalents	4	(1)	(3)
Cash and cash equivalents at beginning of period	5	6	9
Cash and cash equivalents at end of period	9	5	6
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income	(9)	76	104
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	157	148	122
Deferred income taxes and amortization of investment tax credits	109	73	110
Other non-cash operating activities	114	33	22
Changes in assets and liabilities:
Accounts receivable	(5)	(24)	1
Receivables from and payables to affiliates, net	13	3	(6)
Inventories	0	6	(2)
Accounts payable and accrued expenses	(4)	(8)	0
Increase (Decrease) Cash Collateral from Counterparties	1	(1)	0
Income taxes	28	(26)	(1)
Pension and non-pension postretirement benefit contributions	(22)	0	0
Other assets and liabilities	(72)	(14)	(82)
Net cash flows provided by operating activities	310	266	268
Cash flows from investing activities
Capital expenditures	(349)	(352)	(352)
Proceeds from sales of long-lived assets	9	0	0
Change in restricted cash	0	5	(5)
Other investing activities	4	2	(1)
Net cash flows used in investing activities	(336)	(345)	(358)
Cash flows from financing activities
Issuance of long-term debt	175	200	204
Retirement of long-term debt	(100)	(100)	(100)
Dividends paid on common stock	(54)	(92)	(100)
Other financing activities	(1)	(2)	(1)
Contributions from parent	152	75	130
Proceeds from (Repayments of) Short-term Debt	(105)	(1)	(41)
Net cash flows provided by financing activities	67	80	92
(Decrease) Increase in cash and cash equivalents	41	1	2
Cash and cash equivalents at beginning of period	5	4	2
Cash and cash equivalents at end of period	46	5	4
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income	(42)	40	46
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	165	175	155
Deferred income taxes and amortization of investment tax credits	22	31	38
Other non-cash operating activities	155	37	26
Changes in assets and liabilities:
Accounts receivable	(8)	(67)	6
Receivables from and payables to affiliates, net	13	1	0
Inventories	(1)	(1)	4
Accounts payable and accrued expenses	9	9	(17)
Income taxes	174	(34)	(20)
Pension and non-pension postretirement benefit contributions	(17)	(2)	(3)
Other assets and liabilities	(85)	67	24
Net cash flows provided by operating activities	385	256	259
Cash flows from investing activities
Capital expenditures	(311)	(300)	(225)
Proceeds from sales of long-lived assets	2	0	0
Change in restricted cash	(2)	(6)	0
Other investing activities	2	0	1
Net cash flows used in investing activities	(309)	(306)	(224)
Cash flows from financing activities
Repayments of Debt, Maturing in More than Three Months			(100)
Issuance of long-term debt	0	150	150
Retirement of long-term debt	(48)	(58)	(66)
Dividends paid on common stock	(63)	(12)	(26)
Other financing activities	(1)	(2)	(1)
Contributions from parent	139	95	0
Proceeds from (Repayments of) Short-term Debt	(5)	(122)	7
Net cash flows provided by financing activities	22	51	(36)
(Decrease) Increase in cash and cash equivalents	98	1	(1)
Cash and cash equivalents at beginning of period	3	2	3
Cash and cash equivalents at end of period	$ 101	$ 3	$ 2

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

Dec. 31, 2016

Mar. 24, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 635

$ 6,502

$ 1,878

$ 1,609

253

205

4,158

3,187

1,201

912

Energy Marketing Contracts Assets, Current

917

1,365

364

462

1,274

1,104

Prepaid utility taxes

1,250

1,342

759

930

752

12,412

15,334

71,555

57,439

10,046

6,065

11,061

10,342

629

639

6,677

2,672

Unamortized energy contract assets

492

758

447

484

113

206

1,472

1,445

30,937

22,611

^[1]

114,904

95,384

1,267

533

2,430

1,500

3,441

2,883

3,460

2,376

Payables to affiliates

706

282

205

Energy Marketing Accounts Payable

407

100

428

302

151

602

369

981

842

13,457

9,118

31,575

23,645

641

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

18,138

13,776

9,111

8,585

4,248

3,385

Spent nuclear fuel obligation

1,848

1,618

1,024

1,021

4,187

4,201

392

374

Payable for Zion Station decommissioning

830

117

1,827

1,491

41,619

34,658

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[1]

87,292

68,062

193

Treasury stock, at cost (35 shares at December 31, 2016 and 2015, respectively)

18,794

18,676

(2,327)

(2,660)

(2,624)

BGE preference stock not subject to mandatory redemption

25,837

25,793

193

1,775

1,308

Total equity

27,612

27,294

24,133

22,940

12,030

12,068

(2,660)

(2,624)

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

114,904

95,384

8,893

8,268

3,356

3,264

136

154

370

388

3,273

3,070

289

299

206

202

510

511

4,153

3,969

105

119

204

109

381

564

1,221

1,061

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

1,056

945

111

1,225

1,107

2,827

2,732

764

612

Liabilities And Stockholders Equity Including Portion Attributable To Noncontrolling Interest

1,326

1,237

1,178

1,044

4,153

3,969

562

625

528

533

218

272

Inventories, net

159

164

190

218

356

199

1,554

1,518

19,335

17,502

977

895

Receivable from affiliates

2,625

2,170

2,172

1,343

1,490

325

324

7,446

7,512

28,335

26,532

294

425

665

645

660

1,250

706

121

131

329

155

2,938

2,766

6,608

5,844

205

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

5,364

4,914

119

111

239

259

3,369

3,459

(239)

224

529

507

9,859

9,474

19,610

18,289

1,588

Other paid-in capital

6,150

5,677

8,725

8,243

7,907

7,528

Retained Earnings, Unappropriated

28,335

26,532

(1,639)

2,626

2,617

290

431

780

1,258

158

123

2,433

2,095

558

360

Energy Marketing Contracts Assets, Current

917

1,365

292

384

935

880

701

535

156

6,528

6,342

25,585

25,843

11,061

10,342

418

210

476

733

Unamortized energy contract assets

1,595

1,689

447

484

113

206

688

627

14,861

14,344

^[2]

46,974

46,529

699

1,117

1,610

1,583

989

935

137

104

263

182

Energy Marketing Accounts Payable

100

428

302

Notes Payable, Related Parties, Current

313

356

1,252

5,683

4,933

7,202

7,936

922

933

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

5,585

5,845

8,922

8,431

Spent nuclear fuel obligation

930

924

1,024

1,021

153

150

Payable for Zion Station decommissioning

117

595

602

2,608

2,577

19,911

19,757

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[2]

33,718

33,559

(54)

(63)

Membership interest/Common stock(c)

9,261

8,997

2,275

2,701

(54)

(63)

Total member’s equity

11,482

11,635

1,774

1,307

Total equity

13,256

12,942

14,051

12,742

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

46,974

46,529

8,817

8,235

3,170

3,135

295

217

306

258

131

146

Prepaid utility taxes

Due from Affiliates

131

757

842

7,565

7,141

1,681

1,583

Receivable from affiliates

438

405

345

347

2,509

2,384

10,831

10,367

300

342

281

104

109

127

112

727

944

2,580

2,280

184

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

3,006

2,792

289

287

517

527

3,925

3,723

7,416

7,131

2,473

2,455

3,415

3,236

3,121

3,065

941

780

10,831

10,367

395

300

102

112

Prepaid utility taxes

208

267

842

845

7,040

6,597

504

514

297

319

822

853

^[3]

8,704

8,295

210

378

205

209

175

110

110

102

707

1,134

2,281

1,480

252

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

2,219

2,081

205

209

110

184

Preferred Stock, Value, Outstanding

2,616

2,552

190

Preferred Stock, Shares Outstanding

^[3]

$ 5,856

$ 5,418

0.00

1,900,000.00

$ 0

$ 190

1,421

1,367

BGE preference stock not subject to mandatory redemption

2,848

2,687

190

Total equity

2,848

2,877

2,753

2,555

1,427

1,320

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

8,704

8,295

122

581

319

122

305

1,474

10,864

2,277

1,406

1,407

Notes, Loans and Financing Receivable, Gross, Noncurrent

3,850

^[4]

16,188

958

456

404

266

107

2,327

4,823

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

3,406

466

215

147

200

4,442

Preferred Stock, Shares Outstanding

^[4]

$ 11,592

18,000

^[5]

$ 183

(36)

BGE preference stock not subject to mandatory redemption

4,413

4,322

4,315

^[5]

183

Membership interest/Common stock(c)

^[6]

3,832

617

(36)

Total member’s equity

4,413

Pepco Holdings LLC [Member] | Predecessor [Member] | Additional Paid-in Capital [Member]

16,188

Other paid-in capital

3,829

170

496

283

116

653

1,838

11,598

2,851

133

4,005

509

Notes, Loans and Financing Receivable, Gross, Noncurrent

7,589

^[4]

21,025

522

253

458

272

335

123

101

2,284

5,645

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

3,775

134

158

750

249

5,080

^[4]

13,009

$ 165

BGE preference stock not subject to mandatory redemption

Membership interest/Common stock(c)

8,077

7,200

(61)

Total member’s equity

8,016

$ 7,200

^[7]

21,025

235

230

150

261

Inventories, net

162

140

684

726

5,571

5,162

690

661

102

282

287

1,080

1,020

7,335

6,908

209

145

113

119

596

455

2,333

2,340

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

1,910

1,723

133

2,106

1,873

5,035

4,668

1,309

1,122

Liabilities And Stockholders Equity Including Portion Attributable To Noncontrolling Interest

2,300

2,240

2,087

1,922

7,335

6,908

991

1,118

101

125

156

242

399

546

2,521

2,322

405

414

Notes, Loans and Financing Receivable, Gross, Noncurrent

537

519

^[8]

3,457

3,387

132

320

297

1,120

1,153

Deferred Income Taxes and Other Tax Liabilities, Noncurrent

917

885

983

937

^[8]

2,423

2,387

912

773

Liabilities And Stockholders Equity Including Portion Attributable To Noncontrolling Interest

1,034

1,000

$ 877

$ 857

3,457

3,387

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

$ 122

$ 227

[1]	Exelon’s consolidated assets include $8,893 million and $8,268 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,356 million and $3,264 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	Generation’s consolidated assets include $8,817 million and $8,235 million at December 31, 2016 and 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,170 million and $3,135 million at December 31, 2016 and 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[3]	BGE’s consolidated assets include $26 million and $26 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million and $122 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.
[4]	PHI’s consolidated total assets include $49 million and $30 million at December 31, 2016 and 2015, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $143 million and $172 million at December 31, 2016 and 2015, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities.
[5]	At December 31, 2015, PHI had 18,000 shares of Series A preferred stock authorized and outstanding, par value $0.01 per share.
[6]	At December 31, 2015, PHI's (predecessor) shareholders' equity included $3,829 million of other paid-in capital and $3 million of common stock. At December 31, 2015, PHI had 400,000,000 shares of common stock authorized and 254,289,261 shares of common stock outstanding, par value $0.01 per share.
[7]	The March 24, 2016, beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at Exelon Corporate to reflect unitary state income tax consequences of the merger.
[8]	ACE’s consolidated assets include $32 million and $30 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $126 million and $172 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities.

Consolidated Balance Sheets (Unaudited) (Parenthetical)	Dec. 31, 2015 $ / shares shares
Common stock, par value \| $ / shares	$ 0
Common stock, shares authorized	2,000,000,000
Common Stock, Shares, Outstanding	919,924,742
Treasury Stock, Shares held	35,000,000
Commonwealth Edison Co [Member]
Common Stock, Shares, Outstanding	127,016,973
PECO Energy Co [Member]
Common Stock, Shares, Outstanding	170,478,507
Baltimore Gas and Electric Company [Member]
Common Stock, Shares, Outstanding	1,000
Pepco Holdings LLC [Member] \| Predecessor [Member]
Common stock, shares authorized	400,000,000.00
Common Stock, Shares, Outstanding	254,289,261.00
Preferred Stock, Par or Stated Value Per Share \| $ / shares	$ 0.01
Common Stock, Par or Stated Value Per Share \| $ / shares	$ 0.01
Potomac Electric Power Company [Member]
Common Stock, Shares, Outstanding	100
Delmarva Power and Light Company [Member]
Common Stock, Shares, Outstanding	1,000
Atlantic City Electric Company [Member]
Common Stock, Shares, Outstanding	8,546,017

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

Total

Pepco Holdings LLC [Member]

Common Stock Including Additional Paid in Capital [Member]

Pepco Holdings LLC [Member]

^[3]

Common Stock [Member]

Treasury Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Membership Interest [Member]

Undistributed Earnings [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]

Pepco Holdings LLC [Member]

Common Stock Including Additional Paid in Capital [Member]

Pepco Holdings LLC [Member]

Retained Earnings [Member]

Pepco Holdings LLC [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Pepco Holdings LLC [Member]

Additional Paid-in Capital [Member]

Potomac Electric Power Company [Member]

Common Stock [Member]

Potomac Electric Power Company [Member]

Retained Earnings [Member]

Delmarva Power and Light Company [Member]

Common Stock [Member]

Delmarva Power and Light Company [Member]

Retained Earnings [Member]

Atlantic City Electric Company [Member]

Common Stock [Member]

Atlantic City Electric Company [Member]

Retained Earnings [Member]

Income Tax Effects Allocated Directly to Equity, Other

$ 0

$ 170,000,000

$ 0

$ 273,000,000

$ 80,000,000

$ 130,000,000

$ 24,000,000

$ 0

53,000,000

$ 53,000,000

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

892,034

Beginning Balance (Predecessor [Member]) at Dec. 31, 2013

$ 4,315,000,000

$ 3,754,000,000

$ 595,000,000

$ (34,000,000)

Beginning Balance at Dec. 31, 2013

3,065,000,000

2,415,000,000

$ 649,000,000

1,000,000

7,528,000,000

$ 1,588,000,000

5,190,000,000

$ (1,639,000,000)

$ 2,389,000,000

1,922,000,000

930,000,000

$ 992,000,000

1,044,000,000

407,000,000

$ 637,000,000

$ 857,000,000

$ 678,000,000

$ 179,000,000

Beginning Balance at Dec. 31, 2013

12,742,000,000

$ 214,000,000

$ 17,000,000

8,898,000,000

3,613,000,000

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

242,000,000

$ 1,820,000,000

$ 1,623,000,000

184,000,000

$ 13,000,000

352,000,000

1,019,000,000

184,000,000

835,000,000

408,000,000

$ 211,000,000

171,000,000

104,000,000

46,000,000

Dividends

307,000,000

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

$ (116,000,000)

116,000,000

1,574

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

$ 72,000,000

Employee stock purchase plan issuances | Predecessor [Member]

7,000,000

Employee stock purchase plan issuances

$ 35,000,000

35,000,000

Employee stock purchase plan issuances, shares

960

Common stock issuance Constellation merger, shares

Consolidated VIE dividend to noncontrolling interests

$ (421,000,000)

(421,000,000)

Noncontrolling Interest, Increase from Subsidiary Equity Issuance

1,548,000,000

Preferred and preference stock dividends

(13,000,000)

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

(12,000,000)

Other comprehensive loss, net of income taxes

(644,000,000)

(250,000,000)

(134,000,000)

Acquisition of noncontrolling interests

(4,000,000)

2,000,000

(6,000,000)

(645,000,000)

Tax benefit on stock compensation | Predecessor [Member]

7,000,000

Tax benefit on stock compensation

47,000,000

(8,000,000)

Changes in equity of noncontrolling interest

Fair value of financing contract payments

131,000,000

Transfer of CENG pension and non-pension postretirement benefit obligations

(2,000,000)

Reversal of CENG equity method AOCI, net of income taxes

116,000,000

Distribution to member

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

645,000,000

Noncontrolling Interest, Change in Redemption Value

421,000,000

Noncontrolling interest acquired

1,548,000,000

5,000,000

Ending Balance at Dec. 31, 2014

$ 24,133,000,000

16,709,000,000

$ (2,327,000,000)

10,910,000,000

(2,684,000,000)

1,332,000,000

193,000,000

2,753,000,000

$ 1,360,000,000

1,203,000,000

2,563,000,000

$ 190,000,000

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

894,568

Ending Balance (Predecessor [Member]) at Dec. 31, 2014

4,322,000,000

3,803,000,000

565,000,000

(46,000,000)

Ending Balance at Dec. 31, 2014

3,121,000,000

2,439,000,000

681,000,000

1,000,000

7,907,000,000

1,588,000,000

5,468,000,000

(1,639,000,000)

2,490,000,000

2,087,000,000

1,010,000,000

1,077,000,000

1,178,000,000

537,000,000

641,000,000

877,000,000

678,000,000

199,000,000

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

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

$ 8,000,000

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

386,000,000

645,000,000

Stock Issued During Period, Value, Dividend Reinvestment Plan | Predecessor [Member]

386,000,000

28,000,000

Allocated Share-based Compensation Expense, Net of Tax | Predecessor [Member]

11,000,000

Allocated Share-based Compensation Expense, Net of Tax

80,000,000

170,000,000

273,000,000

80,000,000

130,000,000

Temporary Equity, Other Changes

(116,000,000)

116,000,000

(528,000,000)

(4,000,000)

Dividends, Common Stock, Cash | Predecessor [Member]

272,000,000

Dividends, Common Stock, Cash

(1,071,000,000)

(320,000,000)

(86,000,000)

(100,000,000)

(26,000,000)

Noncontrolling Interest, Increase from Business Combination

5,000,000

(408,000,000)

408,000,000

14,000,000

14,000,000

Income Tax Effects Allocated Directly to Equity, Other

202,000,000

7,000,000

112,000,000

75,000,000

95,000,000

$ 47,000,000

16,000,000

(47,000,000)

Beginning Balance at Dec. 31, 2014

14,051,000,000

(36,000,000)

1,333,000,000

8,951,000,000

3,803,000,000

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

327,000,000

Noncontrolling Interest, Period Increase (Decrease)

2,250,000,000

2,269,000,000

(32,000,000)

13,000,000

378,000,000

1,340,000,000

(32,000,000)

1,372,000,000

426,000,000

288,000,000

187,000,000

76,000,000

40,000,000

Dividends

299,000,000

4,000,000

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

$ 0

1,430

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

$ 70,000,000

70,000,000

Employee stock purchase plan issuances | Predecessor [Member]

3,000,000

Employee stock purchase plan issuances

$ 32,000,000

32,000,000

Employee stock purchase plan issuances, shares

1,170

Consolidated VIE dividend to noncontrolling interests

Preferred and preference stock dividends

(13,000,000)

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

10,000,000

^[1]

10,000,000

Other comprehensive loss, net of income taxes

$ 60,000,000

^[1]

60,000,000

(27,000,000)

^[1]

(27,000,000)

Common stock dividends

(1,111,000,000)

Preference stock dividends

13,000,000

Tax benefit on stock compensation | Predecessor [Member]

5,000,000

Tax benefit on stock compensation

46,000,000

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

(2,474,000,000)

2,474,000,000

Noncontrolling Interest, Change in Redemption Value

4,000,000

Noncontrolling interest acquired

1,000,000

(1,000,000)

Ending Balance at Dec. 31, 2015

$ 27,294,000,000

18,676,000,000

(2,327,000,000)

12,068,000,000

(2,624,000,000)

1,308,000,000

193,000,000

2,877,000,000

1,367,000,000

1,320,000,000

2,687,000,000

190,000,000

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

954,668

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

4,413,000,000

3,832,000,000

^[2]

617,000,000

(36,000,000)

Ending Balance at Dec. 31, 2015

$ 25,793,000,000

3,236,000,000

2,455,000,000

780,000,000

1,000,000

8,243,000,000

1,588,000,000

5,677,000,000

(1,639,000,000)

2,617,000,000

2,687,000,000

2,240,000,000

1,122,000,000

1,118,000,000

1,237,000,000

612,000,000

625,000,000

1,000,000,000

773,000,000

227,000,000

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

Stock Issued During Period, Shares, New Issues

57,500

Stock Issued During Period, Value, New Issues

$ 1,868,000,000

1,868,000,000

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

(3,000,000)

3,000,000

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

40,000,000

(2,474,000,000)

2,474,000,000

Stock Issued During Period, Value, Dividend Reinvestment Plan | Predecessor [Member]

40,000,000

11,000,000

Allocated Share-based Compensation Expense, Net of Tax | Predecessor [Member]

8,000,000

Allocated Share-based Compensation Expense, Net of Tax

73,000,000

202,000,000

7,000,000

112,000,000

75,000,000

95,000,000

Temporary Equity, Other Changes

4,000,000

(4,000,000)

Dividends, Common Stock, Cash | Predecessor [Member]

275,000,000

Dividends, Common Stock, Cash

(279,000,000)

(158,000,000)

(146,000,000)

(92,000,000)

(12,000,000)

Members' Equity | Predecessor [Member]

7,000,000

4,413,000,000

11,635,000,000

2,617,000,000

(426,000,000)

426,000,000

15,000,000

$ 3,000,000

Additional Paid in Capital | Predecessor [Member]

18,676,000,000

2,455,000,000

1,588,000,000

1,367,000,000

1,122,000,000

612,000,000

773,000,000

3,829,000,000

5,677,000,000

15,000,000

3,000,000

Additional Paid in Capital | Predecessor [Member]

18,676,000,000

2,455,000,000

1,588,000,000

1,367,000,000

1,122,000,000

612,000,000

773,000,000

3,829,000,000

Beginning Balance at Dec. 31, 2015

5,677,000,000

12,942,000,000

(63,000,000)

1,307,000,000

8,997,000,000

2,701,000,000

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

Employee stock purchase plan issuances | Predecessor [Member]

19,000,000

3,000,000

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

1,000,000

Tax benefit on stock compensation | Predecessor [Member]

1,000,000

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

4,439,000,000

3,838,000,000

^[2]

636,000,000

(35,000,000)

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

Allocated Share-based Compensation Expense, Net of Tax | Predecessor [Member]

2,000,000

Income Tax Effects Allocated Directly to Equity, Other

315,000,000

61,000,000

187,000,000

152,000,000

139,000,000

$ 0

18,000,000

98,000,000

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

954,668

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

4,413,000,000

3,832,000,000

^[2]

617,000,000

(36,000,000)

Beginning Balance at Dec. 31, 2015

$ 25,793,000,000

3,236,000,000

2,455,000,000

780,000,000

1,000,000

8,243,000,000

1,588,000,000

5,677,000,000

(1,639,000,000)

2,617,000,000

2,687,000,000

2,240,000,000

1,122,000,000

1,118,000,000

1,237,000,000

612,000,000

625,000,000

1,000,000,000

773,000,000

227,000,000

Beginning Balance at Dec. 31, 2015

12,942,000,000

(63,000,000)

1,307,000,000

8,997,000,000

2,701,000,000

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

Noncontrolling Interest, Period Increase (Decrease)

1,204,000,000

$ (66,000,000)

1,134,000,000

62,000,000

8,000,000

438,000,000

558,000,000

62,000,000

496,000,000

378,000,000

294,000,000

42,000,000

(9,000,000)

(42,000,000)

Dividends

369,000,000

(5,000,000)

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

$ 0

2,868

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

$ 85,000,000

85,000,000

Employee stock purchase plan issuances

$ 55,000,000

55,000,000

Employee stock purchase plan issuances, shares

1,242

Preferred and preference stock dividends

$ (8,000,000)

8,000,000

(8,000,000)

Other comprehensive loss, net of income taxes

(36,000,000)

9,000,000

Preference stock dividends

(193,000,000)

193,000,000

Tax benefit on stock compensation

68,000,000

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

$ 922,000,000

922,000,000

(7,000,000)

Noncontrolling Interest, Change in Redemption Value

5,000,000

Noncontrolling interest acquired

396,000,000

$ 400,000,000

$ (4,000,000)

$ 0

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

$ 27,612,000,000

18,794,000,000

(2,327,000,000)

12,030,000,000

(2,660,000,000)

1,775,000,000

2,848,000,000

1,421,000,000

1,427,000,000

2,848,000,000

958,778

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

$ 25,837,000,000

3,415,000,000

2,473,000,000

941,000,000

1,000,000

8,725,000,000

1,588,000,000

6,150,000,000

(1,639,000,000)

2,626,000,000

2,848,000,000

2,300,000,000

1,309,000,000

991,000,000

1,326,000,000

764,000,000

562,000,000

1,034,000,000

912,000,000

122,000,000

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

(18,000,000)

Preferred Stock, Redemption Amount

6,934,000,000

293,000,000

33,000,000

(190,000,000)

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

$ 922,000,000

922,000,000

$ 0

(7,000,000)

Allocated Share-based Compensation Expense, Net of Tax

6,934,000,000

293,000,000

33,000,000

107,000,000

315,000,000

61,000,000

187,000,000

152,000,000

139,000,000

Temporary Equity, Other Changes

(157,000,000)

Dividends, Common Stock, Cash

(1,172,000,000)

1,172,000,000

(277,000,000)

(179,000,000)

(169,000,000)

(54,000,000)

(63,000,000)

Common stock | Successor [Member]

3,000,000

3,000,000

Additional Paid in Capital | Successor [Member]

3,835,000,000

Common stock | Successor [Member]

3,000,000

3,000,000

Additional Paid in Capital | Successor [Member]

$ 3,835,000,000

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

4,439,000,000

3,838,000,000

^[2]

636,000,000

(35,000,000)

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

Net income | Successor [Member]

(61,000,000)

(61,000,000)

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

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

$ 27,612,000,000

$ 18,794,000,000

$ (2,327,000,000)

$ 12,030,000,000

$ (2,660,000,000)

$ 1,775,000,000

$ 0

2,848,000,000

$ 1,421,000,000

$ 1,427,000,000

$ 2,848,000,000

$ 0

958,778

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

$ 25,837,000,000

3,415,000,000

$ 2,473,000,000

$ 941,000,000

$ 1,000,000

8,725,000,000

$ 1,588,000,000

6,150,000,000

(1,639,000,000)

2,626,000,000

2,848,000,000

2,300,000,000

$ 1,309,000,000

$ 991,000,000

1,326,000,000

$ 764,000,000

$ 562,000,000

1,034,000,000

$ 912,000,000

$ 122,000,000

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

1,251,000,000

Payments to Acquire Businesses, Gross | Successor [Member]

62,000,000

^[3]

$ 62,000,000

$ 33,000,000

Payments to Acquire Businesses, Gross | Successor [Member]

$ 62,000,000

^[3]

$ 62,000,000

$ 33,000,000

Members' Equity | Successor [Member]

158,000,000

$ 158,000,000

8,016,000,000

8,077,000,000

$ (61,000,000)

$ 0

$ 11,482,000,000

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

2,626,000,000

$ (378,000,000)

$ 378,000,000

^[4]

400,000,000

18,794,000,000

2,473,000,000

1,588,000,000

1,421,000,000

1,309,000,000

764,000,000

912,000,000

Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent | Successor [Member]

6,150,000,000

35,000,000

Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent | Successor [Member]

$ 18,794,000,000

$ 2,473,000,000

1,588,000,000

$ 1,421,000,000

$ 1,309,000,000

$ 764,000,000

$ 912,000,000

$ 35,000,000

Significant Accounting Policies (All Registrants)

$ 6,150,000,000

[1]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[2]	At March 23, 2016 and December 31, 2015, PHI's (predecessor) shareholders' equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million and $3 million of common stock, respectively.
[3]	he liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 4 — Mergers, Acquisitions, and Dispositions.
[4]	Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed by PHI to Exelon.

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2014 USD ($)
Other comprehensive income, income taxes	$ 412
Exelon Generation Co L L C [Member]
Other comprehensive income, income taxes	157
PECO Energy Co [Member]
Other comprehensive income, income taxes	$ 0

Significant Accounting Policies

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Description of Business (All Registrants)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and transmission businesses. Prior to March 23, 2016, Exelon's principal, wholly owned subsidiaries included Generation, ComEd, PECO and BGE. On March 23, 2016, in conjunction with the Amended and Restated Agreement and Plan of Merger (the PHI Merger Agreement), Purple Acquisition Corp, a wholly owned subsidiary of Exelon, merged with and into PHI, with PHI continuing as the surviving entity as a wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in the energy distribution and transmission businesses. Refer to Note 4 - Mergers, Acquisitions, and Dispositions for further information regarding the merger transaction.

The energy generation business includes:


•	Generation: Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation. Generation also sells renewable energy and other energy-related products and services. 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 electric distribution and transmission services in northern Illinois, including the City of Chicago.


•	PECO: Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.


•	BGE: Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas distribution services in central Maryland, including the City of Baltimore.


•	Pepco: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.


•	DPL: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.


•	ACE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southern New Jersey.

Basis of Presentation (All Registrants)

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

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

Pursuant to the acquisition of PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016, acquisition date. Exelon has accounted for the merger transaction applying the acquisition method of accounting, which requires the assets acquired and liabilities assumed by Exelon to be reported in Exelon’s financial statements at fair value, with any excess of the purchase price over the fair value of net assets acquired reported as goodwill. Exelon has pushed-down the application of the acquisition method of accounting to the consolidated financial statements of PHI such that the assets and liabilities of PHI are similarly recorded at their respective fair values, and goodwill has been established as of the acquisition date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016, acquisition date reflect different bases of accounting, and the financial positions and the results of operations of the predecessor and successor periods are not comparable. The acquisition method of accounting has not been pushed down to PHI’s wholly-owned subsidiary utility registrants, Pepco, DPL and ACE.

For financial statement purposes, beginning on March 24, 2016, disclosures that had solely related to PHI, Pepco, DPL or ACE activities now also apply to Exelon, unless otherwise noted.

Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. 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.

PHISCO, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated pursuant to service agreements among PHI Service Company and the participating operating subsidiaries.

Exelon owns 100% of all of its significant consolidated subsidiaries, including PHI, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%. As of December 31, 2016, Exelon owned none of BGE's preferred securities, which BGE redeemed in 2016. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2016 and December 31, 2015, as equity, 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. PHI is subject to some ring-fencing measures established by orders of the DCPSC, DPSC, MDPSC and NJBPU, pursuant to which all of the membership interest in PHI is held directly by PH Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (PH Utility), Inc., an unrelated party, holds a nominal non-economic interest in PH Holdco LLC with limited voting rights on specified matters. PHI owns 100% of its subsidiaries including Pepco, DPL and ACE.

Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain variable interest entities, including CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for further discussion of Exelon’s and Generation’s consolidated VIEs.

The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which the Registrant can exercise control over the operations and policies of the investee, or the results of a model that identifies the Registrant or one of its subsidiaries as the primary beneficiary of a VIE. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or cost method accounting is applied. The Registrants apply proportionate consolidation when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation, the Registrants separately record their proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd, PECO and BGE. Under the equity method, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the entity as single line items in their financial statements. The Registrants use the cost method if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under the cost method, the Registrants report their investments at cost and recognize income only to the extent dividends or distributions are received.

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

Use of Estimates (All Registrants)

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

Reclassifications (All Registrants)

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.

Certain prior year amounts in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows of PHI, Pepco, DPL and ACE have been reclassified to conform the presentation of these amounts to the current period presentation in Exelon’s financial statements. Most significantly for PHI, Pepco, DPL and ACE, current regulatory assets and liabilities have been presented separately from the non-current portions in each respective Consolidated Balance Sheet where recovery or refund is expected within the next 12 months. Additionally, for PHI, Pepco, DPL and ACE, the removal cost within Accumulated depreciation was reclassified to the Regulatory liability or Regulatory asset account to align with Exelon’s presentation. The reclassifications were not considered errors in the prior financial statements.

Accounting for the Effects of Regulation (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

The Registrants apply the authoritative guidance for accounting for certain types of regulation, which requires them 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 and the Utility Registrants account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, the MDPSC, the DCPSC, the DPSC and the NJBPU, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. Exelon and the Utility Registrants continue to evaluate their respective abilities to continue 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 the Registrants' business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3 — Regulatory Matters for additional information.

ACE has a recovery mechanism for purchased power costs associated with BGS. ACE records a deferred energy supply costs regulatory asset or regulatory liability for under or over-recovered costs that are expected to be recovered from or refunded to ACE customers, respectively. In the first quarter of 2016, ACE changed its method of accounting for determining under or over-recovered costs in this recovery mechanism to include unbilled revenues in the determination of under or over-recovered costs. ACE believes this change is preferable as it better reflects the economic impacts of dollar-for-dollar cost recovery mechanisms. ACE applied the change retrospectively. The impact of the change was a $12 million reduction to ACE’s opening Retained earnings as of January 1, 2014 with a corresponding reduction to Regulatory assets. The impact of the change on Net income attributable to common shareholder was an increase of $2 million and $1 million for the years ended December 31, 2015 and December 31, 2014, respectively.

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 (All Registrants)

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, Pepco, DPL and ACE record their best estimate of the transmission revenue impacts resulting from changes in rates that they each believe are probable of approval by FERC in accordance with their formula rate mechanisms. 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. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 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 Consolidated Statements of Operations and Comprehensive Income. 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 (All Registrants)

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) and recognize penalties related to unrecognized tax benefits in Other, net on their Consolidated Statements of Operations and Comprehensive Income.

In the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting for classification of interest on uncertain tax positions. PHI, Pepco, DPL and ACE have reclassified interest on uncertain tax positions as Interest expense from Income tax expense in the Consolidated Statements of Operations and Comprehensive Income. GAAP does not address the preferability of one acceptable method of accounting over the other for the classification of interest on uncertain tax positions. However, PHI, Pepco, DPL and ACE believe this change is preferable for comparability of their financial statements with the financial statements of the other Registrants in the combined filing, for consistency with FERC classification and for a more appropriate representation of the effective tax rate as they manage the settlement of uncertain tax positions and interest expense separately. PHI, Pepco, DPL and ACE applied the change retrospectively. The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2015 is $34 million and $4 million for PHI and Pepco, respectively, and for the year ended December 31, 2014 is $1 million for both Pepco and ACE. The impact on all other PHI Registrants for years ended December 31, 2015 and December 31, 2014 is less than $1 million.

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 (All Registrants)

The Registrants collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 25 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes that are presented on a gross basis.

Cash and Cash Equivalents (All Registrants)

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

Restricted Cash and Cash Equivalents (All Registrants)

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2016 and 2015, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Generation’s restricted cash and cash equivalents primarily included cash at various project-specific non-recourse financing structures for debt service and financing of operations of the underlying entities, see Note 14 - Debt and Credit Agreements for additional information on Generation’s project- specific financing structures. ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. 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. PHI Corporate's restricted cash and cash equivalents primarily represented funds restricted for the payment of merger commitments and cash collateral held from its utility suppliers. Pepco's restricted cash and cash equivalents primarily represented funds restricted for the payment of merger commitments and collateral held from its utility suppliers. DPL's restricted cash and cash equivalents primarily represented cash collateral held from suppliers associated with procurement contracts. ACE's restricted cash and cash equivalents primarily represented funds restricted at its consolidated variable interest entity for repayment of transition 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, 2016 and 2015, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2016, Exelon, Generation, ComEd, PECO, BGE, PHI and Pepco had investments in Rabbi trusts classified as noncurrent assets.

Allowance for Uncollectible Accounts (All Registrants)

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. At December 31, 2015, Pepco, DPL and ACE estimated the allowance for uncollectible accounts based on specific identification of material amounts at risk by customer and maintained a reserve based on their historical collection experience. At December 31, 2016, Pepco, DPL and ACE aligned the estimation of their allowance for uncollectible accounts to be consistent with ComEd, PECO and BGE, as described above. Risk segments represent a group of customers with similar credit quality indicators that are comprised 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. Utility Registrants 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. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC, DPSC and NJBPU regulations. See Note 3 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.

Variable Interest Entities (All Registrants)

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 has a controlling financial interest, meaning (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.

See Note 2 — Variable Interest Entities for additional information.

Inventories (All Registrants)

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

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

Materials and Supplies. Materials and supplies inventory generally includes 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, at weighted average cost 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 charged to purchased power and fuel expense at weighted average cost as they are used in operations.

Marketable Securities (All Registrants)

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 3 — Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 12 — Fair Value of Financial Assets and Liabilities and Note 16 — Asset Retirement Obligations for information regarding marketable securities held by NDT funds.

Property, Plant and Equipment (All Registrants)

Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated property at ComEd, PECO, BGE, Pepco, DPL and ACE. 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 the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, plant and equipment. DOE SGIG funds reimbursed to PECO, BGE, Pepco and ACE have been accounted for as CIAC.

For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite 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 the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. The Utility Registrants' depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility’s regulatory recovery method. The Utility Registrants' 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.

See Note 7 — Property, Plant and Equipment, Note 10 — Jointly Owned Electric Utility Plant and Note 25 — 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. Certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 24 — 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. As of December 31, 2016 and 2015, Generation has capitalized $1.7 billion and $1.3 billion, respectively, to Property, plant and equipment,net on its Consolidated Balance Sheets. 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 $30 million, $22 million and $13 million of costs were expensed by Exelon and Generation for the years ended December 31, 2016, 2015, and 2014, respectively. These costs are primarily related to the possible development of new power generating facilities with the exception of approximately $13 million of costs expensed in 2016 which relate to projects for which completion is no longer probable.

Capitalized Software Costs (All Registrants)

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		Pepco			DPL		ACE
December 31, 2016	$	808	$	173	$	213	$	91	$	164	$	1		$	1	$	1
December 31, 2015	633		180		172		86		178		—			1		1

Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO		BGE		Pepco			DPL		ACE
2016	$	255	$	72	$	62	$	33	$	44	$	—		$	—	$	—
2015	208		73		47		33		46		(2		)	—		—
2014	186		59		45		28		43		2			—		—



	Successor		Predecessor
PHI	December 31, 2016		December 31, 2015
Net unamortized software costs	$	153	$	172

	Successor		Predecessor
PHI	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015		For the Year Ended December 31, 2014
Amortization of capitalized software costs	$	29	$	8	$	36	$	30

Depreciation, Depletion and Amortization (All Registrants)

Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method in which depreciation is calculated using the average estimated service life of assets within a group. The Utility Registrants' depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. The estimated service lives for the Utility Registrants are primarily based on each company's most recent depreciation studies of historical asset retirement and removal cost experience. At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated service lives of its generating facilities. For its nuclear generating facilities, except for Oyster Creek and Clinton, Generation estimates each unit will operate through the full term of its initial 20-year operating license renewal period. See Note 9 - Early Nuclear Plant Retirements for additional information on the impacts of expected and potential early plant retirements. The estimated service lives of Generation's hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of 40 years.

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

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

Amortization of income tax related regulatory assets and liabilities are 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 25 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of the Utility Registrants' regulatory assets.

Asset Retirement Obligations (All Registrants)

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 future cash flow models and discount rates. Generation generally updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various decommissioning 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 unless circumstances warrant more frequent updates. 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 estimated 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 Utility Registrants' accretion, through an increase to regulatory assets. See Note 16 — Asset Retirement Obligations for additional information.

Capitalized Interest and AFUDC (All Registrants)

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, BGE, PHI, Pepco, DPL and ACE 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		Pepco		DPL		ACE
2016	Total incurred interest^(b)	$	1,678	$	472	$	469	$	127	$	114	$	137	$	52	$	65
	Capitalized interest	108		107		—		—		—		—		—		—
	Credits to AFUDC debt and equity	98		—		22		11		30		29		7		9
2015	Total incurred interest^(b)	$	1,170	$	445	$	336	$	116	$	113	$	131	$	51	$	65
	Capitalized interest	79		79		—		—		—		—		—		—
	Credits to AFUDC debt and equity	44		—		9		7		28		19		2		2
2014	Total incurred interest^(b)	$	1,144	$	419	$	323	$	115	$	118	$	121	$	49	$	65
	Capitalized interest	63		63		—		—		—		—		—		—
	Credits to AFUDC debt and equity	37		—		5		8		24		16		3		2



	Successor		Predecessor
PHI	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015		For the Year Ended December 31, 2014
Total incurred interest^(b)	$	207	$	68	$	289	$	277
Credits to AFUDC debt and equity	35		10		23		21

_______________________


(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 (All Registrants)

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

The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 24 — Commitments and Contingencies for additional information.

Asset Impairments (All Registrants)

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, ComEd’s and PHI'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.

Derivative Financial Instruments (All Registrants)

All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. 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 AOCI 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, except for the Utility Registrants where changes in fair value may be recorded as a regulatory asset or liability if there is an ability to recover or return the associated costs. See Note 3 — Regulatory Matters and Note 13 — Derivative Financial Instruments for additional information. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the Consolidated Statements of Operations and Comprehensive Income 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 Statements of Operations and Comprehensive Income. 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 March 2012 merger of Exelon and Constellation. Because the underlying forecasted transactions at that time remained probable, the fair value of the effective portion of these cash flow hedges was frozen in AOCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred through March 31, 2015. Accordingly, 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 (All Registrants)

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

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and inputs 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 Consolidated Statements of Operations and Comprehensive Income. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 17 — Retirement Benefits for additional information.

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 the cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment.

New Accounting Standards (All Registrants)

New Accounting Standards Adopted: in 2016 the Registrants have adopted the following new authoritative accounting guidance issued by the FASB. Unless otherwise indicated, adoption of the guidance in each instance had no or insignificant impacts on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows and disclosures.

Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (Issued May 2015; Adopted first quarter 2016 retrospectively to all prior periods presented): 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, and instead provides for such investments to be disclosed as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. See Note 12 - Fair Value of Financial Assets and Liabilities for the disclosure impacts.

Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement (Issued April 2015; Adopted first quarter 2016 prospectively): 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 operate 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.

Amendments to the Consolidation Analysis (Issued February 2015; Adopted January 1, 2016): Amends the consolidation analysis for variable interest entities (VIEs) and voting interest entities. The new guidance primarily (1) changes the VIE assessment of limited partnerships, (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 Registrants did not revise any consolidation conclusions as a result of the guidance, but did identify additional entities that are now considered VIEs. See Note 2 - Variable Interest Entities for the associated disclosures.

Simplifying the Transition to the Equity Method of Accounting (Issued March 2016; Early adopted fourth quarter 2016): Eliminates the requirement to retroactively adopt the equity method of accounting as a result of an increase in the level ownership or degree of influence of an existing investment. Instead, an investor now adds the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopts the equity method of accounting as of the date the investment qualifies for such treatment.

Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (Issued March 2016; Early adopted fourth quarter 2016 prospectively): Clarifies that a change in the counterparty of a derivative contract does not, in and of itself, require dedesignation of that hedge accounting relationship as long as all of the other hedge accounting criteria are met.

Simplifying the Measurement of Inventory (Issued July 2015; Early adopted fourth quarter 2016 prospectively): Requires inventory to be measured at the lower of cost or net realizable value, with net realizable value defined 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.

Contingent Put and Call Options in Debt Instruments (Issued March 2016; Adopted January 1, 2017 on a modified retrospective basis): Simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess whether a contingent event is related to interest rates or credit risks. The guidance clarifies that a contingent put or call option embedded in a debt instrument would be evaluated for possible separate accounting as a derivative instrument without regard to the nature of the exercise contingency. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments.

Interests Held through Related Parties that are Under Common Control (Issued October 2016; Adopted January 1, 2017 on a retrospective basis to January 1, 2016): Requires consideration of indirect interests held through related parties under common control proportionately when determining whether an entity is the primary beneficiary of a variable interest entity.

Improvements to Employee Share-Based Payment Accounting (Issued March 2016; Adopted January 1, 2017 using either the prospective, modified retrospective, or retrospective method as prescribed by the standard): Simplifies various aspects of how share-based payment awards to employees are accounted for and presented in the financial statements. The new guidance eliminates additional paid-in capital pools and requires excess tax benefits and tax deficiencies to be recorded in the Statement of Operations and Comprehensive Income.

New Accounting Standards Issued and Not Yet Adopted: The following new authoritative accounting guidance issued by the FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements. Unless otherwise indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation such standards will not significantly impact the Registrants' financial reporting.

Revenue from Contracts with Customers (Issued May 2014 and subsequently amended to address implementation questions): Changes the criteria for recognizing revenue from a contract with a customer. The new revenue recognition guidance, including subsequent amendments, is effective for annual reporting periods beginning on or after December 15, 2017, with the 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.

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. In addition, the Registrants will be required to capitalize costs to acquire new contracts, and amortize such costs in a manner consistent with the transfer to the customer of the associated goods or services. Exelon currently expenses those costs as incurred. 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 continue to assess 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. In performing this assessment, the Registrants have utilized a project implementation team comprised of both internal and external resources to conduct the following key activities:


•	Actively participate in the AICPA Power and Utilities Industry Task Force (Industry Task Force) process to identify implementation issues and support the development of related implementation guidance;


•	Evaluate existing contracts and revenue streams for potential changes in the amounts and timing of recognizing revenues under the new guidance;


•	Evaluate and select the transition method; and


•	Develop and implement the approach and process for complying with the new revenue recognition disclosure requirements.

While there continues to be some ongoing activities in all of these areas, the Registrants have substantially completed the evaluation of their collective contracts and revenue streams, as well as the evaluation of the transition method. Based on the work completed thus far, the Registrants have reached the following preliminary conclusions:


•	The Registrants expect to apply the new guidance using the full retrospective method, however this conclusion could change based on the outcome of open implementation issues discussed below;


•	The Registrants currently anticipate that the implementation of the new guidance will not have a material impact on the amount and timing of revenue recognition; and


•	The Registrants expect the new guidance will result in more detailed disclosures of revenue compared to current guidance.

Notwithstanding the preliminary conclusions noted above, certain implementation issues continue to be debated and worked through the Industry Task Force process that could result in amendments to the standard or implementation guidance that could have a material impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The open implementation issues that could be most impactful to the Registrants include: (1) the ability of the Utility Registrants to recognize revenue for certain contracts where collectability is in question, (2) the accounting by the Utility Registrants for contributions in aid of construction (CIAC) and whether CIAC arrangements are within the scope of the revenue guidance and (3) primarily at Generation, bundled sales contracts and contracts with pricing provisions that may require recognition of revenue at prices other than the contract price (e.g., straight line or estimated future market prices). As part of the overall implementation project, the Registrants are developing alternative adoption plans that would be implemented in the event the ultimate resolution of the open implementation issues result in significant changes from current revenue recognition practices.

Leases (Issued February 2016): Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The guidance requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only financing type lease liabilities (capital leases) are recognized in the balance sheet. This is expected to require significant changes to systems, processes and procedures in order to recognize and measure leases recorded on the balance sheet that are currently classified as operating leases. In addition, the definition of a lease has been revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in changes to the classification of an arrangement as a lease. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly changed from current GAAP. The accounting applied by a lessor is largely unchanged from that applied under current GAAP. The standard is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted, however the Registrants do not expect to early adopt the standard. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. Refer to Note 24 — Commitments and Contingencies for additional information regarding operating leases.

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

Goodwill Impairment (issued January 2017): Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, ComEd, Generation, and DPL have goodwill as of December 31, 2016. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1, 2020, with early adoption permitted, and must be adopted on a prospective basis.

Clarifying the Definition of a Business (issued January 2017): Clarifies the definition of a business with the objective of addressing whether acquisitions should be accounted for as acquisitions of assets or as acquisitions of businesses. If substantially all the fair value of the assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities is not a business. If the fair value of the assets acquired is not concentrated in a single identifiable asset or a group of similar identifiable assets, then an entity must evaluate whether an input and a substantive process exist, which together significantly contribute to the ability to produce outputs. The standard also revises the definition of outputs to focus on goods and services to customers. The standard could result in more acquisitions being accounted for as asset acquisitions. The standard will be effective January 1, 2018 and will be applied prospectively.

Intra-Entity Transfers of Assets Other Than Inventory (Issued October 2016): Requires entities to recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs (compared to current GAAP which prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party). The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.

Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Issued August 2016) and Restricted Cash (Issued November 2016): In 2016, the FASB issued two standards impacting the Statement of Cash Flows. The first adds or clarifies guidance on the classification of certain cash receipts and payments on the statement of cash flows as follows: debt prepayment or extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies and bank-owned life insurance policies, distributions received from equity method investees, beneficial interest in securitization transactions, and the application of the predominance principle to separately identifiable cash flows. The second states that amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows (instead of being presented as cash flow activities). Exelon will adopt both standards on January 1, 2018 on a retrospective basis. Adoption of the second standard will result in a change in presentation of restricted cash on the face of the Statement of Cash Flows; otherwise the Registrants expect that adoption of the guidance will have insignificant impacts on the Registrants’ Consolidated Statements of Cash Flows and disclosures.

Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016): (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).

Variable Interest Entities (All Registrants)

12 Months Ended

Dec. 31, 2016

Variable Interest Entity [Abstract]

Variable Interest Entity Disclosure [Text Block]

Variable Interest Entities (All Registrants)

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

At December 31, 2016, Exelon, Generation, BGE, PHI, and ACE collectively consolidated nine VIEs or VIE groups, for which the applicable Registrant was the primary beneficiary. At December 31, 2015, Exelon, Generation and BGE collectively had seven consolidated VIEs or VIE groups and PHI and ACE had one consolidated VIE (see Consolidated Variable Interest Entities below). As of December 31, 2016 and December 31, 2015, Exelon and Generation collectively had significant interests in eight other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated Variable Interest Entities below).

Consolidated Variable Interest Entities

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at December 31, 2016 and December 31, 2015 are as follows:



	December 31, 2016										December 31, 2015
							Successor										Predecessor
	Exelon ^(a)(b)		Generation		BGE		PHI ^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Current assets	$	954	$	916	$	23	$	14	9		$	909	$	881	$	23	$	12	$	12
Noncurrent assets	8,563		8,525		3		35		23		8,009		8,004		3		18		18
Total assets	$	9,517	$	9,441	$	26	$	49	$	32	$	8,918	$	8,885	$	26	$	30	$	30
Current liabilities	$	885	$	802	$	42	$	42	37		$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities	2,713		2,612		—		101		89		2,927		2,884		41		124		124
Total liabilities	$	3,598	$	3,414	$	42	$	143	$	126	$	3,400	$	3,271	$	122	$	172	$	172

_______________________

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

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

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

Exelon's, Generation's, BGE's, PHI's and ACE'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 2016, 2015 and 2014, BGE remitted $86 million, $86 million and $85 million, respectively, to BondCo.

BGE did not provide any additional financial support to BondCo during 2016. 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.

ACE Transition Funding. A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds. Proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three years ended December 31, 2016, 2015 and 2014, ACE transferred $60 million, $61 million and $55 million to ATF, respectively.

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 and provides limited recourse to other third-party suppliers and customers in support of the retail gas 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 there is limited recourse related to Generation related to certain solar entities. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $568 million, as of December 31, 2016, 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 $21 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs do not have a material impact on Generation’s financial results or financial condition.

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.

In December 2016, Generation sold approximately 71% of its equity interest in one of its wind projects that was previously consolidated under the voting interest model to a tax equity investor. The wind project was evaluated and it was determined to be a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. While Generation is the minority interest holder, Generation is the primary beneficiary, because Generation manages the day-to-day activities of the entity. Therefore, the entity continues to be consolidated by Generation.

While Generation owns 100% of the majority of the wind project entities, six of the projects have noncontrolling equity interests of 1% held by third parties and one of the projects has noncontrolling equity interests of approximately 71%. Regarding the projects with noncontrolling equity interests of 1% held by third parties, Generation’s current economic interests in five 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. Generation provides operating and capital funding to the wind project entities for ongoing construction, operations and maintenance of the wind power and there is limited recourse to Generation related to certain wind project entities. However, no additional support to these projects beyond what was contractually required has been provided during 2016. As of December 31, 2016, 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 in support of one of its other generating facilities (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 interests 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.

Generation and Exelon, where indicated, provide the following support to CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC and Note 27—Related Party Transactions for additional information regarding Generation's 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 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, 2016, the remaining obligation is $316 million, including accrued interest, which reflects the principal payment made in January 2015,

•

Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. (See Note 24 — Commitments and Contingencies for more details),


•	in connection with CENG’s severance obligations, Generation reimbursed CENG for a total of approximately $6 million of the severance benefits paid from 2014 through 2016. The final reimbursement was made in 2016, and there was no remaining obligation as of December 31, 2016.


•	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,


•	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 24 — 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.

2015 ESA Investco, LLC. 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. 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 up to a total of $250 million of equity incrementally from inception through the first quarter of 2017 in proportion to their ownership interests, which is up to $172 million for the tax equity investor and up to $78 million for Generation (see Note 24— Commitments and Contingencies for more details). 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 (see additional details in the Unconsolidated Variable Interest Entities section below). As of December 31, 2015, Generation consolidated 2015 ESA Investco, LLC under the voting interest model. Pursuant to the new consolidation guidance effective January 1, 2016, 2015 ESA Investco, LLC meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. Under VIE guidance, Generation is the primary beneficiary; therefore, the entity continues to be consolidated.

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, BGE, PHI and ACE did not provide any additional material financial support to the VIEs;


•	Exelon, Generation, BGE, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and


•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, BGE’s, PHI's or ACE's general credit.

As of December 31, 2016 and December 31, 2015, ComEd, PECO, Pepco and DPL do not have any material consolidated VIEs.

Assets and Liabilities of Consolidated VIEs

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of December 31, 2016 and December 31, 2015, these assets and liabilities primarily consisted of the following:



		December 31, 2016										December 31, 2015
								Successor										Predecessor
		Exelon ^(a)(b)		Generation		BGE		PHI ^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents		$	150	$	150	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash		59		27		23		9		9		100		77		23		12		12
Accounts receivable, net
	Customer	371		371		—		—		—		219		219		—		—		—
	Other	48		48		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets		31		31		—		—		—		140		140		—		—		—
Inventory
	Materials and supplies	199		199		—		—		—		181		181		—		—		—
Other current assets		50		44		—		5		—		35		30		—		—		—
	Total current assets	908		870		23		14		9		882		854		23		12		12

Property, plant and equipment, net		5,415		5,415		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds		2,185		2,185		—		—		—		2,036		2,036		—		—		—
Goodwill		47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets		23		23		—		—		—		53		53		—		—		—
Other noncurrent assets		315		277		3		35		23		90		85		3		18		18
	Total noncurrent assets	7,985		7,947		3		35		23		7,386		7,381		3		18		18
	Total assets	$	8,893	$	8,817	$	26	$	49	$	32	$	8,268	$	8,235	$	26	$	30	$	30

Long-term debt due within one year		$	181	$	99	$	41	$	40	$	35	$	111	$	27	$	79	$	46	$	46
Accounts payable		269		269		—		—		—		216		216		—		—		—
Accrued expenses		119		116		1		2		2		115		113		2		2		2
Mark-to-market derivative liabilities		60		60		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities		15		15		—		—		—		12		12		—		—		—
Other current liabilities		30		30		—		—		—		13		13		—		—		—
	Total current liabilities	674		589		42		42		37		472		386		81		48		48

	Long-term debt	641		540		—		101		89		666		623		41		124		124
	Asset retirement obligations	1,904		1,904		—		—		—		1,999		1,999		—		—		—
	Pension obligation^(c)	9		9		—		—		—		9		9		—		—		—
	Unamortized energy contract liabilities	22		22		—		—		—		39		39		—		—		—
	Other noncurrent liabilities	106		106		—		—		—		79		79		—		—		—
	Noncurrent liabilities	2,682		2,581		—		101		89		2,792		2,749		41		124		124
	Total liabilities	$	3,356	$	3,170	$	42	$	143	$	126	$	3,264	$	3,135	$	122	$	172	$	172

___________

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

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

(c) 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, 2016 and 2015, Exelon and Generation had significant unconsolidated variable interests in eight VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. Exelon and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Generation has several individually immaterial VIEs that in aggregate represent a total investment of $18 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $18 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets.

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



December 31, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	638	$	567	$	1,205
Total liabilities^(a)	215		287		502
Exelon's ownership interest in VIE^(a)	—		248		248
Other ownership interests in VIE^(a)	423		32		455
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		264		264
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	9		—		9



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

___________________


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

(b)

These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $113 million and $206 million as of December 31, 2016 and December 31, 2015, respectively; offset by payables to ZionSolutions LLC of $104 million and $189 million as of December 31, 2016 and December 31, 2015, 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.

The Registrants' unconsolidated VIEs consist of:

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

ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 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 $85 million and was paid incrementally over an approximate two year period (see Note 24 - Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and was recorded as an equity method investment. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, the distributed energy company meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights of the general partner. (For additional details related to the new consolidation guidance, see Note 1 - Significant Accounting Policies.) Generation is not the primary beneficiary; therefore, the investment continues to be recorded using the equity method.

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 up to a total of $250 million of equity incrementally through the first quarter of 2017 in proportion to their ownership interests, which is up to $172 million for the tax equity investor and up to $78 million for Generation (see Note 24 - 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. See additional details in the Consolidated Variable Interest Entities section above.

Both distributed energy companies from the 2015 and 2014 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 (All Registrants)

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

Regulatory Matters (All Registrants)

3. Regulatory Matters (All Registrants)

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 formula rate, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities to modernize Illinois’ electric utility infrastructure.

Participating utilities are required to file an annual update to the performance-based formula rate on or before May 1, with resulting rates effective in January of the following year. This annual electric distribution 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 revenues 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, 2016, and December 31, 2015, ComEd had a regulatory asset associated with the electric distribution formula rate of $188 million and $189 million, respectively. The regulatory asset associated with electric distribution formula rate is amortized to Operating revenues 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, 2016, 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 through 2018. To date, approximately three 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 contributed $10 million annually through 2016 to fund customer assistance programs for low-income customers, which are not 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 Electric Distribution Filings	2016				2015				2014
ComEd's requested total revenue requirement increase (decrease)	$	138			$	(50	)		$	269

Final ICC Order
Initial revenue requirement increase	$	134			$	85			$	160
Annual reconciliation (decrease) increase	(7		)		(152		)		72
Total revenue requirement increase (decrease)	$	127		^(a)	$	(67	)		$	232

Allowed Return on Rate Base:
Initial revenue requirement	6.71		%		7.05		%		7.06		%
Annual reconciliation	6.69		%		7.02		%		7.04		%
Allowed ROE:
Initial revenue requirement	8.64		%		9.14		%		9.25		%
Annual reconciliation	8.59		%	^(b)	9.09		%	^(b)	9.20		%	^(b)

Effective date of rates	January 2017				January 2016				January 2015

__________________

(a) On December 20, 2016, the ICC granted ComEd's and other parties' joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014 and 2015 has on the revenue requirement approved in this order. ComEd has proposed that the 2016 total electric distribution revenue requirement be reduced by $18 million which would be refunded to customers in 2017.

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

Illinois Future Energy Jobs Act (Exelon, Generation, and ComEd).

Background

On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA is effective June 1, 2017, and includes, among other provisions, (1) a ZES providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates exceeds specified limits, (6) revisions to the existing net metering statute to (i) mandate net metering for community generation projects, and establish billing procedures for subscribers to those projects, (ii) provide immediately for netting at the energy-only rate for nonresidential customers, and (iii) transition from netting at the full retail rate to the energy-only rate for certain residential net metering customers once the net meter customer load equals 5% of total peak demand supplied in the previous year and (7) support for low income rooftop and community solar programs.

Zero Emission Standard

FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria. ZES will have a 10-year duration extending through May 31, 2027. Eligible generators may participate in a procurement event overseen by the Illinois Power Agency and selected generators will directly contract with Illinois utilities for the procurement of the ZECs based upon the number of MWh produced by the eligible facilities, subject to specified annual caps. The ZEC price will be based upon the current social cost of carbon as determined by the federal government and is initially established at $16.50 per MWh of production, subject to future adjustments based on specified escalation and pricing adjustment mechanisms designed to lower the ZEC price based on increases in underlying energy and capacity prices.

Illinois utilities, including ComEd, will be required to purchase from eligible nuclear facilities an amount of ZECs equivalent to 16% of the actual amount of electricity delivered in 2014. ComEd will recover all costs associated with purchasing ZECs through a new rate rider, which will provide for an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from ComEd’s retail customers in subsequent periods.

See Note 9 - Early Nuclear Plant Retirements for the impacts of the provisions above on Generation’s Consolidated Balance Sheets and Consolidated Statements of Operations and Comprehensive Income. The provisions do not impact ComEd’s Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows until 2017.

ComEd Electric Distribution Rates

FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allows ComEd to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar, which will eliminate any unfavorable or favorable impacts of weather or load from ComEd’s electric distribution formula rate revenues beginning with the reconciliation filed in 2018 for the 2017 calendar year. ComEd will begin reflecting the impacts of this change in its electric distribution services costs regulatory asset or liability beginning in 2017.

FEJA requires ComEd to make non-recoverable contributions to low income energy assistance programs of $10 million per year for 5 years as long as the electric distribution formula rate remains in effect. With the exception of these contributions, ComEd will recover from customers, subject to certain caps explained below, the costs it incurs pursuant to FEJA either through its electric distribution formula rate or other recovery mechanisms.

Energy Efficiency

Existing Illinois law requires ComEd to implement cost-effective energy efficiency measures and, for a 10-year period ending May 31, 2018, cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.

Beginning January 1, 2018, FEJA provides for new cumulative annual energy efficiency MWh savings goals for ComEd, which are designed to achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared to the deemed baseline of 88 million MWhs of electric power and energy sales. FEJA, deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017. ComEd expects to spend approximately $250 million to $400 million annually from 2017 through 2030 to achieve these energy efficiency MWh savings goals. In addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017. FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017.

FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy efficiency costs (except for any voltage optimization costs which will be recovered through the electric distribution formula rate) as a separate regulatory asset that will be recovered through the energy efficiency formula rate over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd will earn a return on the energy efficiency regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same methodology applicable to ComEd’s electric distribution formula rate. Through December 31, 2030, the return on equity that ComEd earns on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd will be required to file an update to its energy efficiency formula rate on or before June 1 each year, with resulting rates effective in January of the following year. The annual update will be based on projected current year energy efficiency costs and the related projected year-end regulatory asset balance less any related deferred taxes. The update will also include a reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year costs and year-end energy efficiency regulatory asset balances less any related deferred taxes.

ComEd expects to cancel its existing energy efficiency rider, at which time it must perform a reconciliation of revenues and costs incurred through the cancellation date and issue a one-time credit on retail customers' bills for any over-recoveries. As of December 31, 2016, ComEd’s over-recoveries associated with its existing energy efficiency rider of $141 million were reflected in Current regulatory liabilities on Exelon’s and ComEd’s Consolidated Balance Sheets. As a result, ComEd expects to provide credits to customers in 2017 to address this over-recovery.

Renewable Portfolio Standard

Existing Illinois law requires ComEd to purchase each year an increasing percentage of renewable energy resources for the customers for which it supplies electricity. This obligation is satisfied through the procurement of renewable energy credits (RECs). FEJA revises the Illinois RPS to require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support for low-income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS collections. ComEd will recover all costs associated with purchasing RECs through rate riders, which will provide for a reconciliation and true-up to actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent periods. The first reconciliation and true-up for RECs will cover revenues and costs for the four year period beginning June 1, 2017 through May 31, 2021. Subsequently, the RPS rate rider will provide for an annual reconciliation and true-up.

Customer Rate Increase Limitations

FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows: (1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial retail customers during 2015.

By June 30, 2017, ComEd must submit a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential customers with a peak demand less than 10 MW. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year and a rolling 10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through the end of the preceding year and the average annual rate increase projected for the remainder of the 10-year period.

If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a corrective action plan to decrease future year costs to reduce customer rates to ensure future compliance. If the actual residential customer or nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC contracts and further initiate proceedings to reduce energy efficiency savings goals and terminate support for low-income rooftop and community solar programs. ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.

For the energy efficiency formula, ComEd will record a regulatory asset or liability and corresponding increase or decrease to Operating revenues 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. For the other rate riders to be established under FEJA, ComEd will record a regulatory asset or liability for any differences between revenues and incurred expenses. FEJA did not have any impacts on ComEd’s Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows in 2016.

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, 2016, ComEd has completed all required ICC-approved procurements as called for by the IPA Procurement Plan’s timeline.

Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). In accordance with legislation in effect on December 31, 2016, the IPA's Procurement Plans include the procurement of cost-effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation increases by at least 1.5% each year thereafter to 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, 2016, ComEd had purchased renewable energy resources or equivalents, such as RECs, in accordance with the IPA Procurement Plan. 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.

In accordance with FEJA that takes effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.

Grand Prairie Gateway Transmission Line (Exelon and 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 October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line. Elgin did not seek further review of the Illinois Appellate Court decision. 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 the necessary land rights across the project route through voluntary transactions. ComEd began construction of the line during 2015 with an expected in-service date of June 2017.

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. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. The order also directed 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 2015, the DOE suspended funding for the cost development of FutureGen. On January 13, 2016, FutureGen informed the Illinois Supreme Court that it had ceased all development efforts on the FutureGen project. In February 2016, FutureGen terminated its sourcing agreement with ComEd. On May 19, 2016, the Illinois Supreme Court dismissed the matter as moot. As a result, ComEd is under no further obligation under this agreement.

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, which included the approval of the In-Program Arrearage Forgiveness ("IPAF") Program. The approved electric delivery rates became effective on January 1, 2016.

The IPAF Program provides for forgiveness of a portion of the eligible arrearage balance of its low-income Customer Assistance Program (CAP) accounts receivable at program inception. The forgiveness will be granted to the extent CAP customers remain current over the duration of the five-year payment agreement term. 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 has been absorbed by PECO through bad debt expense on its Consolidated Statements of Operations. In October 2016, the IPAF was fully implemented. A regulatory asset of $11 million representing previously incurred bad debt expense associated with the eligible accounts receivable balances was recorded as of December 31, 2016.

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, as well as the low-income advocates and the Office of Consumer Advocate, appealed the Court's decision. On April 5, 2016, the Pennsylvania Supreme Court declined to accept the appeals. On May 11, 2016, the PAPUC issued a Secretarial Letter requiring PECO to propose a rule revision to the PECO CAP Shopping Plan consistent with the Court’s decision. On July 19, 2016, PECO filed a letter stating its intent to revise its Plan by September 1, 2016 to incorporate the rule revision. On September 1, 2016, PECO filed its proposed rule revision that is consistent with the Court’s opinion with a proposed effective date of April 14, 2017.

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 procured 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) moved to spot market pricing. In September 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the final 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, and subsequently implemented in October 2016 as planned.

On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019, in compliance with electric generation procurement guidelines set forth in Act 129. On October 4, 2016, the Administrative Law Judge recommended that PECO’s previously filed partial settlement be approved without modification. The settlement would extend the program period through May 2021 and consolidate the Medium Commercial and Large Commercial classes of default service customers into a Consolidated Large Commercial Class proposed by the Company. The issue of PECO’s implementation of CAP Shopping was reserved for briefing, and the Administrative Law Judge determined that issue was not a part of the DSP IV case. On December 8, 2016, the PAPUC approved the fourth DSP Program for a 48-month term and deferred CAP Shopping to another proceeding. OCA and Low Income Advocates subsequently filed a Petition for Reconsideration and Clarification, which is pending before the PAPUC.

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. As approved by the PAPUC, PECO accelerated its installation and deployed substantially all smart meters by December 31, 2015, for a total of 1.7 million smart meters. PECO spent $578 million and $155 million on smart meter and smart grid infrastructure, respectively, of which $200 million has been funded by SGIG. Recovery of smart meter costs are reflected in base rates effective January 1, 2016.

Energy Efficiency Programs (Exelon and PECO). 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. 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 were 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. On November 15 2016, PECO reported to the PAPUC that as of the conclusion of the EE&C Phase II Plan, all plan requirements have been met. A final Phase II compliance determination is expected to be issued in the first half of 2017.

On June 19, 2015, the PAPUC issued its Phase III EE&C implementation order 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.

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. The PAPUC approved PECO’s EE&C Phase III Plan, with requested clarifications, on May 19, 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

2016 Maryland Electric Distribution Base Rates (Exelon, PHI and Pepco). On November 15, 2016, the MDPSC approved an increase in electric distribution base rates of $53 million based on a ROE of 9.55%. The new rates became effective for services rendered on or after November 15, 2016. MDPSC also approved Pepco's recovery of substantially all of its capital investment and regulatory assets associated with its AMI program as part of the newly effective rates as well as a recovery over a five-year period of transition costs related to a new billing system implemented in 2015. As a result, during the fourth quarter of 2016, Exelon, PHI and Pepco established a regulatory asset of $13 million, wrote-off $3 million in disallowed AMI costs and recorded a pre-tax credit to net income for $10 million. Additionally, the MDPSC denied Pepco's request to extend its Grid Resiliency Program surcharge for new system reliability and safety improvement projects, with costs for such programs to be recovered going forward through base rates.

2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On July 20, 2016, DPL filed an application with the MDPSC requesting an increase of $66 million to its electric distribution base rates, which was later updated to $57 million, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of DPL's regulatory assets associated with its AMI program over a five year period, which was later modified to 10 years, supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the requested increase the MDPSC will approve. In addition to the proposed rate increase, DPL is proposing to continue its Grid Resiliency Program initially approved in September 2013 in connection with DPL's electric distribution rate case filed in February 2013. Under the Grid Resiliency Program, DPL is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In connection with the Grid Resiliency Program, DPL proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $4.6 million a year for two years for a total of $9.2 million. DPL cannot predict whether the MDPSC will approve a continuation of DPL's Grid Resiliency Program proposal.

2015 Maryland Electric and Natural Gas Distribution Base Rates (Exelon and BGE). On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas base rate increases with the MDPSC, ultimately requesting annual increases of $116 million and $78 million, respectively, of which $104 million and $37 million were related to recovery of electric and natural gas smart grid initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit fees through a surcharge.

On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude that BGE's smart grid initiative overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and adjustments, including not allowing BGE to defer or recover through a surcharge the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision associated with the Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearing of the June 3 order.

On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%, respectively. The new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC's July 29 order on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees.

On August 26, 2016, BGE filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC's order but with the Circuit Court for Baltimore City. On November 15, 2016, Baltimore County Circuit Court issued an order deciding that the cases should be consolidated and should proceed in Baltimore County Circuit Court. However, on January 9, 2017, BGE filed to withdraw its appeal of the MDPSC's orders and on January 10, 2017, the residential consumer advocate filed to withdraw its appeal as well. Refer to the Smart Meter and Smart Grid Investment disclosure below for further details on the impact of the ultimate disallowances contained in the orders to BGE.

Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to recover its cash working capital (CWC) requirement for its Provider of Last Resort service, also known as Standard Offer Service (SOS), as well as other components that make up the Administrative Charge, the mechanism that enables BGE to recover all of its SOS-related costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission accepted BGE positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a modest return on the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016, MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request for clarification and the residential consumer advocate request for rehearing.

2014 Maryland Electric and Gas Distribution Base Rates (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.

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

As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by evidence demonstrating that BGE had, in fact, implemented a cost-beneficial advanced metering system. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its customers. However, the June 3 order contained several cost disallowances and adjustments including disallowances of certain program and meter installation costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions and change certain of the cost disallowances and adjustments to enable BGE to defer those costs for recovery through future electric and natural gas rates. The residential consumer advocate also subsequently filed for a petition for rehearing of the June 3 order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed certain of its prior cost disallowances and adjustments related to the smart grid initiative. On August 26, 2016, BGE filed an appeal of the MDPSC's orders with the Circuit Court for Baltimore County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC's order but with the Circuit Court for Baltimore City. On November 15, 2016, Baltimore County Circuit Court issued an order deciding that the cases should be consolidated and should proceed in Baltimore County Circuit Court. However, on January 9, 2017, BGE filed to withdraw its appeal of the MDPSC's orders and on January 10, 2017, the residential consumer advocate filed to withdraw its appeal as well.

As a combined result of the MDPSC orders, BGE recorded a $52 million charge to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory assets and other long-lived assets. Pursuant to the combined MDPSC orders, BGE also reclassified $54 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory assets on Exelon's and BGE's Consolidated Balance Sheets as of December 31, 2016.

2013 Maryland Electric and Gas Distribution Base Rates (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and natural gas base increases with the MDPSC. In addition to these requested rate increases, BGE's application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE's proposed short-term reliability improvement plan (the ERI initiative) in response to a MDPSC order through a surcharge separate from base rates.

On December 13, 2013, the MDPSC issued an order authorizing 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. As of December 31, 2016, BGE has received approval of its updated surcharge filings three times for rates to be effective in 2014, 2015 and 2016.

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 natural 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 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. On March 7, 2016, the consumer advocate withdrew its appeal and no further action is expected.

MDPSC New Generation Contract Requirement (Exelon, Generation, BGE, PHI, Pepco and DPL). On April 12, 2012, the MDPSC issued an order that requires BGE, Pepco and DPL (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a competitive bidding process to build one new power plant in the range of 650 to 700 MWs beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in Waldorf, Maryland, with an expected commercial operation date of June 1, 2015, and each of the Contract EDCs was to recover its costs associated with the contract through surcharges on its respective SOS customers.

In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the District of Maryland issued a ruling that the MDPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit Court for Baltimore City upheld the MDPSC’s orders requiring the Contract EDCs to enter into the contracts.

On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. In November 2013 both the winning bidder and the MDPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the lower Federal court ruling. On November 26, 2014, both the winning bidder and the MDPSC petitioned the U.S. Supreme Court to consider hearing an appeal of the Fourth Circuit decision. On October 19, 2015, the U.S. Supreme Court agreed to review the decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit's ruling upholding the Federal district court's decision.

The decision of the Maryland Circuit Court was appealed to the Maryland Court of Special Appeals and was stayed pending decision by the U.S. Supreme Court. On August 1, 2016, the Contract EDCs submitted a filing requesting that the MDPSC take notice of the U.S. Supreme Court's decision, and notifying the MDPSC that the Contract EDCs will dismiss their appeal pending at the Maryland Court of Special Appeals. On September 14, 2016, the Maryland Court of Special Appeals dismissed the pending appeal and the matter is considered closed.

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 July 1, 2016, BGE filed an amendment to its infrastructure replacement plan, which the MDPSC conditionally approved in an order dated November 23, 2016. The revised surcharge reflecting the costs of the amendment became effective January 1, 2017. On December 2, 2016, BGE filed a surcharge update to be effective February 1, 2017, including a true-up of cost estimates included in the 2016 surcharge, along with its 2017 project list and projected capital estimates of $131 million to be included in the 2017 surcharge calculation. The MDPSC subsequently approved BGE's 2017 project list and the proposed surcharge for 2017, which included the 2016 surcharge true-up. As of December 31, 2016, BGE recorded a regulatory liability of $2 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. As the residential consumer advocate did not appeal the decision of the Court of Special Appeals, the matter is now closed.

Delaware Regulatory Matters

Gas Cost Rates. (Exelon, PHI and DPL) DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2016, DPL made its 2016-2017 GCR filing. The rates proposed in the 2016-2017 GCR filing would result in a GCR increase of approximately 14%. On September 20, 2016, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2016, subject to refund and pending final DPSC approval.

2016 Delaware Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed an application with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million and $22 million, respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases two months after filing the applications which were effective July 16, 2016. On December 1, 2016, the DPSC approved that an additional $30 million in electric distribution base rates be implemented effective December 17, 2016, subject to refund based on the final DPSC order, and an additional $10 million in gas base rates be implemented effective December 17, 2016, subject to refund based on the final DPSC order.

2013 Delaware Electric Distribution Base Rates (Exelon, PHI and DPL). In March 2013, and as amended on September 20, 2013, DPL filed for an electric distribution base rate increase with the DPSC, ultimately requesting an annual increase of $39 million.

In August 2014, the DPSC issued a final order in DPL's 2013 electric distribution rate case for an annual increase of $15 million and an ROE of 9.7%. Rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the Settlement Agreement related to the Merger, the parties agreed to suspend the appeal and, upon consummation of the Merger, to the withdrawal of the appeal and the cross-appeal with prejudice. In accordance with the settlement, on April 13, 2016, the parties filed a Stipulation of Dismissal with the court to dismiss the appeal and the cross-appeal, at which time the matter was closed.

District of Columbia Regulatory Matters

2016 District of Columbia Electric Distribution Base Rates (Exelon, PHI and Pepco). On June 30, 2016, Pepco filed an application with the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $82 million on October 14, 2016, and further updated to approximately $77 million on February 1, 2017, based on a requested ROE of 10.6%. The DCPSC has issued a procedural schedule indicating a final decision will be issued by July 25, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect soon thereafter. Pepco cannot predict how much of the requested increase the DCPSC will approve.

On April 18, 2016, a party to a separate DCPSC proceeding filed a motion to suspend Pepco’s bill stabilization adjustment (BSA), which decouples distribution revenues from utility customers from the amount of electricity delivered. On September 9, 2016, the DCPSC denied the party’s motion and determined that the appropriate forum in which to determine whether the BSA continues to be just and reasonable is in Pepco’s rate case proceeding. In addition, the DCPSC stated that it was putting Pepco on notice that all funds collected for the BSA from January 2015 to the issuance of a decision in the rate case proceeding are subject to refund should the DCPSC determine that such funds were not justly or reasonably collected. On November 22, 2016, following Pepco's October 7, 2016 request for reconsideration of the order, the DCPSC issued an order stating that its September 9, 2016 order was not final and confirming that issues related to the BSA, including potential remedial actions, would be addressed in Pepco's rate case. Pepco cannot predict the outcome of this matter or the impact of a refund if ordered by the DCPSC.

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). In May 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provided enabling legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative which would selectively place underground some of the District of Columbia’s most outage-prone power lines.

The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG initiative, recovering those costs through a volumetric surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a volumetric surcharge (the DDOT surcharge) on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and (iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such assets will be transferred to Pepco for a nominal amount.

In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia. In August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District's bonds. In March 2016, the DCPSC's orders approving the Triennial Plan and the application for financing were upheld upon the resolution of appeals that had been filed with the District of Columbia Court of Appeals. In compliance with the Improvement Financing Act, on September 30, 2016, Pepco and DDOT filed a Second Triennial Plan. Recognizing the delays to the First Triennial Plan, Pepco and DDOT requested that the DCPSC hold the Second Triennial Plan in abeyance, and the DCPSC granted this request by order dated October 27, 2016.

In June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely further delay implementation of the DC PLUG initiative.

New Jersey Regulatory Matters

2016 New Jersey Electric Distribution Base Rates (Exelon, PHI and ACE). On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, and an increase of $45 million (before New Jersey sales and use tax) to its electric distribution base rates, with the new rates effective immediately. The stipulation of settlement provided that a determination on PowerAhead would be separated into a phase II of the rate proceeding and decided at a later date and the parties would seek to resolve the matter by the end of 2016, although resolution will most likely occur in the first quarter of 2017. PowerAhead includes capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused on improving the distribution system's ability to withstand major storm events. ACE cannot predict if the NJBPU will approve the PowerAhead initiative.

Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). On February 1, 2016, ACE submitted its 2016 annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts.

As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate increase of $9 million (revised to $19 million in April 2016, based upon an update for actuals through March 2016), including New Jersey sales and use tax.

On November 30, 2016, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate increase of $1 million effective January 1, 2017. This settlement included a credit of approximately $10 million to the Non-Utility Generation charge deferral balance and a credit of approximately $7 million to the Uncollectible deferral balance. These credits were directed to be applied to the deferral balances in an NJBPU order dated October 31, 2016. That order approved the Joint Recommendation for Settlement of the Most Favored Nation Provision, which was a condition of the merger between Exelon Corporation and Pepco Holdings, Inc. This rate increase will have no effect on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.

On February 1, 2017, ACE submitted its 2017 annual petition with the NJBPU seeking to reconcile and update the same categories of charges and costs as set forth in its 2016 annual petition discussed above. The net impact of adjusting the charges as proposed is an overall annual rate decrease of approximately $29 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for January through March 2017 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2017. There is no assurance that NJBPU will put final rates in effect by the requested date.

New York Regulatory Matters

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

The NYPSC initially identified the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility.

Several parties filed with the NYPSC requests for rehearing or reconsideration of the CES. Generation and CENG also filed a request for clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the eligibility of the FitzPatrick plant only and have no bearing on Ginna or Nine Mile Point’s eligibility for the full 12-year duration. On December 15, 2016, the NYPSC approved Exelon’s petition to clarify this condition and denied all petitions for rehearing of the CES. Parties have until mid-April to appeal to New York State court the denials of the requests for rehearing. In addition, one Petition seeking to invalidate the ZEC program was filed in New York State court on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC violated certain technical provisions of the State Administrative Procedures Act (SAPA) when adopting the ZEC program.

On October 19, 2016, a coalition of fossil generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program violates certain provisions of the U.S. Constitution; specifically that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it discriminates against out of state competitors. On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to dismiss the lawsuit. The motion to intervene has been granted and the motion to dismiss is pending.

Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 9 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point, and Note 4 - Mergers, Acquisitions, and Dispositions for additional information on Generation's proposed acquisition of FitzPatrick.

Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). In November 2014, in response to a petition filed by Ginna Nuclear Power Plant (Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & Electric Company (RG&E) to negotiate a Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and FERC for their approval of the proposed RSSA. Although the RSSA was still subject to 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 RSSA.

On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC accepted the compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA. Because all regulatory approvals for the RSSA have now been received, Generation began recognizing revenue based on the final approved pricing contained in the RSSA. Generation also recognized a one-time revenue adjustment in April 2016 of approximately $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through March 31, 2016. A 49.99% portion of the one-time adjustment will be removed from Generation’s results of operations as a result of the noncontrolling interests in CENG.

The RSSA approved by the regulatory authorities has a term expiring on March 31, 2017, subject to possible extension in the event that RG&E needs additional time to complete transmission upgrades to address reliability concerns. In March 2016, RG&E notified Ginna that RG&E expects to complete the transmission upgrades prior to the RSSA expiration in March 2017 and will not need Ginna as an ongoing reliability solution after that date.

The approved RSSA requires Ginna to continue operating through the RSSA term. If Ginna did not plan to retire shortly after the expiration of the RSSA, Ginna was required to file a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the RSSA, if Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments up to a maximum of $20 million to RG&E related to capital expenditures. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for the sale of ZECs under the CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for Ginna. Subject to prevailing over any administrative or legal challenges, it is expected the CES will allow Ginna to continue to operate through the end of its current operating license in 2029. See Note 9 - Early Nuclear Plant Retirements for additional discussion of Ginna.

Federal Regulatory Matters

Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. 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, BGE, Pepco, DPL, and ACE 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, BGE’s, Pepco's, DPL's and ACE's best estimate of the revenue requirement expected to be filed with the FERC for that year’s reconciliation. 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. On December 13, 2016, BGE filed with the FERC to modify its FERC-approved formula to recover its existing regulatory asset and any future changes to its regulatory asset concerning various tax issues including certain deferred income taxes.

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



	ComEd									BGE
Annual Transmission Filings	2016			2015			2014			2016			2015			2014
Initial revenue requirement increase	$	90		$	68		$	36		$	12		$	—		$	9
Annual reconciliation increase (decrease)	4			18			(14		)	3			(3		)	5
Dedicated facilities increase ^(a)	—			—			—			13			13			3
Total revenue requirement increase	$	94		$	86		$	22		$	28		$	10		$	17

Allowed return on rate base ^(c)	8.47		%	8.61		%	8.62		%	8.09		%	8.46		%	8.53		%
Allowed ROE ^(d)	11.50		%	11.50		%	11.50		%	10.50		%	11.30		%	11.30		%

Effective date of rates	June 2016			June 2015			June 2014			June 2016			June 2015			June 2014



	Pepco									DPL									ACE
Annual Transmission Filings	2016			2015			2014			2016			2015			2014			2016			2015			2014
Initial revenue requirement increase (decrease)	$	2		$	10		$	(9	)	$	8		$	15		$	4		$	8		$	10		$	4
Annual reconciliation (decrease) increase	(10		)	(3		)	(1		)	(10		)	(1		)	6			(14		)	2			3
MAPP abandonment recovery (decrease) increase ^(b)	(15		)	(2		)	17			(12		)	(2		)	15			—			—			—
Total revenue requirement (decrease) increase	$	(23	)	$	5		$	7		$	(14	)	$	12		$	25		$	(6	)	$	12		$	7

Allowed return on rate base ^(c)	7.88		%	8.36		%	8.60		%	7.21		%	7.80		%	8.05		%	7.83		%	8.51		%	8.66		%
Allowed ROE^(d)	10.50		%	11.30		%	11.30		%	10.50		%	11.30		%	11.30		%	10.50		%	11.30		%	11.30		%

Effective date of rates^(e)	June 2016			June 2015			June 2014			June 2016			June 2015			June 2014			June 2016			June 2015			June 2014

____________

(a) BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

(b) In 2012, PJM terminated the MAPP transmission line construction project planned for the Pepco and DPL service territories. Pursuant to a FERC approved settlement agreement, the abandonment costs associated with MAPP were being recovered in transmission rates over a three-year period that ended in May 2016.


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

(d) 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 the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.5%, inclusive of a 50 basis point incentive adder for being a member of a regional transmission organization.

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

PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE, Pepco, DPL and ACE 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. On June 15, 2016, a number of parties, including Exelon and the Utility Registrants filed an Offer of Settlement with FERC. Each state that is a party in this proceeding either signed, or will not oppose, the settlement. If the Settlement is approved, effective January 1, 2016, for the costs of the 500 kV facilities approved by the PJM Board on or after February 1, 2013, 50% will be socialized across PJM and 50% will be allocated according to an engineering formula that calculates the flows on the transmission facilities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.

Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation, ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by FERC.

The Utility Registrants are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. The Utility Registrants will work with PJM to continue to evaluate the scope and timing of any required construction projects. The Utility Registrant's estimated commitments are as follows:



	Total		2017		2018		2019		2020		2021
ComEd	$	97	$	64	$	28	$	5	$	—	$	—
PECO	34		14		10		7		2		1
BGE	226		113		55		44		14		—
Pepco	104		6		39		40		19		—
DPL	63		47		16		—		—		—
ACE	93		36		39		18		—		—

Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation). PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. If a resource is subjected to a MOPR, its offer is adjusted to remove the revenues it receives through a federal, state or other government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Currently, the MOPRs in PJM and NYISO apply only to certain new resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.

On January 9, 2017, the Electric Power Supply Association (EPSA) filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a pending NYISO compliance filing in an existing proceeding. Both filings allege that the relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES programs. Exelon has filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other renewable support programs like the PTC and RPS that have generally not been subject to a MOPR. However, if successful, an expanded MOPR could result in mitigation of Generation’s Quad Cities, Ginna, and Nine Mile Point facilities, which are expected to receive ZEC compensation, such that they would have an increased risk of not clearing in future capacity auctions and thus of no longer receiving capacity revenues during the respective ZEC programs. This would also impact the FitzPatrick facility that Generation is currently in the process of acquiring from Entergy. Any mitigation of these generating resources could have a material effect on Exelon’s and Generation’s future cash flows and results of operations. The timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.

Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). 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 Exelon cannot predict exactly how the D.C. Circuit Court will handle the matter on remand, Exelon does 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, Exelon does 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). 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 October 25, 2016, the D.C. Circuit Court dismissed the appeal.

Operating License Renewals (Exelon and Generation). Generation has 40-year operating license 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 December 9, 2014, Generation submitted an application to the NRC to extend the current operating licenses of LaSalle Units 1 and 2 by 20 years. On October 19, 2016, the NRC approved Generation's request to extend the operating licenses of LaSalle units 1 and 2 by 20 years to 2042 and 2043, respectively.

On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In addition, Generation continues to work with MDE and other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.

On August 7, 2015, US Fish and Wildlife Service of the US Department of the Interior (Interior) 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 Interior’s preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all fish passage issues between the parties. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the 46-year life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly from year to year throughout the life of the new license. Resolution of the remaining issues relating to Conowingo involving various stakeholders 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. As of December 31, 2016, $28 million of direct costs associated with Conowingo licensing efforts have been capitalized-to-date.

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

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

As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting. See Note 4 - Mergers, Acquisitions and Dispositions for additional information.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of December 31, 2016 and December 31, 2015:



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	4,162	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	2,016		75		1,583		98		260		171		38		51
AMI programs	701		164		49		230		258		174		84		—
Under-recovered distribution service costs	188		188		—		—		—		—		—		—
Debt costs	124		42		1		7		81		17		9		6
Fair value of long-term debt	812		—		—		—		671		—		—		—
Fair value of PHI's unamortized energy contracts	1,085		—		—		—		1,085		—		—		—
Severance	5		—		—		5		—		—		—		—
Asset retirement obligations	111		76		23		12		—		—		—		—
MGP remediation costs	305		278		26		1		—		—		—		—
Under-recovered uncollectible accounts	56		56		—		—		—		—		—		—
Renewable energy	260		258		—		—		2		—		—		2
Energy and transmission programs	89		23		—		38		28		6		5		17
Deferred storm costs	36		—		—		1		35		12		5		18
Electric generation-related regulatory asset	10		—		—		10		—		—		—		—
Rate stabilization deferral	7		—		—		7		—		—		—		—
Energy efficiency and demand response programs	621		—		1		285		335		250		85		—
Merger integration costs	25		—		—		10		15		11		4		—
Under-recovered revenue decoupling	27		—		—		3		24		21		3		—
COPCO acquisition adjustment	8		—		—		—		8		—		8		—
Recoverable workers compensation and long-term disability costs	34		—		—		—		34		34		—		—
Vacation accrual	31		—		7		—		24		—		14		10
Securitized stranded costs	138		—		—		—		138		—		—		138
CAP arrearage	11		—		11		—		—		—		—		—
Removal costs	477		—		—		—		477		134		88		255
Other	49		7		9		5		29		22		5		4
Total regulatory assets	11,388		1,167		1,710		712		3,504		852		348		501
Less: current portion	1,342		190		29		208		653		162		59		96
Total noncurrent regulatory assets	$	10,046	$	977	$	1,681	$	504	$	2,851	$	690	$	289	$	405



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	47	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,607		2,169		438		—		—		—		—		—
Removal costs	1,601		1,324		—		141		136		18		118		—
Deferred rent	39		—		—		—		39		—		—		—
Energy efficiency and demand response programs	185		141		41		—		3		3		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	76		—		76		—		—		—		—		—
Gas distribution tax repairs	20		—		20		—		—		—		—		—
Energy and transmission programs	134		60		56		—		18		8		5		5
Other	72		4		5		19		41		2		17		20
Total regulatory liabilities	4,789		3,698		644		160		237		31		140		25
Less: current portion	602		329		127		50		79		11		43		25
Total noncurrent regulatory liabilities	$	4,187	$	3,369	$	517	$	110	$	158	$	20	$	97	$	—



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt	162		—		—		—		—		—		—		—
Severance	9		—		—		9		—		—		—		—
Asset retirement obligations	108		67		22		19		1		1		—		—
MGP remediation costs	286		255		30		1		—		—		—		—
Under-recovered uncollectible accounts	52		52		—		—		—		—		—		—
Renewable energy	247		247		—		—		6		—		1		5
Energy and transmission programs	84		43		1		40		33		9		11		13
Deferred storm costs	2		—		—		2		43		19		6		18
Electric generation-related regulatory asset	20		—		—		20		—		—		—		—
Rate stabilization deferral	87		—		—		87		—		—		—		—
Energy efficiency and demand response programs	279		—		1		278		401		289		111		1
Merger integration costs	6		—		—		6		—		—		—		—
Conservation voltage reduction	3		—		—		3		—		—		—		—
Under-recovered revenue decoupling	30		—		—		30		14		10		4		—
COPCO acquisition adjustment	—		—		—		—		—		—		13		—
Workers compensation and long-term disability costs	—		—		—		—		31		31		—		—
Vacation accrual	6		—		6		—		23		—		14		9
Securitized stranded costs	—		—		—		—		202		—		—		202
CAP arrearage	7		—		7		—		—		—		—		—
Removal costs	—		—		—		—		369		92		69		208
Other	29		10		13		3		32		14		9		8
Total regulatory assets	6,824		1,113		1,617		781		2,582		801		371		512
Less: current portion	759		218		34		267		305		140		72		98
Total noncurrent regulatory assets	$	6,065	$	895	$	1,583	$	514	$	2,277	$	661	$	299	$	414



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	94	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,577		2,172		405		—		—		—		—		—
Removal costs	1,527		1,332		—		195		150		21		129		—
Energy efficiency and demand response programs	92		52		40		—		1		—		—		1
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		27		16		19		8
Over-recovered revenue decoupling	1		—		—		1		—		—		—		—
Other	16		5		2		8		35		7		12		16
Total regulatory liabilities	4,570		3,614		639		222		213		44		160		25
Less: current portion	369		155		112		38		66		15		49		18
Total noncurrent regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7

Pension and other postretirement benefits. As of December 31, 2016, Exelon had regulatory assets of $3,075 and regulatory liabilities of $47 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. As of December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $1,087 million established at the date of the PHI Merger related to unrecognized costs that are probable of regulatory recovery. The regulatory assets are amortized and recovered over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates. 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. As of December 31, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2015, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $15 million, $16 million, $26 million, $18 million and $15 million for ComEd, BGE, Pepco, DPL and ACE, respectively. See Note 15 — Income Taxes, Note 17 — Retirement Benefits, and the Transmission Forumla Rate section above for additional information. ComEd, PECO, BGE, Pepco, DPL and ACE are not earning a return on the regulatory asset in rates. The recovery period is over the life of the associated assets.

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 these meter costs are through January 2020. As of December 31, 2016 and December 31, 2015, ComEd had regulatory assets of $162 million and $137 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 primarily represents accelerated depreciation on PECO’s non-AMI meter assets over a 10-year period ending December 31, 2020. Recovery of smart meter costs are reflected in base rates effective January 1, 2016. For BGE, this amount represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters. The incremental costs associated with the installation, along with depreciation, amortization, and an appropriate return, had been building in a regulatory asset since the MDPSC approved the comprehensive smart grid initiative for BGE in August 2010 through approval of the program in BGE’s rate order issued June, 2016. As of December 31, 2016, the balance of BGE’s regulatory asset was $230 million, which consists of three major components, including $144 million of unamortized incremental deployment costs of the AMI program, $54 million of unamortized costs of the non-AMI meters replaced under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to when approval became effective June 2016. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being amortized and recovered through rates over a 10-year period, which began in June, 2016. A return on the $144 million incremental deployment costs for the AMI program portion of the regulatory asset is included in rates. The $54 million portion of the regulatory asset related to the unamortized cost of the retired non-AMI meters is not earning a return in rates. The $32 million portion related to post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC and are not currently earning a return for financial reporting purposes. For PHI, this amount represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout the service territories for Pepco and DPL. An AMI program has not been approved by the NJBPU for ACE in New Jersey. Pepco has received approval for recovery of deferred AMI program costs from the DCPSC and the MDPSC in its DC and Maryland service territories. Pepco does earn a return on the AMI deployment costs, but not on the early retirement of legacy meters. DPL has received approval for recovery of deferred AMI program costs from the DPSC in its Delaware service territory and has received a proposed order from the MDPSC approving recovery of deferred AMI program costs in its Maryland service territory. As of December 31, 2016, the DPL deferred AMI program costs pending finalization of the proposed order from the MDPSC are $41 million, of which $14 million relates to retired legacy meters which are not earning a return.

Under-recovered distribution services costs. These amounts represent under recoveries related to electric distribution services costs recoverable through EIMA’s performance based formula rate. 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, 2016, the regulatory asset was comprised of $134 million for the 2015 to 2016 annual reconciliations and $54 million related to significant one-time events, including $20 million in deferred storm costs and $11 million of Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. ComEd's 2015 annual reconciliation regulatory asset includes a reduction of $8 million related to a ComEd-proposed refund to customers for the impact of changing its OSHA recordable rate for 2014 and 2015. 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.

Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE'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 these costs. Recovery of these costs will continue through 2038 for ComEd and BGE. PECO, Pepco, DPL and ACE are earning a return on the premium of the cost of the reacquired debt through base rates. The regulatory asset for Pepco, DPL and ACE was eliminated at Exelon and PHI as part of acquisition accounting.

Fair value of long-term debt. These amounts represent the unamortized regulatory assets recorded at Exelon for the difference between the carrying value and 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 and at Exelon and PHI for the difference between carrying value and fair value of long-term debt of Pepco, DPL and ACE as of the PHI Merger date. 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.

Fair value of PHI's unamortized energy contracts. These amounts represent the regulatory asset recorded at Exelon and PHI offsetting the fair value adjustments related to Pepco's, DPL's and ACE's electricity and natural gas energy supply contracts recorded at PHI as of the PHI Merger date. Pepco, DPL and ACE are allowed full recovery of the costs of these contracts through their respective rate making processes.

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. The recovery period will be over the expected life of the related assets. 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, currently estimated to be completed in 2022 for both ComEd and PECO. 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 24 — 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 and associated RECs through 2032 in order to meet a portion of its obligations under the Illinois RPS. 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). Recovery of these costs will continue through 2032. 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, 2016, ComEd's regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC approved formula rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd's regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for renewable energy requirements. 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. 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. 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. 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. 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, 2016, PECO's regulatory liability of $56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recovered non-bypassable transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to over-recovered electric transmission costs. As of December 31, 2015, PECO's regulatory asset of $1 million related to under-recovered non-bypassable transmission service charges. As of December 31, 2015, PECO's regulatory liability of $60 million included $35 million related to over-recovered costs under the DSP program, $22 million related to the over-recovered natural gas costs under the PGC and $3 million related to the over-recovered electric transmission costs.

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 earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. BGE does not earn or pay interest to customers on under-recovered or over-recovered SOS and MBR costs. The recovery or refund period is a twelve-month period beginning in June of the following calendar year. As of December 31, 2016, BGE's regulatory asset of $38 million included $4 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $3 million related to under-recovered natural gas costs. As of December 31, 2015, BGE’s regulatory asset of $40 million included $12 million of costs 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 $14 million of over-recovered transmission costs and $5 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be recovered upon FERC approval.

The Pepco energy costs represent the electric supply and transmission related costs recoverable (refundable) from (to) customers under Pepco’s market-based SOS program and FERC approved transmission rates. Pepco earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. Pepco does not earn or pay interest to customers on under- or over-recovered SOS costs. The asset is being amortized and recovered over the life of the associated assets. As of December 31, 2016, Pepco's regulatory asset of $6 million related to under-recovered electric energy costs. As of December 31, 2016, Pepco's regulatory liability of $8 million included $5 million of over-recovered transmission costs and $3 million of over-recovered electric energy costs. As of December 31, 2015, Pepco's regulatory asset of $9 million included $5 million of transmission costs recoverable through its FERC approved formula rate and $4 million of recoverable abandonment costs. As of December 31, 2015, Pepco's regulatory liability of $16 million included $14 million of over-recovered transmission costs and $2 million of over-recovered electric energy costs.

The DPL energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to) customers under DPL’s market-based SOS program, GCR and FERC approved transmission rates. DPL earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. In Delaware, DPL earns interest on under-recovered costs and pays interest to customers on over-recovered SOS an GCR costs. In Maryland, DPL does not earn or pay interest to customers on under- or over-recovered SOS costs. The asset is being amortized and recovered over the life of the associated assets. As of December 31, 2016, DPL's regulatory asset of $5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric energy costs. As of December 31, 2016, DPL's regulatory liability of $5 million included $2 million of over-recovered electric energy costs and $3 million of over-recovered transmission costs. As of December 31, 2015, DPL's regulatory asset of $11 million included $7 million of transmission costs recoverable through its FERC approved formula rate, $3 million of recoverable abandonment costs, and $1 million of under-recovered electric energy costs. As of December 31, 2015, DPL's regulatory liability of $19 million included $4 million related to the over-recovered natural gas costs under the GCR mechanism, $4 million of over-recovered electric energy costs, and $11 million of over-recovered transmission costs.

The ACE energy costs represent the electric supply and transmission related costs recoverable (refundable) from (to) customers under ACE’s market-based BGS program and FERC approved transmission rates. ACE earns or pays interest to customers on under-recovered or over-recovered FERC transmission formula-related costs. ACE earns interest on under-recovered and pays interest to customers on over-recovered BGS costs. As of December 31, 2016, ACE's regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE's regulatory liability of $5 million included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs. As of December 31, 2015, ACE's regulatory asset of $13 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2015, ACE's regulatory liability of $8 million related to over-recovered transmission 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 original recovery period of five years was extended for an additional 25 months, in accordance with the MDPSC 2014 electric and natural gas distribution rate case order.

For Pepco, DPL and ACE, amounts represent total incremental storm restoration costs incurred for repair work due to major storm events in 2016, 2015, 2012 and 2011, including the January 2016 winter storm Jonas for Pepco, June 2015 storm (for DPL and ACE), Hurricane Sandy, the June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), that are recoverable from customers in the Maryland and New Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the 2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. However, in the November 2016 Pepco Maryland Case No. 9418 order, the Commission ruled that the remaining amortization for the Pepco Maryland February 2010 storm, the January 2011 storm and Hurricane Irene be extended for an additional three years. The reason for the extension was that since these assets would be fully amortized in 2017, Pepco would over-recover these costs if the rates in this case remained in effect beyond July 2017. The January 2017 PULJ report for DPL Maryland Case No. 9424 also recommended that amortization period for Hurricane Irene (DPL MD) be extended an additional three years as well. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from customers, each over a three-year period. PHI does not earn a return on these ACE regulatory assets.

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 $9 million as of December 31, 2016, and $19 million as of December 31, 2015. 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 2016 and 2015, BGE recovered $81 million and $73 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 expects to refund these over recoveries in 2017. ComEd earns a return on the capital investment incurred under the program, but does not earn or pay a return or interest on under or over recoveries, respectively. For PECO, these amounts represent over recoveries of program costs related to both Phase II and Phase III of its PAPUC-approved EE&C Plan. PECO began recovering the costs of its Phase II and Phase III EE&C Plans through a surcharge in June 2013 and June 2016, respectively, based on projected spending under the programs. Phase II of the program began on June 1, 2013 and expired on May 31, 2016. Phase III of the program began on June 1, 2016 and will expire on May 31, 2021. 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.

For Pepco, DPL and ACE, amounts represent recoverable costs associated with customer direct load control and energy efficiency and conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy consumption. PHI earns a return on these regulatory assets.

Merger integration costs. These amounts include 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.

These amounts also include integration costs to achieve distribution synergies related to the PHI acquisition. As of December 31, 2016, BGE's regulatory asset of $10 million included $6 million of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order. As of December 31, 2016, PHI's regulatory asset of $15 million represents previously incurred PHI acquisition costs expected to earn a return and be recovered in distribution rates in the Maryland service territories of Pepco and DPL.

Under (Over)-recovered electric and gas revenue decoupling. For BGE, these amounts represent the electric and gas distribution costs recoverable from or (refundable) to customers under BGE’s decoupling mechanisms, which does not earn a rate of return and is being recovered over the life of the associated assets. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas revenue decoupling and $1 million related to under-recovered electric revenue decoupling. 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.

For Pepco and DPL, these amounts represents the electric distribution costs recoverable from customers under Pepco's Maryland and District of Columbia decoupling mechanisms and DPL's Maryland decoupling mechanism. Pepco and DPL earn a return on these regulatory assets.

COPCO acquisition adjustment. On July 19, 2007, the MDPSC issued an order which provided for the recovery of a portion of DPL’s goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007 through August 2018. DPL earns a return of 12.95% on these regulatory assets.

Recoverable workers compensation and long-term disability costs. These amounts represent accrued workers’ compensation and long-term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. Pepco is not earning a return on the recovery of these costs and the recovery period is over the life of the associated assets.

Vacation accrual. These amounts represent accrued vacation costs for PECO, DPL and ACE. PECO, DPL and ACE do not earn a return on these regulatory assets and the costs are recoverable from customers when actual payments are made to employees or when vacation is taken.

Securitized stranded costs. These amounts represent certain contract termination payments under a contract between ACE and an unaffiliated non-utility generator and costs associated with the regulated operations of ACE’s electricity generation business that are no longer recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds issued by Atlantic City Electric Transition Funding LLC (ACE Funding) to securitize the recoverability of these stranded costs. These bonds mature between 2017 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a return on these regulatory assets.

CAP arrearage. These amounts represent the guaranteed recovery of PECO's previously incurred bad debt expense associated with the 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 over the duration of the five-year payment agreement term 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, BGE, PHI, Pepco, DPL and ACE 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. PHI, Pepco, DPL, and ACE have a regulatory asset which represents removal costs incurred in excess of amounts received from customers through depreciation rates recoverable from ratepayers. Pepco, DPL and ACE do not earn a return on these regulatory assets and the recovery period is over the life of the associated assets.

Deferred rent. Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease. The costs of the lease are recoverable through the ratemaking process at Pepco, DPL and ACE.

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.

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

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



									Successor
	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(b)		DPL^(b)		ACE
December 31, 2016	$	72	$	5	$	—	$	57	$	10	$	6	$	4	$	—
									Predecessor
	Exelon		ComEd^(a)		PECO		BGE^(b)		PHI		Pepco^(b)		DPL^(b)		ACE
December 31, 2015	$	55	$	6	$	—	$	49	$	4	$	1	$	3	$	—

_________________________


(a)	Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs regulatory assets.


(b)	BGE's, Pepco's and DPL's authorized amounts capitalized for ratemaking purposes related to earnings on shareholders' investment on their respective AMI Programs.

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

ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount primarily to recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of December 31, 2016 and December 31, 2015.



													Successor
As of December 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables ^(c)	$	313		$	87		$	72		$	59		$	95		$	63		$	10		$	22
Allowance for uncollectible accounts ^(a)	(37		)	(14		)	(6		)	(4		)	(13		)	(7		)	(2		)	(4		)
Purchased receivables, net	$	276		$	73		$	66		$	55		$	82		$	56		$	8		$	18

													Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables ^(b)(c)	$	229		$	103		$	67		$	59		$	100		$	70		$	11		$	19
Allowance for uncollectible accounts ^(a)	(31		)	(16		)	(7		)	(8		)	(6		)	(4		)	—			(2		)
Purchased receivables, net	$	198		$	87		$	60		$	51		$	94		$	66		$	11		$	17

_________________________


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


(b)	PECO’s natural gas POR program became effective on January 1, 2012 and included 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.

(c)

Pepco's electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and Pepco's electric POR program in the District of Columbia included a discount on purchased receivables ranging from 0% to 6% depending on customer class. DPL's electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 1% depending on customer class.

Mergers, Acquisitions and Dispositions (All Registrants)

12 Months Ended

Dec. 31, 2016

Mergers, Acquisitions and Dispositions

Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

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

Regulatory Matters

Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund, workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger in Delaware, New Jersey, and Maryland include a “most favored nation” provision which, generally speaking, requires allocation of merger benefits proportionally across all the jurisdictions.

During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million excluding renewable generation commitments (approximately $444 million on a net present value basis, excluding renewable generation commitments and charitable contributions). These filings, which reflect agreements reached with certain parties to the merger proceedings in the jurisdictions, were subject to regulatory review and approval in each jurisdiction. The DPSC and NJBPU approved the amounts and allocations during the third and fourth quarters of 2016. An order from the MDPSC is expected in the first quarter of 2017. No changes in commitment cost levels are required in the District of Columbia.

During the fourth quarter of 2016, the MDPSC approved a change in the application of $9 million in funding for energy-efficiency program support in the DPL MD service territory. This resulted in an adjustment to the merger commitment costs recorded at Exelon Corporate and DPL. Exelon Corporate recorded a decrease and DPL recorded an increase of $9 million in Operating and maintenance expense.

The following amounts were recognized as total commitment costs in Operating and maintenance expense in Exelon's, PHI's, Pepco's, DPL's and ACE's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016 and PHI's successor period:



	Expected Payment Period							Successor
Description	Expected Payment Period	Pepco^(a)		DPL^(a)		ACE^(a)		PHI^(a)		Exelon^(a)
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		111
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2016	—		—		—		—		22
Green sustainability fund	Q2 2016	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		24
Other		7		7		—		14		33
Total		$	126	$	86	$	111	$	323	$	513

_______

(a) Included within the individual line items is the most favored nation provision estimate of $6 million, $5 million $38 million, $49 million and $134 million at Pepco, DPL, ACE, PHI and Exelon, respectively.

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

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

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

Exelon was previously named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the merger transaction and that Exelon aided and abetted the individual directors’ breaches. The suits sought rescission of the merger and unspecified damages and costs. On June 1, 2016, the parties executed a settlement to resolve all claims, subject to the approval of the Delaware Court. A hearing had been scheduled for September 8, 2016 in the Delaware Court to consider whether to approve the settlement. However, on August 19, 2016, the plaintiffs advised Exelon that they had determined to dismiss the case in its entirety and with prejudice. On August 24, 2016, the Delaware Court issued an order approving the dismissal.

In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order approving the merger and 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, 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, 2016, the Sierra Club and CCAN filed a notice of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment. The OPC and Sierra Club have until the later of (i) 30 days from the date of the Court's order or (ii) 15 days from the date the Court enters its mandate, to file their petition for further review in the Court of Appeals. Exelon cannot predict if the petition will be filed.

Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On June 17, 2016, the DCPSC denied all motions. In August 2016, the District of Columbia Office of People’s Counsel, the District of Columbia Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review of the DCPSC’s March 23, 2016 order with the District of Columbia Court of Appeals. On September 9, 2016, the Court consolidated the appeals. The Court has issued a scheduling order, and a decision is expected in the second or third quarter of 2017. Exelon believes the matters are without merit.

Accounting for the Merger Transaction

The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid for PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:



(In millions of dollars, except per share data)	Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)	$	6,933
Cash paid for PHI preferred stock^(a)	180
Cash paid for PHI stock-based compensation equity awards^(b)	29
Total purchase price	$	7,142

_____________


(a)	As of December 31, 2015, the preferred stock was included in Other non-current assets on Exelon's Consolidated Balance Sheets.

(b)

PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger. In connection with the Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred securities was treated as purchase price consideration.

The valuations performed in the first quarter of 2016 to assess the fair value of certain assets acquired and liabilities assumed were considered preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2016. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about the fair value of assets acquired and liabilities assumed. Exelon expects to finalize these amounts in the first quarter of 2017. During the second, third and fourth quarters of 2016, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment, unamortized energy contracts, current liabilities, long-term debt, deferred income taxes and pension and OPEB liabilities resulting in an $11 million net decrease to goodwill. The preliminary amounts recognized are subject to further revision to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price allocation and could potentially impact goodwill.

Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded at their estimated fair values on Exelon’s and PHI's Consolidated Balance Sheets as of March 23, 2016, as follows:



Preliminary Purchase Price Allocation
Current assets	$	1,441
Property, plant and equipment	11,088
Regulatory assets	5,015
Other assets	248
Goodwill	4,005
Total assets	$	21,797

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,447
Pension and OPEB liabilities	821
Other liabilities	187
Total liabilities	$	14,655
Total purchase price	$	7,142

On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equity of $7.2 billion, which is greater than the total $7.1 billion purchase price, reflecting the impact of a $59 million deferred tax liability recorded only at Exelon Corporate to reflect unitary state income tax consequences of the merger.

The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was recognized as goodwill by PHI and Exelon at the acquisition date, reflecting the value associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and the opportunities for synergies. For purposes of future required impairment assessments, the goodwill has been preliminarily assigned to PHI's reportable units Pepco, DPL and ACE in the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. None of this goodwill is tax deductible.

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

The fair values of PHI's assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows, future market prices and impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.

Through its wholly-owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject to cost-of-service rate regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured at historical cost. In applying the acquisition method of accounting, for regulated assets and liabilities included in rate base or otherwise earning a return (primarily property, plant and equipment and regulatory assets earning a return), no fair value adjustments were recorded as historical cost is viewed as a reasonable proxy for fair value.

Fair value adjustments were applied to the historical cost bases of other assets and liabilities subject to rate regulation but not earning a return (including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also established, as the underlying utility asset and liability amounts are recoverable from or refundable to customers at historical cost (and not at fair value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and liabilities, such as for electricity and gas energy supply contracts as further described below. Regulatory assets and liabilities established to offset fair value adjustments are amortized in amounts and over time frames consistent with the realization or settlement of the fair value adjustments, with no impact on reported net income. See Note 3 - Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by Exelon and PHI.

Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and gas energy supply contracts of PHI’s wholly-owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of December 31, 2016. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible assets and liabilities 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. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date.

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

The current impact of PHI, including its unregulated businesses, on Exelon's Consolidated Statements of Operations and Comprehensive Income includes Operating revenues of $3,785 million and Net loss of $(66) million during the year ended December 31, 2016.

For the periods ended December 31, 2016 and 2015, Exelon and PHI have recognized expense to achieve the PHI acquisition as follows:



	For the Year Ended December 31,
Acquisition, Integration and Financing Costs^(a)	2016			2015
Exelon^(b)	$	143		$	87
Generation	37			24
ComEd^(c)	(6		)	9
PECO	5			4
BGE^(c)	(1		)	5
Pepco^(c)	28			3
DPL^(c)	20			2
ACE	19			1



	Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015
PHI^(c)	$	69	$	29	$	19

______________


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


(b)	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.


(c)	For the year ended December 31, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million, $4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.

Pro-forma Impact of the Merger

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

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



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

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

______________


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


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

Acquisition of ConEdison Solutions (Exelon and Generation)

On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison Solutions), a subsidiary of Consolidated Edison, Inc. for a purchase price of $257 million including net working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison Solutions are excluded from the transaction. As of December 31, 2016, Generation had remitted $235 million to ConEdison Solutions and the remaining balance of $22 million, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets, will be paid during the first quarter of 2017.

The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the ConEdison Solutions acquisition by Generation as of September 1, 2016:



Total consideration transferred	$	257

Identifiable assets acquired and liabilities assumed
Working capital assets	$	204
Property, plant and equipment	2
Mark-to-market derivative assets	6
Unamortized energy contract assets	100
Customer relationships	9
Other assets	1
Total assets	$	322

Mark-to-market derivative liabilities	$	(65	)
Total liabilities	$	(65	)
Total net identifiable assets, at fair value	$	257

The purchase price equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain purchase was recorded as of December 31, 2016. The purchase accounting is preliminary, and, although not expected, may be further adjusted from what is shown above. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed; however, Generation expects to finalize these amounts by the first quarter of 2017.

The fair values of ConEdison Solutions' assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices.

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

On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838 MW single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York for a cash purchase price of $110 million. As part of the transaction, Generation would receive the FitzPatrick NDT fund assets and assume the obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. In November 2015, Entergy had announced plans to early retire FitzPatrick at the end of the current fuel cycle in January 2017. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to prepare for and conduct the plant refueling outage as well as to operate and maintain the plant after the refueling outage, scheduled to end in February 2017, through the closing date. These are costs which otherwise would have been avoided by FitzPatrick’s planned permanent shutdown in January 2017. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon completion of the refueling outage through the acquisition closing date. The agreements provide for certain termination rights, including the right of either party to terminate if the transaction has not been consummated within 12 months due to failure to obtain the required regulatory approvals.

Closing of the transaction is currently anticipated to occur in the first half of 2017 and requires regulatory approval by FERC, NRC, and the New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act (which had been completed) and other customary closing conditions. On November 17, 2016 the NYPSC issued an order approving the transaction. On October 11, 2016, Public Citizen, Inc. filed a protest with FERC challenging Generation and Entergy’s application to FERC for the transfer of ownership of FitzPatrick. No other party to the FERC proceeding filed any protests or comments. On December 7, 2016 FERC approved Generation's acquisition of the FitzPatrick facility and dismissed the Public Citizen protest. Public Citizen filed a request for rehearing on January 6, 2017. NRC is the final regulatory approval required to close the transaction and is anticipated during the first half of 2017.

The transaction is expected to be accounted for as a business combination. For accounting and financial reporting purposes, the costs for which Generation reimburses Entergy as well as the revenue received from FitzPatrick prior to the closing of the transaction will be treated as part of the purchase price consideration. Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.

As of December 31, 2016, Generation has recorded $127 million of purchase price consideration in Other noncurrent assets on Exelon’s and Generation’s Consolidated Balance Sheets. The cash outflows associated with these amounts are reflected within Acquisition of businesses on Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the event the acquisition does not close, these amounts would be subject to potential write-off to Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. For the year ended December 31, 2016, Exelon and Generation incurred $19 million 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.

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 and 2016 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, Generation, PHI, Pepco and DPL)

On November 10, 2015, Pepco completed the sale of a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point area of southeast Washington, D.C., resulting in a pre-tax gain of $37 million.

On December 31, 2015, Pepco completed the sale of a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of northeast Washington, D.C., resulting in a pre-tax gain of $9 million. The purchase and sale agreement also provided the third party with a 90-day option to purchase the remaining 1.8 acre land parcel.

On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million.

On May 2, 2016, Pepco completed the sale of the remaining 1.8 acre land parcel noted above, located in the NoMa area of northeast Washington, D.C., resulting in a pre-tax gain of approximately $8 million at Pepco. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in Exelon's and PHI's Consolidated Statements of Operations and Comprehensive Income.

On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse debt. See Note 14 - Debt and Credit Agreements for more information. In December 2016, Generation sold substantially all of the Upstream assets for $37 million which resulted in a pre-tax loss on sale of $10 million which is included in Gain (loss) on sales of assets on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.

In July 2016, DPL completed the sale of a 9 acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain of approximately $4 million. In December 2016, DPL completed the sale of a 48 acre land parcel located in Middletown, DE, resulting in a pre-tax gain of approximately $5 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in Exelon's and PHI's Consolidated Statements of Operations and Comprehensive Income.

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

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, 2016

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 27 — 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 $316 million as of December 31, 2016.

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. 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 27 — 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, 2016, 2015, and 2014 Generation had sales to EDF of $376 million, $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 interests 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 interests 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 interests 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 interests on the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interests 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, 2016 and 2015, Generation reduced by $20 million and $18 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 $548 million and $509 million and CENG’s net income (loss), prior to any intercompany eliminations and any adjustments for noncontrolling interests, of $201 million and $(11) million during the years ended December 31, 2016 and 2015, respectively.

Exelon and Generation incurred no merger integration-related costs in 2016. However, in 2015 Exelon and Generation incurred $2 million of merger related integration costs. 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 (All Registrants)

12 Months Ended

Dec. 31, 2016

Receivables [Abstract]

Accounts Receivable (All Registrants)

Accounts receivable at December 31, 2016 and 2015 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:



																		Successor
2016	Exelon			Generation				ComEd			PECO				BGE			PHI				Pepco				DPL				ACE
Unbilled customer revenues	$	1,673		$	910		^(a)	$	219		$	140			$	182		$	222			$	123			$	58			$	41
Allowance for uncollectible accounts ^(b)	(334		)	(91		)		(70		)	(61		)	^(c)	(32		)	(80		)	^(d)	(29		)	^(d)	(24		)	^(d)	(27		)	^(d)



																		Predecessor
2015	Exelon			Generation				ComEd			PECO				BGE			PHI			Pepco			DPL			ACE
Unbilled customer revenues	$	1,203		$	732		^(a)	$	218		$	105			$	148		$	177		$	93		$	45		$	39
Allowance for uncollectible accounts^(b)	(284		)	(77		)		(75		)	(83		)	^(c)	(49		)	(56		)	(17		)	(17		)	(17		)

_________________________


(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 $23 million and $8 million at December 31, 2016 and 2015, respectively, related to PECO’s current installment plan receivables described below.

(d)

At December 31, 2016, as explained in Note 1—Significant Accounting Policies, PHI, Pepco, DPL and ACE 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 an overall increase of $30 million, $14 million, $8 million, and $8 million in the allowance for uncollectible accounts with $20 million, $8 million, $4 million, and $8 million deferred as a regulatory asset on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets at December 31, 2016, respectively. This also resulted in a $10 million, $6 million, and $4 million pre-tax charge to provision for uncollectible accounts expense for the year ended December 31, 2016, which is included in Operating and maintenance expense on PHI's, Pepco's, and DPL's Consolidated Statements of Operations and Comprehensive Income, respectively.

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 $9 million and $15 million at December 31, 2016 and 2015, respectively. 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, 2016 of $13 million consists of $1 million, $3 million and $9 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2015 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, 2016 and 2015 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.

The entire disclosure for claims held for amounts due a entity, excluding financing receivables. Examples include, but are not limited to, trade accounts receivables, notes receivables, loans receivables. Includes disclosure for allowance for credit losses.

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment (All Registrants)

12 Months Ended

Dec. 31, 2016

Property, Plant and Equipment (All Registrants)

Exelon

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-90	$	45,698	$	32,546
Electric—generation	3-56	27,193		25,615
Gas—transportation and distribution	5-90	4,642		3,864
Common—electric and gas	4-50	1,312		1,149
Nuclear fuel ^(a)	1-8	6,546		6,384
Construction work in progress	N/A	4,306		3,075
Other property, plant and equipment ^(b)	3-50	1,027		1,181
Total property, plant and equipment		90,724		73,814
Less: accumulated depreciation ^(c)		19,169		16,375
Property, plant and equipment, net		$	71,555	$	57,439

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,326 million and $1,266 million at December 31, 2016 and 2015, respectively.

(b)

Includes Generation’s buildings under capital lease with a net carrying value of $10 million and $13 million at December 31, 2016 and 2015, respectively. The original cost basis of the buildings was $52 million, and total accumulated amortization was $42 million and $39 million, as of December 31, 2016 and 2015, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2016 and 2015, of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2016 and 2015. Includes land held for future use and non utility property at ComEd, PECO, BGE, Pepco, DPL, and ACE of $60 million, $21 million, $32 million, $66 million, $16 million, and $27 million, respectively, at December 31, 2016. At December 31, 2015 these balances also include capitalized acquisition, development and exploration costs of $266 million related to oil and gas production activities at Generation, see Note 4—Mergers, Acquisitions, and Dispositions for additional information regarding the sale of upstream assets. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $17 million and $146 million at December 31, 2016 and 2015, respectively. See Note 8 —Impairment of Long-Lived Assets for additional information on the impairment of Generations turbine equipment.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $3,186 million and $2,861 million as of December 31, 2016 and 2015, 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	2016			2015		2014
Electric—transmission and distribution	2.73	%		2.83	%	2.93	%
Electric—generation	5.94	%	^(a)	3.47	%	3.50	%
Gas	2.17	%		2.17	%	2.13	%
Common—electric and gas	7.41	%		7.79	%	7.32	%

_________________________


(a)	See Note 9—Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton and Quad Cities.

Generation

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—generation	3-56	$	27,193	$	25,615
Nuclear fuel ^(a)	1-8	6,546		6,384
Construction work in progress	N/A	2,332		2,017
Other property, plant and equipment ^(b)	4	76		466
Total property, plant and equipment		36,147		34,482
Less: accumulated depreciation ^(c)		10,562		8,639
Property, plant and equipment, net		$	25,585	$	25,843

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,326 million and $1,266 million at December 31, 2016 and 2015, respectively.

(b)

Includes buildings under capital lease with a net carrying value of $10 million and $13 million at December 31, 2016 and 2015, respectively. The original cost basis of the buildings was $52 million, and total accumulated amortization was $42 million and $39 million, as of December 31, 2016 and 2015, respectively. At December 31, 2015 these balances also include capitalized acquisition, development and exploration costs of $266 million related to oil and gas production activities at Generation, see Note 4—Mergers, Acquisitions, and Dispositions for additional information regarding the sale of upstream assets. Includes the original cost and progress payments associated with Generation’s turbine equipment held for future use with a carrying value of $17 million and $146 million at December 31, 2016 and 2015, respectively. See Note 8 —Impairment of Long-Lived Assets for additional information on the impairment of Generations turbine equipment.


(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 million and $2,861 million as of December 31, 2016 and 2015, respectively.

The annual depreciation provisions as a percentage of average service life for electric generation assets were 5.94%, 3.47% and 3.50% for the years ended December 31, 2016, 2015 and 2014, respectively. See Note 9—Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton and Quad Cities.

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 Clinton) 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. Oyster Creek depreciation provisions are based on the 2019 expected shutdown date. Clinton depreciation provisions are based on 2027 which is the last year of the Illinois ZECs. See Note 3 - Regulatory Matters for additional information regarding license renewals and the Illinois ZECs. See Note 9 - Early Nuclear Plant Retirements for additional information on the impacts of expected and potential early plant retirement.

ComEd

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-80	$	22,636	$	20,576
Construction work in progress	N/A	569		572
Other property, plant and equipment ^{(a), (b)}	37-50	67		64
Total property, plant and equipment		23,272		21,212
Less: accumulated depreciation		3,937		3,710
Property, plant and equipment, net		$	19,335	$	17,502

_________________________


(a)	Includes buildings under capital lease with a net carrying value at both December 31, 2016 and 2015 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2016 and 2015.


(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%, 3.03% and 3.05% for the years ended December 31, 2016, 2015 and 2014, respectively.

PECO

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-65	$	7,591	$	7,230
Gas—transportation and distribution	5-70	2,348		2,206
Common—electric and gas	5-50	670		631
Construction work in progress	N/A	188		154
Other property, plant and equipment ^(a)	50	21		21
Total property, plant and equipment		10,818		10,242
Less: accumulated depreciation		3,253		3,101
Property, plant and equipment, net		$	7,565	$	7,141

_________________________


(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	2016		2015		2014
Electric—transmission and distribution	2.32	%	2.39	%	2.55	%
Gas	1.82	%	1.87	%	1.84	%
Common—electric and gas	5.11	%	5.16	%	5.16	%

BGE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-90	$	7,067	$	6,663
Gas—distribution	5-90	2,170		1,951
Common—electric and gas	5-40	707		655
Construction work in progress	N/A	318		312
Other property, plant and equipment ^(a)	20	32		32
Total property, plant and equipment		10,294		9,613
Less: accumulated depreciation		3,254		3,016
Property, plant and equipment, net		$	7,040	$	6,597

_______________________


(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	2016		2015		2014
Electric—transmission and distribution	2.56	%	2.62	%	2.96	%
Gas	2.45	%	2.50	%	2.47	%
Common—electric and gas	9.45	%	10.35	%	9.49	%

PHI

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



		Successor			Predecessor
	Average Service Life (years)	2016			2015
Asset Category
Electric—transmission and distribution	5-86	$	10,315		$	14,563
Gas—distribution	5-75	414			547
Common—electric and gas	4-40	65			164
Construction work in progress	N/A	892			591
Other property, plant and equipment ^(a)	3-43	107			339
Total property, plant and equipment		11,793			16,204
Less: accumulated depreciation		195		—	5,340
Property, plant and equipment, net		$	11,598		$	10,864

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

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	2016		2015		2014
Electric—transmission and distribution	2.52	%	2.48	%	2.42	%
Gas	2.57	%	2.55	%	2.48	%
Common—electric and gas	8.12	%	5.19	%	4.55	%

Pepco

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016			2015
Asset Category
Electric—transmission and distribution	5-86	$	8,018		$	7,682
Construction work in progress	N/A	537			318
Other property, plant and equipment^(a)	10-33	66			91
Total property, plant and equipment		8,621			8,091
Less: accumulated depreciation		3,050		—	2,929
Property, plant and equipment, net		$	5,571		$	5,162

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.17%, 2.13% and 2.10% for the years ended December 31, 2016, 2015 and 2014, respectively.

DPL

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service life	2016			2015
Asset Category
Electric—transmission and distribution	5-68	$	3,574		$	3,431
Gas—distribution	5-75	580			547
Common—electric and gas	4-40	115			108
Construction work in progress	N/A	163			107
Other property, plant and equipment ^(a)	10-43	16			16
Total property, plant and equipment		4,448			4,209
Less: accumulated depreciation		1,175		—	1,139
Property, plant and equipment, net		$	3,273		$	3,070

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

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	2016		2015		2014
Electric—transmission and distribution	2.49	%	2.44	%	2.41	%
Gas	2.57	%	2.55	%	2.48	%
Common—electric and gas	4.99	%	4.24	%	4.08	%

ACE

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016			2015
Asset Category
Electric—transmission and distribution	5-55	$	3,341		$	3,105
Construction work in progress	N/A	169			158
Other property, plant and equipment ^(a)	13-15	27			28
Total property, plant and equipment		3,537			3,291
Less: accumulated depreciation		1,016		—	969
Property, plant and equipment, net		$	2,521		$	2,322

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.45%, 2.46% and 2.48% for the years ended December 31, 2016, 2015 and 2014, respectively.

See Note 1—Significant Accounting Policies for further information regarding property, plant and equipment policies and accounting for capitalized software costs for the Registrants. 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
Impairment of Long-lived Assets (Exelon and Generation)	Dec. 31, 2016
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 or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 2016, updates to the Company's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was recorded during the second quarter of 2016 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Also in the second quarter of 2016, updates to the Company's long-term view, as described above, in conjunction with the retirement announcements of the Quad Cities and Clinton nuclear plants in Illinois suggested that the carrying value of our Midwest asset group may be impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required. 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. During the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its upstream subsidiary CEU Holdings, LLC (as described in Note 14 - Debt and Credit Agreements) and continued declines in both production volumes and commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016, Generation initiated the sales process of its Upstream natural gas and oil exploration and production business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 14 — Debt and Credit Agreements for additional information. An additional pre-tax impairment charge of $15 million was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 4—Mergers, Acquisitions, and Dispositions for additional information. 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. 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 and is included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. See Note 4—Mergers, Acquisitions, and Dispositions for further information on asset sales. Like-Kind Exchange Transaction (Exelon) In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased back to MEAG as part of the transactions (Leases). Pursuant to the applicable 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. All the Headleases were terminated by the second quarter of 2016, and no events occurred prior to the termination that required Exelon to review the estimated residual values of the direct financing lease investments in 2016. On 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. On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and Comprehensive Income. See Note 15—Income Taxes for additional information. As of December 31, 2016, all the long-term leases had been terminated and no residual and net investment value was outstanding. At December 31, 2015, the components of the net investment in the long-term leases consisted of estimated residual value of $639 million, unearned income of $287 million and a resulting net investment of $352 million.

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

12 Months Ended

Dec. 31, 2016

Implications of Potential Early Plant Retirements [Abstract]

Implications Of Potential Early Retirement Disclosure [Text Block]

9. Early Nuclear 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 and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of final rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules.

In 2015, Generation identified the Quad Cities, Clinton and Ginna nuclear plants as having the greatest risk of early retirement based on economic valuation and other factors. At that time, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in order to participate in the 2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity auctions held in April and May 2016, respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design changes to ensure long-term power system reliability in southern Illinois.

In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price was insufficient to cover cash operating costs and a risk-adjusted rate of return to shareholders. In May 2016, Quad Cities did not clear in the PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period.

Based on these capacity auction results, and given the lack of progress on Illinois energy legislation and MISO market reforms, on June 2, 2016 Generation announced it would move forward to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively. The current Nuclear Regulatory Commission (NRC) licenses for Clinton and Quad Cities expire in 2026 and 2032, respectively.

In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges in Operating and maintenance expense of $146 million related to materials and supplies inventory reserve adjustments, employee-related costs and construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, Exelon and Generation began recognizing incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities, including accelerated depreciation of plant assets (along with any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions.

On December 7, 2016, Illinois FEJA was signed into law by the Governor of Illinois and included a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria, much like the solution implemented with the New York CES. The Illinois ZES will have a 10-year duration extending from June 1, 2017 through May 31, 2027. See Note 3 - Regulatory Matters for additional discussion on the Illinois FEJA and the ZES.

With the passage of the Illinois ZES, and subject to prevailing over any related potential administrative or legal challenges, in December 2016 Generation reversed its June 2016 decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants. Accordingly, in December 2016 Exelon and Generation reversed approximately $120 million of the one-time charges initially recorded in June 2016 associated with the early retirements primarily for employee-related costs and a materials and supplies inventory reserve adjustment. In addition, Generation updated the expected economic useful life for both facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates. See Note 16 - Asset Retirement Obligations for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the initial decision and subsequent reversal of the decision to early retire Clinton and Quad Cities.

Through December 31, 2016, Exelon's and Generation's results include a net incremental $688 million of pre-tax expense associated with the initial early retirement decision for Clinton and Quad Cities, as summarized in the table below.




Income statement expense (pre-tax)	2016

Depreciation and Amortization
Accelerated depreciation^(a)	$	712
Accelerated nuclear fuel amortization	60
Operating and Maintenance
Increase ARO accretion, net of contractual offset^(b)	2
Contractual offset for ARC depreciation^(b)	(86		)
Total	$	688

_________


(a)	Reflects incremental accelerated depreciation of plant assets, including any ARC, for the period June 2, 2016, through December 6, 2016.

(b)

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

In New York, the Ginna and Nine Mile Point nuclear plants continue to face significant economic challenges and risk of retirement before the end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, and 2046 for Nine Mile Point Unit 2). On August 1, 2016, the NYPSC issued an order adopting the CES, which would provide payments to Ginna and Nine Mile Point for the environmental attributes of their production. On November 18, 2016 Ginna and Nine Mile Point executed the necessary contracts with NYSERDA, as required under the CES. Subject to prevailing over any administrative or legal challenges, the CES will allow Ginna and Nine Mile Point to continue to operate at least through the life of the program (March 31, 2029). The assumed useful life for depreciation purposes is through the end of their current operating licenses. The approved RSSA currently requires Ginna to continue operating through the RSSA term expiring on March 31, 2017 and required notification to the NYPSC if Ginna did not plan to retire shortly after the expiration of the RSSA. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to continue operating beyond the expiry of the RSSA. Refer to Note 3 - Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.

Assuming the successful implementation of the Illinois ZES and the New York CES and the continued effectiveness of these programs, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent either the Illinois ZES or the New York CES programs do not operate as expected over their full terms, each of these plants could again be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future results of operations, cash flows and financial position.

The Three Mile Island (TMI) nuclear plant also did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period. This is the second consecutive year that TMI failed to clear the capacity auction. Although the plant is committed to operate through May 2019, the plant faces continued economic challenges and Exelon and Generation are exploring all options to return it to profitability. While a portion of the Byron nuclear plant’s capacity did not clear the PJM 2019-2020 planning year capacity auction, the plant is committed to run through May 2020. The Company’s other nuclear plants in PJM cleared in the auction, except Oyster Creek, which did not participate in the auction given Exelon's and Generation’s previous commitment to cease operation of the Oyster Creek nuclear plant by the end of 2019.

The following table provides the balance sheet amounts as of December 31, 2016 for significant assets and liabilities associated with TMI currently considered by management to be at the greatest risk of early retirement due to current economic valuations and other factors.



(in millions)	TMI
Asset Balances
Materials and supplies inventory	$	39
Nuclear fuel inventory, net	83
Completed plant, net	1,015
Construction work in progress	37

Liability Balances
Asset retirement obligation	(565		)

NRC License Renewal Term	2034

The precise timing of an early retirement date for any nuclear plant, and the resulting financial statement impacts, may be affected by a number of factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and decommissioning trust fund requirements, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, where applicable, and just prior to its next scheduled nuclear refueling outage.

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

12 Months Ended

Dec. 31, 2016

Public Utilities, Property, Plant and Equipment [Abstract]

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

Exelon's, Generation's, PECO's, BGE's, PHI's and ACE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2016 and 2015 were as follows:



	Nuclear Generation												Fossil Fuel Generation			Transmission				Other
	Quad Cities			Peach Bottom			Salem^(a)			Nine Mile Point Unit 2			Wyman			PA^(b)		NJ/ DE^(c)		Other^(d)
Operator	Generation			Generation			PSEG Nuclear			Generation			FP&L			First Energy		PSEG/ DPL		various
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	5.89		%	various		various		various
Exelon’s share at December 31, 2016:
Plant^(e)	$	1,054		$	1,384		$	596		$	830		$	3		$	27	$	97	$	15
Accumulated depreciation^(e)	515			407			186			68			3			15		52		13
Construction work in progress	—			16			41			37			—			—		—		—
Exelon’s share at December 31, 2015:
Plant^(e)	$	1,035		$	1,345		$	566		$	756		$	3		$	27	$	93	$	15
Accumulated depreciation^(e)	309			368			167			42			3			15		52		13
Construction work in progress	11			18			40			56			—			—		—		—

________________________


(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, 2016 and 2015.


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


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


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


(e)	Excludes asset retirement costs.

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

Intangible Assets (All Registrants)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets (All Registrants)

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

Goodwill

Exelon’s, Generation's, ComEd’s, PHI's, and DPL's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2016 and 2015 were as follows:



	Balance at January 1, 2015		Impairment losses		Balance at December 31, 2015		Goodwill from business combination		Impairment losses		Measurement period adjustments^(b)			Balance at December 31, 2016
Exelon
Gross amount	$	4,655	$	—	$	4,655	$	4,016	$	—	$	(11	)	$	8,660
Accumulated impairment loss	1,983		—		1,983		—		—		—			1,983
Carrying amount	2,672		—		2,672		4,016		—		(11		)	6,677
Generation
Gross amount	47		—		47		—		—		—			47
Carrying amount	47		—		47		—		—		—			47
ComEd^(a)
Gross amount	4,608		—		4,608		—		—		—			4,608
Accumulated impairment loss	1,983		—		1,983		—		—		—			1,983
Carrying amount	2,625		—		2,625		—		—		—			2,625
DPL
Gross amount	8		—		8		—		—		—			8
Carrying amount	8		—		8		—		—		—			8



March 24, 2016 to December 31, 2016	Beginning Balance		Goodwill from business combination		Impairment losses			Measurement period adjustments^(b)			Ending Balance
PHI - Successor
Gross amount	$	—	$	4,016	$	—		$	(11	)	$	4,005
Accumulated impairment loss	—		—		—			—			—
Carrying amount	—		4,016		—			(11		)	4,005

January 1, 2016 to March 23, 2016
PHI - Predecessor
Gross amount	1,418		—		—			—			1,418
Accumulated impairment loss	12		—		—			—			12
Carrying amount	1,406		—		—			—			1,406

For the Year Ended December 31, 2015
PHI - Predecessor
Gross amount	1,425		—		(7		)	—			1,418
Accumulated impairment loss	18		—		(6		)	—			12
Carrying amount	1,407		—		(1		)	—			1,406

______________________


(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.


(b)	Represents various measurement period adjustments to the valuation of the fair value of the PHI assets acquired and liabilities assumed as a result of the merger.

Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the Exelon, Generation, ComEd, PHI and DPL 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. Generation's operating segments are Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, PHI's operating segments are Pepco, DPL and ACE, and ComEd and DPL have a single operating segment. See Note 26 — Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by segment management. Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill impairment testing purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's $4 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. DPL's $8 million of goodwill is assigned entirely to the DPL reporting unit.

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

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

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

2016 and 2015 Goodwill Impairment Assessment. Generation performed a qualitative test as of November 1, 2016, for its 2016 annual goodwill impairment assessment. Generation previously completed its last quantitative assessment in the first quarter of 2015, and updated its qualitative assessment as of November 1, 2015. Based on the qualitative factors above, Generation concluded that the fair value of the reporting unit is more likely than not greater than the carrying amount, and no further testing was required.

Exelon, ComEd, PHI, and DPL performed quantitative tests as of November 1, 2016, for their 2016 annual goodwill impairment assessments. The first step of the tests comparing the estimated fair values of the ComEd, Pepco, DPL, and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second steps were required.

While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, PHI’s or DPL’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2016, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 10%, 10% and 10%, respectively, for Exelon, ComEd and PHI to fail the first step of their respective impairment tests. The $8 million of goodwill recorded at DPL is related to DPL’s 1995 acquisition of the Conowingo Power Company and the fair value of the DPL reporting unit would have needed to decrease by more than 50% for DPL to fail the first step of the impairment test.

As of November 1, 2015, Exelon, ComEd, and PHI qualitatively determined that the fair value of their reporting units was not more likely than not less than their carrying value and, therefore, did not perform quantitative assessments. As part of their qualitative assessments, Exelon, ComEd and PHI evaluated, among other things, management’s best estimate of projected operating and capital cash flows for their respective 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 their last quantitative assessments.

Other Intangible Assets and Liabilities

Exelon’s, Generation’s, ComEd’s and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2016:



	Weighted Average Amortization Years ^(l)										Estimated amortization expense
		Gross			Accumulated Amortization			Net			2017			2018			2019			2020			2021
Exelon
Software License Agreement ^(a)	10.0	$	95		$	(15	)	$	80		$	10		$	10		$	10		$	10		$	10
Generation
Unamortized Energy Contracts ^(b)
Exelon Wind ^(c)	18.0	224			(83		)	141			14			14			14			10			10
Antelope Valley^(d)	25	190			(28		)	162			8			8			8			8			8
Constellation ^(e)	1.5	1,499			(1,440		)	59			(21		)	11			8			10			10
CENG ^(f)	1.7	(97		)	59			(38		)	(15		)	(18		)	(15		)	(8		)	(4		)
Integrys ^(g)	2.4	5			(3		)	2			1			1			—			—			—
ConEdison ^(h)	1.5	100			(53		)	47			37			7			2			1			—
Service Contract Backlog
PES ^(h)	1.0	9			(7		)	2			2			—			—			—			—
Customer Relationships ⁽ⁱ⁾
Constellation ^(e)	12.4	214			(94		)	120			18			18			17			17			17
Integrys ^(g)	10.0	50			(11		)	39			5			5			5			5			5
PES ^(h)	15.0	12			(1		)	11			1			1			1			1			1
ConEdison ^(h)	10.0	9			—			9			1			1			1			1			1
Trade Names
Constellation ^(e)	10.0	243			(125		)	118			23			23			23			23			23
ComEd
Chicago settlement—1999 agreement ^(j)	21.8	100			(86		)	14			3			3			3			3			—
Chicago settlement—2003 agreement ^(k)	17.9	62			(47		)	15			4			4			4			4			—
PHI
Unamortized Energy Contracts^(h)	6.8	(1,515		)	430			(1,085		)	(335		)	(189		)	(119		)	(115		)	(92		)
Pepco
DC Sponsorship Agreement ^(m)	0	25			—			25			—			—			—			—			—

Total		$	1,225		$	(1,504	)	$	(279	)	$	(244	)	$	(101	)	$	(38	)	$	(30	)	$	(11	)

_________________________


(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 $10 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 $(9) million, $(7) million, $(6) million, $(2) million and $4 million for 2017, 2018, 2019, 2020 and 2021, respectively.


(c)	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735 MWs 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 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)	On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc.


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


(i)	Excludes $11 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 2017 to 2021.

(j)

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.

(k)

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.


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


(m)	In the third quarter of 2015, Pepco entered into a sponsorship agreement with the District of Columbia for future naming rights associated with public property within the District of Columbia to be determined over time through future negotiations. Amortization of the intangible asset will begin once the terms of the naming rights are defined.

The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2016, 2015 and 2014:




For the Year Ended December 31,	Exelon ^(a)		Generation ^(a)		ComEd
2016	$	87	$	79	$	7
2015	76		69		7
2014	179		179		7

________________________

(a) At Exelon, amortization of unamortized energy contracts totaling $35 million, $22 million and $135 million for the years ended December 31, 2016, 2015 and 2014, respectively, was recorded in Operating revenues or Purchase power and fuel expense within Exelon’s Consolidated Statements of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $35 million, $22 million and $135 million for the years ended December 31, 2016, 2015 and 2014, respectively, was recorded in Operating revenues or Purchase power and fuel expense within Generation’s Consolidated Statements of Operations and Comprehensive Income

Acquired Intangible Assets and Liabilities

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

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

Service Contract Backlog. The service contract backlog intangibles were determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the contracts. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include estimated revenues and expenses to complete the contracts as well as 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 service contract backlog 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, PECO, DPL and ACE)

Exelon’s, Generation’s, ComEd’s, PECO's, DPL's and ACE'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, ComEd, DPL and ACE) and AECs (Exelon and PECO). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Generally, revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer, otherwise, the revenue is recognized upon physical transfer of the REC. As of December 31, 2016, and 2015, PECO had current AECs of $1 million and $2 million, respectively. PECO had no noncurrent AECs as of December 31, 2016 and 2015. As of December 31, 2016, and 2015, Generation had current RECs of $317 million and $251 million, respectively, and $29 million and $56 million of noncurrent REC's, respectively. ComEd had no current RECs as of December 31, 2016 and $5 million as of December 31, 2015. ComEd had no noncurrent RECs as of December 31, 2016 and 2015. As of December 31, 2016 and 2015, DPL had current RECs of $11 million and $9 million, respectively. DPL had no noncurrent RECs as of December 31, 2016 and 2015. As of December 31, 2016 and 2015, ACE had current RECs of $1 million. ACE had no noncurrent RECs as of December 31, 2016 and 2015. See Note 3—Regulatory Matters and Note 24—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 (All Registrants)

Fair Value of Financial Assets and Liabilities (All Registrants)

12 Months Ended

Dec. 31, 2016

Fair Value Disclosures [Abstract]

12. Fair Value of Financial Assets and Liabilities (All Registrants)

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, 2016 and 2015:

Exelon



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,267	$	—	$	1,267	$	—	$	1,267
Long-term debt (including amounts due within one year) ^(a)	34,005		1,113		31,741		1,959		34,813
Long-term debt to financing trusts ^(b)	641		—		—		667		667
SNF obligation	1,024		—		732		—		732



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

Generation



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	699	$	—	$	699	$	—	$	699
Long-term debt (including amounts due within one year) ^(a)	9,241		—		7,482		1,670		9,152
SNF obligation	1,024		—		732		—		732



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

ComEd



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	7,033	$	—	$	7,585	$	—	$	7,585
Long-term debt to financing trusts ^(b)	205		—		—		215		215



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

PECO



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	2,580	$	—	$	2,794	$	—	$	2,794
Long-term debt to financing trusts	184		—		—		192		192



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

BGE



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	45	$	—	$	45	$	—	$	45
Long-term debt (including amounts due within one year) ^(a)	2,322		—		2,467		—		2,467
Long-term debt to financing trusts ^(b)	252		—		—		260		260



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

PHI



	December 31, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	522	$	—	$	522	$	—	$	522
Long-term debt (including amounts due within one year) ^(a)	5,898		—		5,520		289		5,809



	December 31, 2015
	Carrying Amount		Fair Value
Predecessor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	958	$	—	$	958	$	—	$	958
Long-term debt (including amounts due within one year) ^(a)	5,279		—		5,231		586		5,817
Preferred stock	183		—		—		183		183

Pepco



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	23	$	—	$	23	$	—	$	23
Long-term debt (including amounts due within one year) ^(a)	2,349		—		2,788		8		2,796



	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	64	$	—	$	64	$	—	$	64
Long-term debt (including amounts due within one year) ^(a)	2,351		—		2,673		—		2,673

DPL



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	1,340	$	—	$	1,383	$	—	$	1,383



	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	105	$	—	$	105	$	—	$	105
Long-term debt (including amounts due within one year) ^(a)	1,265		—		1,185		103		1,288

ACE



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	1,155	$	—	$	1,007	$	280	$	1,287



	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	5	$	—	$	5	$	—	$	5
Long-term debt (including amounts due within one year) ^(a)	1,201		—		1,044		280		1,324

________

(a)

Includes unamortized debt issuance costs, which are not fair valued, of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE respectively, as of December 31, 2016. Includes unamortized debt issuance costs, which are not fair valued, of $180 million, $70 million, $38 million, $15 million, $9 million, $49 million, $31 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE respectively, as of December 31, 2015.


(b)	Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016 and December 31, 2015.

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

Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3. The fair value of Exelon's equity units (Level 1) are valued based on publicly traded securities issued by Exelon.

The fair value of Generation’s, Pepco's and PHI'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 monthly or quarterly basis and the carrying value approximates fair value (Level 2). When trading data is available on variable rate project financing debt, the fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2). Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.

SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2030 and 2025 as of December 31, 2016 and 2015, respectively. See Note 24 - Commitments and Contingencies for additional information regarding the change in estimated settlement date.

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.

Preferred Stock. The fair value of these securities is determined based on the carrying value of the shares per the Subscription Agreement between PHI and Exelon. See Note 19 - Mezzanine Equity for further details.

Recurring Fair Value Measurements

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


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


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


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

Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Additionally, there were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2016 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.

Generation and Exelon

In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below. See Note 1 - Significant Accounting Policies for additional information.

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, 2016 and 2015:



	Generation										Exelon
As of December 31, 2016	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling			Total
Assets
Cash equivalents ^(a)	$	39	$	—	$	—	$	—	$	39	$	373	$	—	$	—	$	—		$	373
NDT fund investments
Cash equivalents ^(b)	110		19		—		—		129		110		19		—		—			129
Equities	3,551		452		—		2,011		6,014		3,551		452		—		2,011			6,014
Fixed income
Corporate debt	—		1,554		250		—		1,804		—		1,554		250		—			1,804
U.S. Treasury and agencies	1,291		29		—		—		1,320		1,291		29		—		—			1,320
Foreign governments	—		37		—		—		37		—		37		—		—			37
State and municipal debt	—		264		—		—		264		—		264		—		—			264
Other ^(c)	—		59		—		493		552		—		59		—		493		—	552
Fixed income subtotal	1,291		1,943		250		493		3,977		1,291		1,943		250		493			3,977
Middle market lending	—		—		427		71		498		—		—		427		71			498
Private equity	—		—		—		148		148		—		—		—		148			148
Real estate	—		—		—		326		326		—		—		—		326			326
NDT fund investments subtotal ^(d)	4,952		2,414		677		3,049		11,092		4,952		2,414		677		3,049			11,092
Pledged assets for Zion Station decommissioning
Cash equivalents	11		—		—		—		11		11		—		—		—			11
Equities	—		2		—		—		2		—		2		—		—			2
Fixed Income - U.S. Treasury and agencies	16		1		—		—		17		16		1		—		—			17
Middle market lending	—		—		19		64		83		—		—		19		64			83
Pledged assets for Zion Station decommissioning subtotal ^(e)	27		3		19		64		113		27		3		19		64			113
Rabbi trust investments
Cash equivalents	2		—		—		—		2		74		—		—		—			74
Mutual funds	19		—		—		—		19		50		—		—		—			50



	Generation														Exelon
As of December 31, 2016	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Fixed income	—			—			—			—		—			—			16			—			—		16
Life insurance contracts	—			18			—			—		18			—			64			20			—		84
Rabbi trust investments subtotal	21			18			—			—		39			124			80			20			—		224
Commodity derivative assets
Economic hedges	1,356			2,505			1,229			—		5,090			1,358			2,505			1,229			—		5,092
Proprietary trading	3			50			23			—		76			3			50			23			—		76
Effect of netting and allocation of collateral ^(f)	(1,162		)	(2,142		)	(481		)	—		(3,785		)	(1,164		)	(2,142		)	(481		)	—		(3,787		)
Commodity derivative assets subtotal	197			413			771			—		1,381			197			413			771			—		1,381
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			16			—			—		16
Economic hedges	—			28			—			—		28			—			28			—			—		28
Proprietary trading	3			2			—			—		5			3			2			—			—		5
Effect of netting and allocation of collateral	(2		)	(19		)	—			—		(21		)	(2		)	(19		)	—			—		(21		)
Interest rate and foreign currency derivative assets subtotal	1			11			—			—		12			1			27			—			—		28
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,237			2,859			1,509			3,113		12,718			5,674			2,937			1,529			3,113		13,253
Liabilities
Commodity derivative liabilities
Economic hedges	(1,267		)	(2,378		)	(794		)	—		(4,439		)	(1,267		)	(2,378		)	(1,052		)	—		(4,697		)
Proprietary trading	(3		)	(50		)	(26		)	—		(79		)	(3		)	(50		)	(26		)	—		(79		)
Effect of netting and allocation of collateral ^(f)	1,233			2,339			542			—		4,114			1,233			2,339			542			—		4,114
Commodity derivative liabilities subtotal	(37		)	(89		)	(278		)	—		(404		)	(37		)	(89		)	(536		)	—		(662		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(10		)	—			—		(10		)	—			(10		)	—			—		(10		)
Economic hedges	—			(21		)	—			—		(21		)	—			(21		)	—			—		(21		)
Proprietary trading	(4		)	—			—			—		(4		)	(4		)	—			—			—		(4		)
Effect of netting and allocation of collateral	4			19			—			—		23			4			19			—			—		23
Interest rate and foreign currency derivative liabilities subtotal	—			(12		)	—			—		(12		)	—			(12		)	—			—		(12		)
Deferred compensation obligation	—			(34		)	—			—		(34		)	—			(136		)	—					(136		)
Total liabilities	(37		)	(135		)	(278		)	—		(450		)	(37		)	(237		)	(536		)	—		(810		)
Total net assets	$	5,200		$	2,724		$	1,231		$	3,113	$	12,268		$	5,637		$	2,700		$	993		$	3,113	$	12,443



	Generation										Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents ^(a)	$	104	$	—	$	—	$	—	$	104	$	5,766	$	—	$	—	$	—	$	5,766
NDT fund investments
Cash equivalents ^(b)	219		92		—		—		311		219		92		—		—		311
Equities	3,008		—		—		1,894		4,902		3,008		—		—		1,894		4,902



	Generation									Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
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)	—		147		—		390	537		—		147		—		390	537
Fixed income subtotal	1,323		2,373		242		390	4,328		1,323		2,373		242		390	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		2,465		670		2,660	10,345		4,550		2,465		670		2,660	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	—		—		22		105	127		—		—		22		105	127
Pledged assets for Zion Station decommissioning subtotal ^(e)	7		71		22		105	205		7		71		22		105	205
Rabbi trust investments
Mutual funds	17		—		—		—	17		48		—		—		—	48
Life insurance contracts	—		13		—		—	13		—		36		—		—	36
Rabbi trust investments subtotal	17		13		—		—	30		48		36		—		—	84
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 ^(f)	(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		3,473		1,898		2,765	12,815		10,372		3,521		1,898		2,765	18,556
Liabilities
Commodity derivative liabilities



	Generation														Exelon
As of December 31, 2015	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
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 ^(f)	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
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		$	3,208		$	1,776		$	2,765	$	12,453		$	10,397		$	3,187		$	1,529		$	2,765	$	17,878

_________________________

(a)

Generation excludes cash of $252 million and $329 million at December 31, 2016 and 2015 and restricted cash of $157 million and $121 million at December 31, 2016 and 2015. Exelon excludes cash of $360 million and $763 million at December 31, 2016 and 2015 and restricted cash of $180 million and $178 million at December 31, 2016 and 2015 and includes long term restricted cash of $25 million at December 31, 2016, which is reported in other deferred debits on the balance sheet.


(b)	Includes $29 million and $52 million of cash received from outstanding repurchase agreements at December 31, 2016 and 2015, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

Includes derivative instruments of $(2) million and $(8) million, which have a total notional amount of $933 million and $1,236 million at December 31, 2016 and 2015, 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 $(31) million and $(3) million at December 31, 2016 and 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.


(e)	Excludes net assets of less than $1 million and $1 million at December 31, 2016 and 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)

Collateral posted to/(received from) counterparties totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2016. 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.

ComEd, PECO and BGE

The following tables present assets and liabilities measured and recorded at fair value on ComEd's, PECO's and BGE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2016 and 2015:



	ComEd											PECO										BGE
As of December 31, 2016	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	20	$	—		$	—		$	20		$	45	$	—		$	—	$	45		$	36	$	—		$	—	$	36
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			4		—			—		4
Total assets	20		—			—			20			52		10			—		62			40		—			—		40
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities ^(b)	—		—			(258		)	(258		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(258		)	(266		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	20	$	(8	)	$	(258	)	$	(246	)	$	52	$	(1	)	$	—	$	51		$	40	$	(4	)	$	—	$	36



	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 ^(a)	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			4		—			—		4
Life insurance contracts	—		—			—			—			—		12			—		12			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		12			—		20			4		—			—		4
Total assets	29		—			—			29			279		12			—		291			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	$	—		$	—	$	279		$	29	$	(4	)	$	—	$	25

_________________________

(a)

ComEd excludes cash of $36 million and $38 million at December 31, 2016 and 2015 and restricted cash of $2 million and $2 million at December 31, 2016 and 2015. PECO excludes cash of $22 million and $27 million at December 31, 2016 and 2015. BGE excludes cash of $13 million and $6 million at December 31, 2016 and 2015 and restricted cash of less than $1 million and $2 million at December 31, 2016 and 2015 and includes long term restricted cash of $2 million at December 31, 2016, which is reported in other deferred debits on the balance sheet.


(b)	The Level 3 balance consists of the current and noncurrent liability of $19 million and $239 million, respectively, at December 31, 2016, and $23 million and $224 million, respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL and ACE

The following tables present assets and liabilities measured and recorded at fair value on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2016 and December 31, 2015:



	Successor											Predecessor
	As of December 31, 2016											As of December 31, 2015
PHI	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	217		$	—		$	—	$	217		$	42		$	—		$	—	$	42
Mark-to-market derivative assets ^(b)(c)	2			—			—		2			—			—			18		18
Effect of netting and allocation of collateral	(2		)	—			—		(2		)	—			—			—		—
Mark-to-market derivative assets subtotal	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			16			—		16			—			15			—		15
Life insurance contracts	—			22			20		42			—			27			19		46
Rabbi trust investments subtotal	73			38			20		131			12			42			19		73
Total assets	290			38			20		348			54			42			37		133
Liabilities
Deferred compensation obligation	—			(28		)	—		(28		)	—			(30		)	—		(30		)
Mark-to-market derivative liabilities ^(b)	—			—			—		—			(2		)	—			—		(2		)
Effect of netting and allocation of collateral	—			—			—		—			2			—			—		2
Mark-to-market derivative liabilities subtotal	—			—			—		—			—			—			—		—
Total liabilities	—			(28		)	—		(28		)	—			(30		)	—		(30		)
Total net assets	$	290		$	10		$	20	$	320		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of December 31, 2016	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents ^(a)	$	33	$	—		$	—	$	33		$	42		$	—		$	—	$	42		$	130	$	—	$	—	$	130
Mark-to-market derivative assets ^(b)	—		—			—		—			2			—			—		2			—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		16			—		16			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			19		41			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		38			19		100			—			—			—		—			—		—		—		—
Total assets	76		38			19		133			42			—			—		42			130		—		—		130
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	76	$	33		$	19	$	128		$	42		$	(1	)	$	—	$	41		$	130	$	—	$	—	$	130



	Pepco										DPL											ACE
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 ^(a)	$	2	$	—		$	—	$	2		$	—		$	—		$	—	$	—		$	30	$	—	$	—	$	30
Rabbi trust investments
Cash equivalents	11		—			—		11			—			—			—		—			—		—		—		—
Fixed income	—		15			—		15			—			—			—		—			—		—		—		—
Life insurance contracts	—		23			19		42			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	11		38			19		68			—			—			—		—			—		—		—		—
Total assets	13		38			19		70			—			—			—		—			30		—		—		30
Liabilities
Deferred compensation obligation	—		(6		)	—		(6		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities ^(b)	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			2			—			—		2			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(6		)	—		(6		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	13	$	32		$	19	$	64		$	—		$	(1	)	$	—	$	(1	)	$	30	$	—	$	—	$	30

_______

(a)

PHI excludes cash of $19 million and $16 million at December 31, 2016 and 2015 and includes long term restricted cash of $23 million and $18 million at December 31, 2016 and 2015 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $9 million and $5 million at December 31, 2016 and 2015. DPL excludes cash of $4 million and $5 million at December 31, 2016 and 2015. ACE excludes cash of $3 million and $3 million at December 31, 2016 and 2015 and includes long term restricted cash of $23 million and $18 million at December 31, 2016 and 2015 which is reported in other deferred debits on the balance sheet.


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


(c)	Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 19 - Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2016 and 2015:



																			Successor
	Generation															ComEd			PHI ^(c)						Exelon
For the year ended December 31, 2016	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(a)			Life Insurance Contracts			Eliminated in Consolidation			Total
Balance as of January 1, 2016	$	670		$	22		$	1,051			$	33	$	1,776		$	(247	)	$	—		$	—		$	1,529
Included due to merger	—			—			—				—		—			—			20			—			20
Total realized / unrealized gains (losses)
Included in net income	7			—			(568		)	^(b)	1		(560		)	—			3			—			(557		)
Included in noncurrent payables to affiliates	16			—			—				—		16			—			—			(16		)	—
Included in regulatory assets/liabilities	—			—			—				—		—			(11		)	—			16			5
Change in collateral	—			—			(141		)		—		(141		)	—			—			—			(141		)
Purchases, sales, issuances and settlements																			—
Purchases	143			2			342			^(d)	7		494			—			—			—			494
Sales	(1		)	(5		)	(9		)		—		(15		)	—			—			—			(15		)
Issuances	—			—			—				—		—			—			(3		)	—			(3		)
Settlements	(144		)	—			—				—		(144		)	—			—			—			(144		)
Transfers into Level 3	—			—			1				1		2			—			—			—			2
Transfers out of Level 3	(14		)	—			(183		)		—		(197		)	—			—			—			(197		)
Balance as of December 31, 2016	$	677		$	19		$	493			$	42	$	1,231		$	(258	)	$	20		$	—		$	993
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2016	$	5		$	—		$	109			$	—	$	114		$	—		$	2		$	—		$	116




	Generation																ComEd						Exelon
For the year ended December 31, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives ^(d)				Other Investments			Total Generation			Mark-to-Market Derivatives^(a)			Eliminated in Consolidation			Total
Balance as of January 1, 2015	$	605		$	50		$	1,050			$	3		$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income	4			—			22			^(b)	1			27			—			—			27
Included in noncurrent payables to affiliates	18			—			—				—			18			—			(18		)	—
Included in payable for Zion Station decommissioning	—			(2		)	—				—			(2		)	—			—			(2		)
Included in regulatory assets/liabilities	—			—			—				—			—			(40		)	18			(22		)
Change in collateral	—			—			29				—			29			—			—			29
Purchases, sales, issuances and settlements
Purchases	146			2			144				30			322			—			—			322
Sales	(8		)	(28		)	(25		)		—			(61		)	—			—			(61		)
Settlements	(95		)	—			—				—			(95		)	—			—			(95		)
Transfers into Level 3	4			—			80				—			84			—			—			84
Transfers out of Level 3	(4		)	—			(249		)		(1		)	(254		)	—			—			(254		)
Balance as of December 31, 2015	$	670		$	22		$	1,051			$	33		$	1,776		$	(247	)	$	—		$	1,529
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, 2015	$	2		$	—		$	856			$	—		$	858		$	—		$	—		$	858

_________________________

(a)

Includes $29 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2016. Includes $55 million of decreases in fair value and a reduction for realized losses due to settlements of $(15) million for the year ended December 31, 2015.


(b)	Includes a reduction for the reclassification of $677 million and $834 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2016 and 2015, respectively.


(c)	Successor period represents activity from March 24, 2016 to December 31, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco and DPL for the year ended December 31, 2016.


(d)	Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.



	Successor			Predecessor
	March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016					December 31, 2015
PHI	Life Insurance Contracts			Preferred Stock			Life Insurance Contracts		Preferred Stock		Life Insurance Contracts
Beginning Balance	$	20		$	18		$	19	$	3	$	19
Total realized / unrealized gains (losses)
Included in net income	3			(18		)	1		15		5
Purchases, sales, issuances and settlements
Issuances	(3		)	—			—		—		(3		)
Settlements	—			—			—		—		(2		)
Ending Balance	$	20		$	—		$	20	$	18	$	19
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	2		$	—		$	1	$	15	$	3



	December 31, 2016					December 31, 2015
	Pepco			DPL		Pepco			DPL
	Life Insurance Contracts			Life Insurance Contracts		Life Insurance Contracts			Life Insurance Contracts
Balance as of December 31	$	19		$	—	$	18		$	1
Total realized / unrealized gains (losses)
Included in net income	3			—		5			—
Purchases, sales, issuances and settlements
Issuances	(3		)	—		(3		)	—
Settlements	—			—		(1		)	(1		)
Balance as of December 31	$	19		$	—	$	19		$	—
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period	$	3		$	—	$	3		$	—

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, 2016 and 2015:



	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, 2016	$	(477	)	$	(91	)	$	7	$	(477	)	$	(91	)	$	10
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2016	$	154		$	(45	)	$	5	$	154		$	(45	)	$	7



	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	)	$	2	$	858	$	(2	)	$	2



	Successor		Predecessor
	PHI		PHI					Pepco
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016			December 31, 2015		December 31, 2016		December 31, 2015
	Other, net		Other, net					Other, net
Total (losses) gains included in net income	$	3	$	(17	)	$	20	$	3	$	5
Change in the unrealized gains (losses) relating to assets and liabilities held	2		1			18		3		3

________________________


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

Valuation Techniques Used to Determine Fair Value

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

Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ cash equivalents include investments with 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.

Preferred Stock Derivative (PHI). In connection with entering into the PHI Merger Agreement, as further described in Note 19 - Mezzanine Equity, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued quarterly using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore, were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of March 23, 2016. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.

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

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

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

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

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.

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

As of December 31, 2016, Generation has outstanding commitments to invest in middle market lending, private equity investments and real estate investments of approximately $284 million, $65 million, and $205 million, respectively. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2016. 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, 2016, 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, BGE, PHI, Pepco, DPL and ACE). The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3.

Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are 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, BGE, PHI, Pepco, DPL and ACE). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

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

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

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

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

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.65 and $0.34 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 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, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Exelon and Generation) ^(a)(c)	$	435		Discounted Cash Flow	Forward power price	$11	-	$130
					Forward gas price	$1.72	-	$9.20
				Option Model	Volatility percentage	8%	-	173%

Mark-to-market derivatives—Proprietary trading (Exelon and Generation) ^(a)(c)	$	(3	)	Discounted Cash Flow	Forward power price	$19	-	$79

Mark-to-market derivatives (Exelon and ComEd)	$	(258	)	Discounted Cash Flow	Forward heat rate ^(b)	8x	-	9x
					Marketability reserve	3%	-	8%
					Renewable factor	89%	-	121%

_________________________


(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 $61 million as of December 31, 2016.



Type of trade	Fair Value at December 31, 2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Exelon and Generation) ^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11	-	$88
					Forward gas price	$1.18	-	$8.95
				Option Model	Volatility percentage	5%	-	152%

Mark-to-market derivatives— Proprietary trading (Exelon and Generation) ^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13	-	$78

Mark-to-market derivatives (Exelon and 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

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

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

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

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

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments (All Registrants)

12 Months Ended

Dec. 31, 2016

Derivative Financial Instruments (All Registrants)

13. Derivative Financial Instruments (All Registrants)

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

Commodity Price Risk (All Registrants)

To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and 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 Generation, 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. Generation has also entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators, as well as contractual obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. These non-derivative contracts are accounted for primarily under the accrual method of accounting. 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, 2016, the proportion of expected generation hedged for the major reportable segments was 91%-94%, 56%-59% and 28%-31% for 2017, 2018, and 2019, 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 generating facilities 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. 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. PECO has certain full requirements 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 2016 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2016 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 25% 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.

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

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

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

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

Proprietary Trading. 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 6,179 GWh, 7,310 GWh and 10,571 GWh for the years ended December 31, 2016, 2015 and 2014, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.

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

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, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon and Generation had $659 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 $7 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2016. To manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2016:



	Generation															Exelon Corporate		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (current assets)	$	—		$	17		$	4		$	(13	)	$	8		$	—	$	8
Mark-to-market derivative assets (noncurrent assets)	—			11			1			(8		)	4			16		20
Total mark-to-market derivative assets	—			28			5			(21		)	12			16		28
Mark-to-market derivative liabilities (current liabilities)	(7		)	(13		)	(2		)	14			(8		)	—		(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(3		)	(8		)	(2		)	9			(4		)	—		(4		)
Total mark-to-market derivative liabilities	(10		)	(21		)	(4		)	23			(12		)	—		(12		)
Total mark-to-market derivative net assets (liabilities)	$	(10	)	$	7		$	1		$	2		$	—		$	16	$	16

_________________________

(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, 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		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)

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	2016			2015			2014			2016		2015		2014
	Income Statement Location	Gain (Loss) on Swaps									Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	—		$	(1	)	$	(16	)	$	—	$	—	$	2
Exelon	Interest expense	$	(9	)	$	3		$	14		$	23	$	14	$	(1	)

______________________


(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, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $16 million. At December 31, 2015, Exelon had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $25 million. During the years ended December 31, 2016 and 2015, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $14 million gain and $17 million gain, respectively.

Cash Flow Hedges. During the second quarter of 2016, Exelon entered into $90 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the third quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination.

During the first and second quarter of 2016, Exelon entered into $600 million and $100 million of floating-to-fixed forward starting interest rate swaps, respectively, to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as cash flow hedges. Exelon terminated the swaps during the second quarter of 2016 upon issuance of the debt. Exelon recognized a loss of $3 million related to the swaps and $3 million of AOCI will be amortized into Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income over the term of the debt. See Note 14 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

During the first quarter of 2016, Exelon entered into a $100 million floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swap was designated as a cash flow hedge. Exelon terminated the swap during the first quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination of the swap and an immaterial amount of AOCI will be amortized into Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income over the term of the debt.

During the third quarter of 2014, EGTP, 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 $495 million as of December 31, 2016 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2016, the subsidiary had a $9 million derivative liability related to the swap.

During the first quarter of 2014, EGR, 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 $164 million as of December 31, 2016 and expire in 2020. The swaps are designated as cash flow hedges. At December 31, 2016, the subsidiary had a $1 million derivative liability related to the swaps.

During the second quarter of 2002, PHI entered into treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate debt commencing in August 2002 to manage a portion of its interest rate exposure. Upon issuance of the fixed-rate debt in August 2002, the treasury rate locks were terminated at a loss and the loss was deferred in AOCI. As a result of the PHI Merger, the remaining unamortized deferred loss recorded in AOCI was adjusted to zero through application of purchase accounting.

During the years ended December 31, 2016 and 2015, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships was 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. During the first quarter of 2016, upon the termination of debt, Generation terminated the swaps. The total notional amount of the swaps were $25 million. No gain or loss was recognized as a result of the termination of the swaps.

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. During the first quarter of 2016, upon the termination of debt, Generation terminated the swap. The total notional amount of the swap was $24 million. No gain or loss was recognized as a result of the termination of the swap.

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, 2016, Generation had no notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $85 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, BGE, PHI and DPL)

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, 2016 and 2015, $8 million of cash collateral held and $3 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.

In the table below, DPL's economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column.

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2016:



																							Successor
	Generation												ComEd			DPL							PHI		Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)			Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,623		$	55		$	(2,769	)	$	909		$	—		$	2	$	(2	)	$	—	$	—	$	909
Mark-to-market derivative assets (noncurrent assets)	1,467			21			(1,016		)	472			—			—		—			—		—		472
Total mark-to-market derivative assets	5,090			76			(3,785		)	1,381			—			2		(2		)	—		—		1,381
Mark-to-market derivative liabilities (current liabilities)	(3,165		)	(54		)	2,964			(255		)	(19		)	—		—			—		—		(274		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,274		)	(25		)	1,150			(149		)	(239		)	—		—			—		—		(388		)
Total mark-to-market derivative liabilities	(4,439		)	(79		)	4,114			(404		)	(258		)	—		—			—		—		(662		)
Total mark-to-market derivative net assets (liabilities)	$	651		$	(3	)	$	329		$	977		$	(258	)	$	2	$	(2	)	$	—	$	—	$	719

______________________

(a)

Exelon, Generation, PHI and DPL 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 $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.


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


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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2015:



																												Predecessor
	Generation												ComEd			Exelon			DPL							PHI Corporate		PHI
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives			Economic Hedges^(e)			Collateral and Netting^(a)		Subtotal		Other^(d)		Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,236		$	108		$	(3,994	)	$	1,350		$	—		$	1,350		$	—		$	—	$	—	$	18	$	18
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			—			—		—		18		18
Mark-to-market derivative liabilities (current liabilities)	(4,907		)	(94		)	4,827			(174		)	(23		)	(197		)	(2		)	2		—		—		—
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		)	(2		)	2		—		—		—
Total mark-to-market derivative net assets (liabilities)	$	516		$	3		$	1,234		$	1,753		$	(247	)	$	1,506		$	(2	)	$	2	$	—	$	18	$	18

______________________

(a)

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit 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.


(d)	Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 19 - Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.


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

Cash Flow Hedges (Exelon and Generation). The tables below provide the activity of OCI related to cash flow hedges for the years ended December 31, 2016 and 2015, 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 OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
For the Year Ended December 31, 2016	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
AOCI derivative loss at December 31, 2015		$	(21	)		$	(19	)
Effective portion of changes in fair value		(6		)		(6		)
Reclassifications from AOCI to net income	Interest expense	8			^(a)	8			^(a)
AOCI derivative loss at December 31, 2016		$	(19	)		$	(17	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
For the Year Ended December 31, 2015	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2014		$	(18	)		$	(28	)
Effective portion of changes in fair value		(8		)		(12		)
Reclassifications from AOCI to net income	Other, net	—				16			^(b)
Reclassifications from AOCI to net income	Interest Expense	7			^(c)	7			^(c)
Reclassifications from AOCI to net income	Operating Revenues	(2		)		(2		)
Accumulated OCI derivative loss at December 31, 2015		$	(21	)		$	(19	)

_______________________


(a)	Amount is net of related income tax expense of $5 million for the year ended December 31, 2016.


(b)	Amount is net of related income tax expense 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 and 2014, the effect of Exelon's and Generation's former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from OCI to earnings was a $2 million and $195 million pre-tax gain, respectively. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods relating to energy-related hedges positions as all were de-designated prior to the Constellation 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. For the years ended December 31, 2016, 2015 and 2014, 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								Exelon
Year Ended December 31, 2016	Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	5		$	208	$	213		$	213
Reclassification to realized at settlement of commodity positions	(495		)	251		(244		)	(244		)
Net commodity mark-to-market gains (losses)	(490		)	459		(31		)	(31		)
Change in fair value of treasury positions	(2		)	—		(2		)	(2		)
Reclassification to realized at settlement of treasury positions	(8		)	—		(8		)	(8		)
Net treasury mark-to-market gains (losses)	(10		)	—		(10		)	(10		)
Net mark-to-market gains (losses)	$	(500	)	$	459	$	(41	)	$	(41	)



	Generation									Exelon Corporate		Exelon
Year Ended December 31, 2015	Operating Revenues			Purchased Power and Fuel			Total			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												Exelon Corporate			Exelon
Year Ended December 31, 2014	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			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	)

Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2016, 2015, and 2014 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 and foreign exchange derivative contracts to hedge risk associated with the interest rate and foreign exchange components of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. 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.



	For the Years Ended December 31,
	2016			2015			2014
Change in fair value of commodity positions	$	23		$	8		$	(1	)
Reclassification to realized at settlement of commodity positions	(21		)	(14		)	(29		)
Net commodity mark-to-market gains (losses)	2			(6		)	(30		)
Change in fair value of treasury positions	(1		)	8			1
Reclassification to realized at settlement of treasury positions	—			(10		)	3
Net treasury mark-to market gains (losses)	(1		)	(2		)	4
Net mark-to market gains (losses)	$	1		$	(8	)	$	(26	)

Credit Risk (All Registrants)

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, 2016. 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. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $14 million, $33 million $26 million, $44 million, $16 million and $9 million as of December 31, 2016, respectively.



Rating as of December 31, 2016	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	$	995	$	—	$	995	1	$	328
Non-investment grade	118		16		102		—	—
No external ratings
Internally rated — investment grade	352		1		351		—	—
Internally rated — non-investment grade	72		8		64		—	—
Total	$	1,537	$	25	$	1,512	1	$	328



Net Credit Exposure by Type of Counterparty	December 31, 2016
Financial institutions	$	116
Investor-owned utilities, marketers, power producers	689
Energy cooperatives and municipalities	636
Other	71
Total	$	1,512

______________________


(a)	As of December 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $9 million of cash and $16 million of letters of credit. The credit collateral does not include non-liquid collateral.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on 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, 2016, ComEd’s net credit exposure to suppliers was approximately $1 million.

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters 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, 2016, 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, 2016, PECO had no material credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters 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, 2016, 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, 2016, BGE had credit exposure of $8 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers.

Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of December 31, 2016, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of December 31, 2016, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

Collateral and Contingent-Related Features (All Registrants)

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	2016			2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(960	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	627			684
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(333	)	$	(248	)

__________________________


(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 $347 million and letters of credit posted of $284 million, and cash collateral held of $24 million and letters of credit held of $28 million as of December 31, 2016 for external counterparties with derivative positions. 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 at December 31, 2015 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P or Ba1 by Moody's), Generation would have been required to post additional collateral of $1.9 billion and $2.0 billion as of December 31, 2016 and 2015, 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, 2016, Generation’s swaps had an immaterial fair value and Exelon's swaps were in an asset position with a fair value of $16 million.

See Note 26 — 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, 2016, ComEd held approximately $3 million in 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, 2016, 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. If ComEd lost its investment grade credit rating as of December 31, 2016, it would have been required to post approximately $19 million of collateral to its counterparties. 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, 2016, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2016, PECO could have been required to post approximately $31 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, 2016, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2016, BGE could have been required to post approximately $62 million of collateral to its counterparties.

Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require Pepco to post collateral.

DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require DPL to post collateral.

DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating as of December 31, 2016, DPL could have been required to post an additional amount of approximately $10 million of collateral to its natural gas counterparties.

ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require ACE to post collateral.

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

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Debt and Credit Agreements (All Registrants)

Debt and Credit Agreements (All Registrants)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

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

Commercial Paper

The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at December 31, 2016 and December 31, 2015:



	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	2016 (a)(b)		2015 (a)(b)		2016		2015		2016		2015
Exelon Corporate	$	600	$	500	$	—	$	—	0.70	%	n.a.
Generation	5,300		5,450		620		—		0.94	%	0.49	%
ComEd	1,000		1,000		—		294		0.77	%	0.53	%
PECO	600		600		—		—		n.a		n.a.
BGE	600		600		45		210		0.77	%	0.48	%
PHI Corporate	—		875		—		484		1.03	%	0.80	%
Pepco	500		500		23		64		0.71	%	0.44	%
DPL	500		500		—		105		0.68	%	0.47	%
ACE	350		350		—		5		0.65	%	0.46	%
Total	$	9,450	$	10,375	$	688	$	1,162

_____________________


(a)	Excludes $500 million and $275 million in bilateral credit facilities that do not back Generation's commercial paper program at December 31, 2016 and 2015, respectively.

(b)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 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 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, 2016, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:



								Available Capacity at December 31, 2016
Borrower	Facility Type	Aggregate Bank Commitment ^(a)(b)		Facility Draws		Outstanding Letters of Credit^(c)		Actual		To Support Additional Commercial Paper ^(d)
Exelon Corporate	Syndicated Revolver	$	600	$	—	$	29	$	571	$	571
Generation	Syndicated Revolver	5,300		—		1,170		4,130		3,510
Generation	Bilaterals	500		75		306		119		—
ComEd	Syndicated Revolver	1,000		—		2		998		998
PECO	Syndicated Revolver	600		—		2		598		598
BGE	Syndicated Revolver	600		—		—		600		555
Pepco	Syndicated Revolver	300		—		—		300		277
DPL	Syndicated Revolver	300		—		—		300		300
ACE	Syndicated Revolver	300		—		1		299		299
Total		$	9,500	$	75	$	1,510	$	7,915	$	7,108

_______________________

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

(b)

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


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


(d)	Excludes $500 million in bilateral credit facilities that do not back Generation’s commercial paper program.

As of December 31, 2016, there was $75 million of borrowings under Generation's bilateral credit facilities.

The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, BGE, PHI, Pepco, DPL and ACE during 2016, 2015 and 2014. PECO did not have any short-term borrowings during 2016, 2015 or 2014.



Exelon
	2016			2015			2014
Average borrowings	$	1,125		$	499		$	571
Maximum borrowings outstanding	3,076			739			1,164
Average interest rates, computed on a daily basis	0.88		%	0.53		%	0.32		%
Average interest rates, at December 31	1.12		%	0.88		%	0.53		%
Generation
	2016			2015			2014
Average borrowings	$	536		$	1		$	93
Maximum borrowings outstanding	1,735			50			552
Average interest rates, computed on a daily basis	0.94		%	0.49		%	0.32		%
Average interest rates, at December 31	1.14		%	n.a.			n.a.



ComEd
	2016			2015			2014
Average borrowings	$	256		$	461		$	415
Maximum borrowings outstanding	755			684			597
Average interest rates, computed on a daily basis	0.77		%	0.53		%	0.33		%
Average interest rates, at December 31	n.a.			0.89		%	0.50		%
BGE
	2016			2015			2014
Average borrowings	$	143		$	37		$	64
Maximum borrowings outstanding	369			210			180
Average interest rates, computed on a daily basis	0.77		%	0.48		%	0.29		%
Average interest rates, computed at December 31	0.95		%	0.87		%	0.61		%
PHI
	Successor			Predecessor
	2016			2015			2014
Average borrowings	$	153		$	444		$	153
Maximum borrowings outstanding	559			784			369
Average interest rates, computed on a daily basis	1.03		%	0.90		%	0.56		%
Average interest rates, computed at December 31	n.a.			1.22		%	0.78		%
Pepco
	2016			2015			2014
Average borrowings	$	4		$	34		$	37
Maximum borrowings outstanding	73			190			209



Average interest rates, computed on a daily basis	0.71		%	0.44		%	0.28		%
Average interest rates, computed at December 31	0.90		%	0.68		%	0.46		%
DPL
	2016			2015			2014
Average borrowings	$	33		$	81		$	69
Maximum borrowings outstanding	116			179			177
Average interest rates, computed on a daily basis	0.68		%	0.47		%	0.26		%
Average interest rates, computed at December 31	n.a.			0.79		%	0.42		%
ACE
	2016			2015			2014
Average borrowings	$	—		$	175		$	112
Maximum borrowings outstanding	5			253			259
Average interest rates, computed on a daily basis	0.65		%	0.46		%	0.27		%
Average interest rates, computed at December 31	n.a.			0.65		%	0.52		%

Short-Term Loan Agreements

On July 30, 2015, PHI entered into a $300 million term loan agreement. The net proceeds of the loan were used to repay PHI's outstanding commercial paper and for general corporate purposes. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.95%, and all indebtedness thereunder is unsecured. On April 4, 2016, PHI repaid $300 million of its term loan in full.

On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to repay PHI's outstanding commercial paper, and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1%, and all indebtedness thereunder is unsecured, and the aggregate principal amount of all loans, together with any accrued but unpaid interest due under the Loan Agreement, must be repaid in full on or before March 27, 2017. The loan agreement is reflected in Exelon's and PHI's Consolidated Balance Sheets within Short-term borrowings.

On February 22, 2016, Generation and EDF entered into separate member revolving promissory notes with CENG to finance short-term working capital needs. The notes are scheduled to mature on January 31, 2017 and bear interest at a variable rate equal to LIBOR plus 1.75%. On July 25, 2016, CENG paid off the outstanding balances under each note.

Credit Agreements

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 will solely be utilized by Generation to issue lines of credit. This facility does not back Generation's commercial paper program.

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

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

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



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Prime based borrowings	27.5	27.5	7.5	0.0	0.0	7.5	7.5	7.5
LIBOR-based borrowings	127.5	127.5	107.5	90.0	100.0	107.5	107.5	107.5

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

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, 2016:

Exelon

Generation

ComEd

PECO

BGE

Pepco

DPL

ACE

Credit agreement threshold

2.50 to 1

3.00 to 1

2.00 to 1

At December 31, 2016, the interest coverage ratios at the Registrants were as follows:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Interest coverage ratio	7.03	11.81	6.89	8.77	10.47	6.24	8.42	5.84

Through May 26, 2016, when Pepco, DPL and ACE entered into a new restated credit agreement, as mentioned above, PHI, Pepco, DPL and ACE had maintained an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit, borrowing for general corporate purposes and supporting their commercial paper programs. The termination date of this credit facility was August 1, 2018.

The aggregate borrowing limit under the amended and restated credit facility was $1.5 billion, all or any portion of which could have been used to obtain loans and up to $500 million of which could have been used to obtain letters of credit. The facility also included a swingline loan sub-facility, pursuant to which each company could have made same day borrowings in an aggregate amount not to exceed 10% of the total amount of the facility. Any swingline loan had to be repaid by the borrower within fourteen days of receipt. The credit sublimit was $750 million for PHI and $250 million for each of Pepco, DPL and ACE. The sublimits could have been increased or decreased by the individual borrower during the term of the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease had to equal the total amount of the facility and (ii) the aggregate amount of credit used at any given time by (a) PHI could not exceed $1.25 billion and (b) each of Pepco, DPL or ACE could not exceed the lesser of $500 million and the maximum amount of short-term debt the company was permitted to have outstanding by its regulatory authorities. The total number of the sublimit reallocations could not exceed eight per year during the term of the facility.

The interest rate payable by each company on utilized funds was, at the borrowing company’s election, (i) the greater of the prevailing prime rate, the federal funds effective rate plus 0.5% and the one-month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar rate, plus a margin that varies according to the credit rating of the borrower.

In order for a borrower to use the facility, certain representations and warranties had to be true and correct, and the borrower had to be in compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excluded from the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contained certain covenants and other customary agreements and requirements that, if not complied with, resulted in an event of default and the acceleration of repayment obligations of one or more of the borrowers thereunder.

The absence of a material adverse change in PHI’s business, property, results of operations or financial condition was not a condition to the availability of credit under the credit agreement. The credit agreement did not include any rating triggers.

Variable Rate Demand Bonds

DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for this reason, are accounted for as short-term debt in accordance with GAAP. However, bonds submitted for purchase are remarketed by a remarketing agent on a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The bonds may be converted to a fixed-rate, fixed-term option to establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of December 31, 2016 and December 31, 2015, $105 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year on Exelon's, PHI's and DPL's Consolidated Balance Sheet.

Long-Term Debt

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2016 and 2015:

Exelon



							Maturity Date	December 31,
	Rates						Maturity Date	2016			2015
Long-term debt
Rate stabilization bonds	5.82	%	-	5.82	%		2017	$	41		$	120
First mortgage bonds ^(a)	1.70	%	-	7.90	%		2017 - 2046	14,123			9,019
Senior unsecured notes	1.55	%	-	7.60	%		2017 - 2046	11,868			9,803
Unsecured bonds	2.40	%	-	6.35	%		2021 - 2046	2,300			1,750
Pollution control notes	2.50	%	-	2.70	%		2025 - 2036	435			435
Nuclear fuel procurement contracts	3.15	%	-	3.35	%		2018 - 2020	105			127
Notes payable and other ^(b)(c)	1.43	%	-	7.83	%		2017 - 2053	576			314
Junior subordinated notes				6.50	%		2024	1,150			1,150
Contract payment - junior subordinated notes				2.50	%		2017	19			64
Long-term software licensing agreement				3.95	%		2024	103			111
Unsecured Tax-Exempt Bonds				5.40	%	—	2031	112			—
Medium-Terms Notes (unsecured)	6.81	%	-	7.72	%	—	2017 - 2027	40			—
Transition bonds	5.05	%	-	5.55	%	—	2020 - 2023	124			—
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%		2031 - 2037	1,400			1,162
Variable rates	3.18	%	-	5.00	%		2019 - 2021	915			1,058
Total long-term debt								33,311			25,113
Unamortized debt discount and premium, net								(68		)	(63		)
Unamortized debt issuance costs								(200		)	(180		)
Fair value adjustment								962			275
Long-term debt due within one year								(2,430		)	(1,500		)
Long-term debt								$	31,575		$	23,645
Long-term debt to financing trusts ^(d)
Subordinated debentures to ComEd Financing III				6.35	%		2033	$	206		$	206
Subordinated debentures to PECO Trust III				7.38	%		2028	81			81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103			103
Subordinated debentures to BGE Capital Trust II				6.20	%		2043	258			258
Total long-term debt to financing trusts								648			648
Unamortized debt issuance costs								(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, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.


(b)	Includes capital lease obligations of $69 million and $29 million at December 31, 2016 and 2015, respectively. Lease payments of $17 million, $18 million, $20 million, $5 million, $1 million, and $8 million will be made in 2017, 2018, 2019, 2020, 2021 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, 2016, $198 million was outstanding.


(d)	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	2016			2015
Long-term debt
Senior unsecured notes	2.00	%	-	7.60	%	2017 - 2042	$	5,971		$	5,971
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			435
Nuclear fuel procurement contracts	3.15	%	-	3.35	%	2018 - 2020	105			127
Notes payable and other ^(a)(b)	1.43	%	-	7.83	%	2017 - 2035	382			166
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,400			1,162
Variable rates	3.18	%	-	5.00	%	2019 - 2021	915			1,058
Total long-term debt							9,208			8,919
Fair value adjustment							115			127
Unamortized debt discount and premium, net							(17		)	(17		)
Unamortized debt issuance costs							(65		)	(70		)
Long-term debt due within one year							(1,117		)	(90		)
Long-term debt							$	8,124		$	8,869

______________________


(a)	Includes Generation’s capital lease obligations of $22 million and $21 million at December 31, 2016 and 2015, respectively. Generation will make lease payments of $5 million, $5 million, $6 million and $5 million and $1 million in 2017, 2018, 2019, 2020 and 2021 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, 2016, $198 million was outstanding.

ComEd



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds ^(a)	2.15	%	-	6.45	%	2017 - 2046	$	6,954		$	6,419
Notes payable and other^(b)	6.95	%	-	7.49	%	2018 - 2053	147			148
Total long-term debt							7,101			6,567
Unamortized debt discount and premium, net							(22		)	(20		)
Unamortized debt issuance costs							(46		)	(38		)
Long-term debt due within one year							(425		)	(665		)
Long-term debt							$	6,608		$	5,844
Long-term debt to financing trust ^(c)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Total long-term debt to financing trusts							206			206
Unamortized debt issuance costs							(1		)	(1		)
Long-term debt to financing trusts							$	205		$	205

______________________


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


(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2016 and 2015, respectively. Lease payments of less than $1 million will be made from 2017 through expiration at 2053.


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

PECO



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds ^(a)	1.70	%	-	5.95	%	2018 - 2044	$	2,600		$	2,600
Total long-term debt							2,600			2,600
Unamortized debt discount and premium, net							(5		)	(5		)
Unamortized debt issuance costs							(15		)	(15		)
Long-term debt due within one year							—			(300		)
Long-term debt							$	2,580		$	2,280
Long-term debt to financing trusts ^(b)
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)	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	2016			2015
Long-term debt
Rate stabilization bonds	5.82	%	-	5.82	%	2017	$	41		$	120
Senior unsecured notes	2.40	%	-	6.35	%	2021 - 2046	2,300			1,750
Total long-term debt							2,341			1,870
Unamortized debt discount and premium, net							(4		)	(3		)
Unamortized debt issuance costs							(15		)	(9		)
Long-term debt due within one year							(41		)	(378		)
Long-term debt							$	2,281		$	1,480
Long-term debt to financing trusts ^(a)
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							(6		)	(6		)
Long-term debt to financing trusts							$	252		$	252

___________________


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

PHI



							Successor			Predecessor
						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
Notes (unsecured)	6.13	%	-	7.45	%	2017 - 2032	$	266		$	456
First mortgage bonds	3.05	%	-	7.90	%	2018 - 2045	4,569			4,495
Unsecured Tax-Exempt Bonds				5.40	%	2031	112			112
Medium-Terms Notes (unsecured)	6.81	%	-	7.72	%	2017 - 2027	40			40
Transition bonds^(a)	5.05	%	-	5.55	%	2020 - 2023	124			171
Notes payable and other^(b)	6.20	%	-	8.88	%	2019 - 2021	46			57
Total long-term debt							5,157			5,331
Unamortized debt discount and premium, net							1			(2		)
Unamortized debt issuance costs							(2		)	(50		)
Fair value adjustment							742			—
Long-term debt due within one year							(253		)	(456		)
Long-term debt							$	5,645		$	4,823

________________


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


(b)	Includes Pepco's capital lease obligations of $39 million and $50 million at December 31, 2016 and 2015, respectively.

Pepco



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds^(a)	3.05	%	-	7.90	%	2022 - 2043	$	2,335		$	2,335
Notes payable and other^(b)	6.20	%	-	8.88	%	2019 - 2021	46			50
Total long-term debt							2,381			2,385
Unamortized debt discount and premium, net							(2		)	(3		)
Unamortized debt issuance costs							(30		)	(31		)
Long-term debt due within one year							(16		)	(11		)
Long-term debt							$	2,333		$	2,340

________________


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


(b)	Includes capital lease obligations of $39 million and $50 million at December 31, 2016 and 2015, respectively. Lease payments of $12 million, $13 million and $14 million will be made in 2017, 2018 and 2019, respectively.

DPL



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds^(a)	3.50	%	-	4.15	%	2023 - 2045	$	1,196		$	1,121
Unsecured Tax-Exempt Bonds				5.40	%	2031	112			112
Medium-Terms Notes (unsecured)	6.81	%	-	7.72	%	2017 - 2027	40			40
Total long-term debt							1,348			1,273
Unamortized debt discount and premium, net							2			2
Unamortized debt issuance costs							(10		)	(10		)
Long-term debt due within one year							(119		)	(204		)
Long-term debt							$	1,221		$	1,061

___________________


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

ACE



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds^(a)	3.38	%	-	7.75	%	2018 - 2036	$	1,038		$	1,039
Transition bonds ^(b)	5.05	%	-	5.55	%	2020 - 2023	124			171
Total long-term debt							1,162			1,210
Unamortized debt discount and premium, net							(1		)	(1		)
Unamortized debt issuance costs							(6		)	(8		)
Long-term debt due within one year							(35		)	(48		)
Long-term debt							$	1,120		$	1,153

___________________


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


(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2016 are $35 million in 2017, $31 million in 2018, $18 million in 2019, $19 million in 2020 and $21 million in 2021.

Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2017 through 2021 and thereafter are as follows:



Year	Exelon			Generation		ComEd			PECO			BGE			PHI		Pepco		DPL		ACE
2017	$	2,430		$	1,117	$	425		$	—		$	41		253		16		119		35
2018	1,742			104		840			500			—			298		13		4		281
2019	1,060			606		300			—			—			154		124		12		18
2020	3,331			1,912		500			—			—			19		—		—		19
2021	2,400			888		350			300			300			262		2		—		260
Thereafter	22,996		^(a)	4,581		4,892		^(b)	1,984		^(c)	2,258		^(d)	4,171		2,226		1,213		549
Total	$	33,959		$	9,208	$	7,307		$	2,784		$	2,599		$	5,157	$	2,381	$	1,348	$	1,162

____________________


(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.

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 were 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 2016, contract payments of $45 million related to the Contract Payment Obligation were included within Retirements of long-term debt in Exelon's Consolidated Statements of Cash Flows. 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 $2.8 billion of generating assets have been pledged as collateral at December 31, 2016. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project in Denver, Colorado. The agreement is scheduled to mature on June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2016, $6 million was outstanding.

CEU Upstream. In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserve based lending agreement (RBL) associated with certain Upstream oil and gas properties. The lenders do not have recourse against Exelon or Generation in the event of default pursuant to the RBL. Borrowings under this arrangement are secured by the assets and equity of CEU Holdings. The commitment level can be decreased if the assets no longer support the current borrowing base, which may result in repayment of a portion or all of the outstanding balance, or potential foreclosure of the assets. The commitment can be increased up to $500 million million if the assets support a higher borrowing base and CEU Holdings 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 on January 14, 2014 through January 2019. As of December 31, 2015, $68 million was outstanding under the facility with interest payable monthly at a variable rate equal to LIBOR plus 2.50% and the borrowing base committed under the facility was $85 million. The outstanding balance was classified as Long-term debt on Exelon's and Generation's Consolidated Balance Sheets.

In February 2016, as part of their semi-annual borrowing base re-determination testing, the RBL lenders notified CEU Holdings that the RBL borrowing base was decreased to $45 million, resulting in a “borrowing base deficiency” under the RBL of $23 million. Given the decline in value of the Upstream assets resulting from lower commodity prices, CEU Holdings chose not to provide the lenders with a formal plan for curing the borrowing base deficiency by March 31, 2016, as was required by the RBL. The lenders sent CEU Holdings a notice of event of default and demand for cure.

On June 16, 2016, CEU Holdings executed a forbearance agreement with the lenders which included terms stipulating roles and responsibilities governing a sales process, approval of the sale of the assets to be at the discretion of the lenders, and a sales timetable.

In December 2016, substantially all of the Upstream natural gas and oil exploration and production assets were sold for $37 million. The proceeds were used to reduce the debt balance by $31 million. The remaining proceeds of $6 million are being held in escrow and will be released at final settlement. In addition, during 2016, $15 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt balance of $22 million with interest payable monthly at a variable rate equal to LIBOR plus 2.75%. Upon disposition of all of the assets and the satisfaction of certain other conditions, CEU Holdings will be released of its obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation credit facilities or other debt of an Exelon entity. At December 31, 2016, the outstanding debt balance of $22 million was classified within Long term debt due within one year on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 4 - Mergers, Acquisitions, and Dispositions and Note 8 - Impairment of Long-Lived Assets for additional information.

Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solar construction project in Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2016, $9 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, 2016, $552 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2016, Generation had $106 million in letters of credit outstanding related to the project.

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, 2016, $543 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, 2016, the Continental Wind letter of credit facility had $108 million in letters of credit outstanding related to the project.

ExGen Renewables I. In February 2014, 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, 2016, $234 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, 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, 2016, $660 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 various interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 13 — Derivative Financial Instruments for additional information regarding interest rate swaps.

EGTP’s operating cash flows have been negatively impacted by certain market conditions including, but not limited to: low power prices, higher fuel prices and the seasonality of its cash flows. Despite the declining operating cash flows, EGTP remains in compliance with its covenants related to the project specific financing. Management continues to monitor the project entity’s short term liquidity needs.

Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2016, $141 million was outstanding.

SolGen. In September 2016, SolGen, LLC (SolGen), an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2016, $148 million was outstanding.

Income Taxes (All Registrants)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

Income Taxes (All Registrants)

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



																								Successor			Predecessor
	For the Year Ended December 31, 2016																							March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO		BGE			Pepco			DPL			ACE			PHI			PHI
Included in operations:
Federal
Current	$	60		$	513		$	(135	)	$	63	$	51		$	(118	)	$	(88	)	$	(26	)	$	(281	)	$	—
Deferred	607			(247		)	379			72		88			136			97			22			283			10
Investment tax credit amortization	(24		)	(20		)	(2		)	—		(1		)	—			—			—			(1		)	—
State
Current	39			45			(4		)	9		5			7			1			—			(11		)	—
Deferred	79			(1		)	63			5		31			16			12			—			13			7
Total	$	761		$	290		$	301		$	149	$	174		$	41		$	22		$	(4	)	$	3		$	17



	For the Year Ended December 31, 2015
																									Predecessor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Included in operations:
Federal
Current	$	407		$	546		$	(80	)	$	64		$	25		$	(54	)	$	(27	)	$	(2	)	$	12
Deferred	566			16			310			69			126			126			73			27			103
Investment tax credit amortization	(22		)	(19		)	(2		)	—			(1		)	—			—			—			(1		)
State
Current	(86		)	(90		)	7			(10		)	—			6			2			3			17
Deferred	208			49			45			20			39			24			1			5			32
Total	$	1,073		$	502		$	280		$	143		$	189		$	102		$	49		$	33		$	163

	For the Year Ended December 31, 2014
																									Predecessor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Included in operations:
Federal
Current	$	121		$	360		$	(171	)	$	28		$	24		$	(79	)	$	(45	)	$	(6	)	$	(153	)
Deferred	576			(35		)	395			87			90			150			98			31			261
Investment tax credit amortization	(20		)	(16		)	(2		)	—			(1		)	—			(1		)	(1		)	(1		)
State
Current	42			35			7			(2		)	—			(2		)	—			(1		)	(10		)
Deferred	(53		)	(137		)	39			1			27			24			13			7			41
Total	$	666		$	207		$	268		$	114		$	140		$	93		$	65		$	30		$	138

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



																	Successor		Predecessor
	For the Year Ended December 31, 2016																March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL ^(a)		ACE ^(a)		PHI ^(a)		PHI
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit ^(b)	3.3		3.3		5.6		1.3		5.0		15.7		52.7		6.2		5.8		11.9
Qualified nuclear decommissioning trust fund loss	3.4		7.8		—		—		—		—		—		—		—		—
Domestic production activities deduction	—		—		—		—		—		—		—		—		—		—
Health care reform legislation	—		—		—		—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)	(2.3	)	(0.3	)	(0.1	)	(0.1	)	(0.2	)	(3.7	)	0.8		1.4		(0.9	)
Plant basis differences	(4.8	)	—		(0.6	)	(9.6	)	(2.7	)	(22.8	)	(25.5	)	10.3		39.0		(13.5	)
Production tax credits and other credits	(3.6	)	(8.2	)	—		—		—		—		—		—		—		—
Noncontrolling interests	(0.2	)	(0.3	)	—		—		—		—		—		—		—		—
Statute of limitations expiration	(0.4	)	(1.7	)	—		—		—		—		—		—		—		—
Penalties	1.9		—		4.5		—		—		—		—		—		(0.7	)	—
Merger Expenses	5.5		1.1		—		—		—		23.5		112.9		(44.9	)	(89.0	)	11.1
Other ^(c)	(0.6	)	(1.5	)	0.1		(1.2	)	—		(1.8	)	(2.2	)	1.3		3.3		3.6
Effective income tax rate	38.3	%	33.2	%	44.3	%	25.4	%	37.2	%	49.4	%	169.2	%	8.7	%	(5.2	)%	47.2	%



	For the Year Ended December 31, 2015
																	Predecessor
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.7		1.0		4.9		1.0		5.3		6.7		1.7		5.7		6.6
Qualified nuclear decommissioning trust fund income	(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	)	(0.1	)	(0.4	)	(0.6	)	(0.2	)
Plant basis differences	(1.5	)	—		(0.1	)	(8.7	)	(0.7	)	(5.8	)	(2.3	)	(1.3	)	(4.3	)
Production tax credits and other credits	(1.9	)	(3.4	)	—		—		—		—		—		—		—
Noncontrolling interests	0.3		0.5		—		—		—		—		—		—		—
Statute of limitations expiration	(1.4	)	(2.4	)	—		—		—		—		—		—		—
Other ^(d)	—		—		0.2		0.2		—		(0.5	)	5.2		6.4		(3.2	)
Effective income tax rate	32.2	%	27.1	%	39.7	%	27.4	%	39.6	%	35.3	%	39.2	%	45.2	%	33.9	%

	For the Year Ended December 31, 2014
																	Predecessor
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.3		(1.9	)	4.5		(0.1	)	5.0		5.4		4.8		5.8		5.3
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	)	(0.1	)	(0.3	)	(0.6	)	(0.3	)
Plant basis differences	(1.9	)	—		(0.1	)	(10.4	)	0.2		(4.9	)	(2.4	)	(0.5	)	(4.5	)
Production tax credits and other credits	(2.4	)	(4.8	)	—		—		—		—		—		—		—
Noncontrolling interests	(1.8	)	(3.7	)	—		—		—		—		—		—		—
Statute of limitations expiration	(2.6	)	(5.3	)	—		—		—		—		—		—		—
Other	(0.2	)	(1.1	)	0.3		0.1		(0.2	)	(0.2	)	1.4		(0.2	)	0.8
Effective income tax rate	26.8	%	16.9	%	39.6	%	24.5	%	39.9	%	35.2	%	38.5	%	39.5	%	36.3	%

_____________________

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

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


(c)	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.

(d) Includes impacts of the PHI Global Settlement for Pepco, DPL, ACE, and PHI

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2016 and 2015 are presented below:



	As of December 31, 2016
																									Successor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Plant basis differences	$	(17,966	)	$	(4,192	)	$	(5,034	)	$	(3,095	)	$	(1,977	)	$	(1,678	)	$	(973	)	$	(869	)	$	(3,586	)
Accrual based contracts	434			(115		)	—			—			—			—			—			—			548
Derivatives and other financial instruments	(179		)	(162		)	(3		)	—			—			—			—			—			(1		)
Deferred pension and postretirement obligation	2,287			(316		)	(453		)	(18		)	(43		)	(122		)	(74		)	(21		)	(111		)
Nuclear decommissioning activities	(509		)	(509		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	325			44			(13		)	(1		)	(3		)	(7		)	(4		)	(2		)	293
Regulatory assets and liabilities	(3,319		)	—			(226		)	10			(240		)	(194		)	(75		)	(69		)	(1,205		)
Tax loss carryforward	189			61			29			—			22			27			39			14			77
Tax credit carryforward	446			493			—			—			—			—			—			—			—
Investment in CENG	(650		)	(650		)	—			—			—			—			—			—			—
Other, net	1,485			403			351			99			27			66			34			34			225
Deferred income tax liabilities (net)	$	(17,457	)	$	(4,943	)	$	(5,349	)	$	(3,005	)	$	(2,214	)	$	(1,908	)	$	(1,053	)	$	(913	)	$	(3,760	)
Unamortized investment tax credits	(658		)	(626		)	(15		)	(1		)	(5		)	(2		)	(3		)	(4		)	(9		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(18,115	)	$	(5,569	)	$	(5,364	)	$	(3,006	)	$	(2,219	)	$	(1,910	)	$	(1,056	)	$	(917	)	$	(3,769	)



	As of December 31, 2015
																									Predecessor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Plant basis differences	$	(13,393	)	$	(4,269	)	$	(4,424	)	$	(2,901	)	$	(1,821	)	$	(1,599	)	$	(915	)	$	(791	)	$	(3,342	)
Accrual based contracts	(136		)	(136		)	—			—			—			—			—			—			—
Derivatives and other financial instruments	(203		)	(181		)	(4		)	—			—			—			—			—			(1		)
Deferred pension and postretirement obligation	1,801			(371		)	(505		)	(9		)	(47		)	(95		)	(82		)	(20		)	(92		)
Nuclear decommissioning activities	(592		)	(592		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	133			48			(15		)	(1		)	(4		)	(8		)	(4		)	(3		)	(15		)
Regulatory assets and liabilities	(1,706		)	—			(219		)	16			(264		)	(202		)	(91		)	(93		)	(414		)
Tax loss carryforward	103			56			—			—			33			141			122			8			378
Tax credit carryforward	327			374			—			—			—			—			—			—			6
Investment in CENG	(595		)	(595		)	—			—			—			—			—			—			—
Other, net	1,112			425			270			105			27			42			29			18			103
Deferred income tax liabilities (net)	$	(13,149	)	$	(5,241	)	$	(4,897	)	$	(2,790	)	$	(2,076	)	$	(1,721	)	$	(941	)	$	(881	)	$	(3,377	)
Unamortized investment tax credits	(622		)	(598		)	(17		)	(2		)	(5		)	(2		)	(4		)	(4		)	(15		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(13,771	)	$	(5,839	)	$	(4,914	)	$	(2,792	)	$	(2,081	)	$	(1,723	)	$	(945	)	$	(885	)	$	(3,392	)

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2016.



																							Successor
	Exelon			Generation			ComEd		PECO		BGE			Pepco			DPL			ACE			PHI
Federal
Federal net operating loss	$	282	^(a)	$	11		$	82	$	—	$	—		$	44		$	38		$	18		$	121
Deferred taxes on Federal net operating loss	99			4			29		—		—			15			13			6			42
Federal general business credits carryforwards	511		^(b)	509			1		—		1			—			—			—			—
State
State net operating losses and credit carryforwards	3,501		^(c)	1,245		^(c)	—		—		425		^(d)	360		^(e)	639		^(f)	272		^(g)	1,522		^(h)
Deferred taxes on state tax attributes (net)	186			65			—		—		23			20			36			16			86
Valuation allowance on state tax attributes	20			9			—		—		1			—			—			—			10

_____________________


(a)	Exelon's federal net operating loss will begin expiring in 2032.


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


(c)	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2017.


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


(e)	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2028.


(f)	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.


(g)	ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2032.


(h)	PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.

Tabular reconciliation of unrecognized tax benefits

The following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2016, 2015 and 2014:



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



																					Predecessor
	Exelon			Generation			ComEd			PECO			BGE		Pepco		DPL		ACE		PHI
Unrecognized tax benefits at January 1, 2015	$	1,829		$	1,357		$	149		$	44		$	—	$	—	$	—	$	—	$	702
Increases based on tax positions related to 2015	108			—			—			—			106		—		—		—		—
Change to positions that only affect timing	(705		)	(659		)	(7		)	(44		)	—		—		—		—		(688		)
Increases based on tax positions prior to 2015	79			65			—			—			14		8		3		—		11
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		)	—			—			—		—		—		—		(3		)
Unrecognized tax benefits at December 31, 2015	$	1,078		$	534		$	142		$	—		$	120	$	8	$	3	$	—	$	22



																							Predecessor
	Exelon			Generation			ComEd			PECO		BGE		Pepco			DPL			ACE			PHI
Unrecognized tax benefits at January 1, 2014	$	2,175		$	1,415		$	324		$	44	$	—	$	45		$	3		$	3		$	743
Increases based on tax positions related to 2014	15			15			—			—		—		—			—			—			—
Change to positions that only affect timing	(255		)	33			(175		)	—		—		(45		)	(3		)	(3		)	(41		)
Increases based on tax positions prior to 2014	18			18			—			—		—		—			—			—			—
Decreases based on tax positions prior to 2014	(1		)	(2		)	—			—		—		—			—			—			—
Decreases 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	$	—	$	—		$	—		$	—		$	702

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

Exelon, Generation, and ComEd had $415 million, $20 million, and $142 million of unrecognized tax benefits at December 31, 2015 for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits

Exelon, Generation, ComEd, PECO, and PHI had $1,122 million, $680 million, $149 million, $43 million, and $686 million of unrecognized tax benefits at December 31, 2014 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.

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

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

Exelon, Generation, and PHI had $538 million, $509 million, and $11 million, respectively, of unrecognized tax benefits at December 31, 2015 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, and DPL had $120 million, $11 million, $8 million, and $3 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, Generation, and PHI had $701 million, $672 million, and $15 million, respectively, of unrecognized tax benefits at December 31, 2014 that, if recognized, would decrease the effective tax rate.

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

Settlement of Income Tax Audits and Litigation

As of December 31, 2016, Exelon, Generation, PHI, Pepco, ACE and DPL have approximately $146 million, $19 million, $59 million, $21 million, $22 million, and $16 million, respectively, of unrecognized federal and state tax benefits that will decrease in the first quarter of 2017 due to the receipt in January of favorable IRS guidance as to whether certain business expenses should be capitalized or deducted. The recognition of these unrecognized tax benefits will decrease the effective tax rate in the first quarter of 2017.

As of December 31, 2016, Exelon, Generation, BGE, PHI, Pepco, and DPL have approximately $244 million, $44 million, $120 million, $80 million, $59 million, and $21 million, respectively, 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 $44 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to BGE, Pepco, and DPL if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.

Total amounts of interest and penalties recognized

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



Net interest receivable (payable) as of	Exelon			Generation		ComEd			PECO		BGE			Pepco		DPL		ACE
December 31, 2016	$	(507	)	$	46	$	(384	)	$	8	$	(1	)	$	1	$	—	$	1
December 31, 2015	(288		)	80		(210		)	3		(1		)	20		3		24



Net penalties receivable (payable) as of	Exelon			Generation		ComEd			PECO		BGE		Pepco		DPL		ACE
December 31, 2016	$	(106	)	$	—	$	(86	)	$	—	$	—	$	—	$	—	$	—
December 31, 2015	—			—		—			—		—		—		—		—



	Successor		Predecessor
PHI	December 31, 2016		December 31, 2015
Net interest receivable (payable)	$	2	$	(34	)
Net penalties receivable (payable)	—		—

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



Net interest expense (income) for the years ended	Exelon			Generation			ComEd		PECO		BGE		Pepco			DPL		ACE
December 31, 2016	$	165		$	(13	)	$	117	$	—	$	—	$	6		$	—	$	(1	)
December 31, 2015	(13		)	(31		)	7		—		—		(4		)	—		—
December 31, 2014	(36		)	(50		)	6		—		1		(1		)	—		(1		)



Net penalty expense (income) for the years ended	Exelon		Generation		ComEd			PECO		BGE		Pepco		DPL		ACE
December 31, 2016	$	106	$	—	$	86	—	$	—	$	—	$	—	$	—	$	—
December 31, 2015	—		—		—			—		—		—		—		—
December 31, 2014	—		—		—			—		—		—		—		—



	Successor			Predecessor
PHI	March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016		December 31, 2015			December 31, 2014
Net interest expense (income)	$	(2	)	$	—	$	(34	)	$	—
Net penalty expense (income)	—			—		—			—

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, 2001-2015
PHI Holdings and subsidiaries consolidated Federal income tax returns	2013-2015
Exelon and subsidiaries Illinois unitary income tax returns	2010-2015
Constellation combined New York corporate income tax returns	2010-March 2012
Exelon combined New York corporate income tax returns	2011-2015
Various separate company (excluding PECO) Pennsylvania corporate net income tax returns	2011-2015
PECO Pennsylvania separate company returns	2010-2015
DPL Delaware separate company returns	Same as Federal
ACE New Jersey separate company returns	2012-2015
Various separate company Maryland corporate net income tax returns	Same as Federal
Washington D.C. corporate income tax returns	2013-2015

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 was unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was 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 asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.

In accordance with applicable accounting standards, Exelon was required to assess whether it was more-likely-than-not that to prevail in litigation. In light of the outcome of another case involving a listed transaction and Exelon’s determination that settlement was unlikely, Exelon concluded that subsequent to December 31, 2012, it was no longer more-likely-than-not that its position would be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represented 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 has agreed to hold ComEd harmless from any unfavorable impacts on ComEd’s equity of the after-tax interest or penalty amounts. As a result, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Based on applicable case law and the facts of the transaction, Exelon did not believe it was likely a penalty would be assessed. Accordingly, no charge was recorded for the penalty asserted nor for after-tax interest that could be due on the asserted penalty.

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.

On September 19, 2016, the Tax Court rejected Exelon’s position in the case and ruled that Exelon was not entitled to defer gain on the transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest due on the asserted penalty. In the second quarter of 2017, Exelon expects to timely appeal this decision to the U.S. Court of Appeals for the Seventh Circuit.

While it has strong arguments on appeal with respect to both the merits and the penalty, Exelon has determined that, pursuant to accounting standards, it is no longer more-likely-than-not to avoid the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net, respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any unfavorable impact on its equity, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, a $150 million receivable and non-cash equity contributions from Exelon.

In order to appeal the decision, Exelon is required to pay the tax, penalty and interest at the time Exelon files its appeal (expected in the second quarter of 2017). While the final calculation of tax, penalty and interest has not yet been finalized by the IRS, Exelon estimates that a payment of approximately $1.4 billion related to the like-kind exchange will be due, including $300 million from ComEd, in the second quarter of 2017. While Exelon will receive a tax benefit of $400 million associated with the deduction for the interest, Exelon expects to have a net operating loss carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total estimated net cash outflow for the like-kind exchange is $1 billion, of which approximately $300 million is attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts of after-tax interest or penalty amounts on ComEd’s equity. Upon a final appellate decision, which could take up to several years, Exelon expects to receive $80 million related to final interest computations.

Of the above amounts payable, Exelon deposited with the IRS approximately $1.25 billion in October of 2016. The remaining amount will be paid in the second quarter of 2017 at the time Exelon files its appeal of the Tax Court decision. Exelon funded the $1.25 billion deposit with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and interest are included on Exelon’s balance sheet as current obligations.

As of December 31, 2016, ComEd has a total receivable from Exelon pursuant to the hold harmless agreement of $345 million, which is included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet. Under the agreement, Exelon will settle this receivable with ComEd no later than the time that the payments related to the like-kind exchange are due to the IRS, currently anticipated in the second quarter of 2017. Exelon will not seek recovery from ComEd customers for any interest or penalty amounts associated with the like-kind exchange tax position.

As previously disclosed, 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. On March 31, 2016, Exelon entered into an agreement to terminate its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.

PHI Global Tax Settlement

On November 18, 2015, PHI entered into a settlement with the IRS and the DOJ (the Global Tax Settlement) to primarily provide for the resolution of the uncertain tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of the United States structured as sale-in, lease-out, or SILO, transactions.

As a result of the Global Tax Settlement in the fourth quarter of 2015, PHI re-measured uncertain tax positions resulting in the recognition of a tax benefit of $35 million, including $26 million related to continuing operations and $9 million related to discontinued operations. PHI also recorded an interest benefit, net of tax, of $21 million. Pepco recorded a tax benefit of $6 million and interest benefit, net of tax, of $3 million. ACE and DPL recorded a tax expense of $3 million and $3 million, respectively.

Long-Term State Tax Apportionment (Exelon, Generation and PHI)

Exelon, Generation and PHI periodically review events that may significantly impact how income is apportioned among the states and, therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon, Generation and PHI to update their long-term state tax apportionment include significant changes in tax law and/or significant operational changes, such as the merger with PHI. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they have state income tax obligations, which include Delaware, Illinois, Maryland, New Jersey, Pennsylvania, and Washington D.C., as well as other states. The total effect of revising the long-term state tax apportionment resulted in the recording of deferred state tax benefit in the amount of $1 million and $6 million, net of tax, for Exelon and Generation, respectively. Further, Exelon and PHI recorded deferred state tax liabilities of $59 million and $8 million, net of tax, respectively, as part of purchase accounting during the first quarter of 2016. The long-term state tax apportionment was revised in the fourth quarter of 2016 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 $8 million and $14 million, net of tax.

Allocation of Tax Benefits (All Registrants)

Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2016, Generation, PECO, and BGE recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $94 million, $18 million, and $8 million respectively. ComEd did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss. PHI, Pepco, DPL, and ACE did not record an allocation of Federal tax benefits from Exelon as they were not a part of Exelon's 2015 consolidated tax return.

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.

Asset Retirement Obligations (All Registrants)

12 Months Ended

Dec. 31, 2016

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations (All Registrants)

Nuclear Decommissioning Asset Retirement Obligations

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2015 to December 31, 2016:



	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2015	$	6,961
Accretion expense	387
Net increase for changes in and timing of estimated future cash flows	901
Costs incurred related to decommissioning plants	(3		)
Nuclear decommissioning ARO at December 31, 2015^(a)	8,246
Accretion expense	436
Net increase for changes in and timing of estimated future cash flows	61
Costs incurred related to decommissioning plants	(9		)
Nuclear decommissioning ARO at December 31, 2016 ^(a)	$	8,734

_________________________


(a)	Includes $10 million and $7 million as the current portion of the ARO at December 31, 2016 and 2015, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During 2016, Generation’s total nuclear ARO increased by approximately $488 million, primarily reflecting year-to-date accretion of the ARO liability of approximately $436 million due to the passage of time and impacts of ARO updates completed during 2016 to reflect changes in amounts and timing of estimated decommissioning cash flows.

The $61 million increase in the ARO during 2016 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments throughout the year, some with offsetting impacts. These adjustments include increases of $288 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2025 to 2030 as well as increases resulting from updates to the cost studies of Oyster Creek, Zion, Calvert Cliffs, R.E. Ginna and Nine Mile Point. These increases were partially offset by a decrease of $165 million resulting from changes to the decommissioning scenarios and their probabilities as well as reductions in estimated cost escalation rates, primarily for labor, energy and waste burial costs. Most of the increase to the ARO resulting from the June 2, 2016, announcement to early retire Clinton and Quad Cities was reversed pursuant to the December 7, 2016, enactment of the Illinois FEJA. See Note 9 - Early Nuclear Plant Retirements for additional information.

The financial statement impact related to changes in the ARO, on an individual unit basis, due to the changes in, and timing of, estimated cash flows primarily resulted in a corresponding change in the unit’s ARC within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a unit that does not have any remaining ARC, the corresponding change is recorded as a credit to income in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Approximately $89 million of the 2016 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 2015, Generation’s ARO increased by approximately $1.3 billion. The increase 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 was 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 included 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 - Early Nuclear 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.

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, 2016, and 2015, Exelon and Generation had NDT fund investments totaling $11,061 million and $10,342 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 2016, 2015 and 2014:



	Exelon and Generation
	For the Years Ended December 31,
	2016		2015			2014
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	216	$	(282	)	$	180
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units ^(b)(c)	194		(197		)	134

_______________________


(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 $(1) million, $7 million and $29 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2016, 2015 and 2014, 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, 2016, 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 27 — 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 $111 million, which is included within the nuclear decommissioning ARO at December 31, 2016. 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, 2016 and 2015:



	Exelon and Generation
	2016		2015
Carrying value of Zion Station pledged assets	$	113	$	206
Payable to Zion Solutions ^(a)	104		189
Current portion of payable to Zion Solutions ^(b)	90		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs ^(c)	878		786

___________________


(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. In accordance with the terms of the ASA, the letter of credit was reduced to $173 million in November 2016 due to the completion of key decommissioning milestones. EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded 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, 2016 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, 2016 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under four possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.3% to 5.9% (as compared to a historical 5-year annual average pre-tax return of approximately 8%).

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.

Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status of decommissioning funding assurance for all units 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. 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 approved license renewals for these units, and showed adequate decommissioning funding assurance for each of the three units.

On March 31, 2016, Generation submitted its NRC required annual decommissioning funding status report as of December 31, 2015 for reactors that have been shut down or are within five years of shut down (Dresden Unit 1, Oyster Creek, Zion and Peach Bottom Unit 1), except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). The status report demonstrated adequate decommissioning funding assurance for all these units except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. As discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers will be adjusted in the next filing to the PAPUC with new rates effective January 1, 2018.

Generation will file its next decommissioning funding status report with the NRC by March 31, 2017. This report will reflect the status of decommissioning funding assurance as of December 31, 2016.

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

Non-Nuclear Asset Retirement Obligations (All Registrants)

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

The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2015 to December 31, 2016:



																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI^(f)		Pepco		DPL		ACE
Non-nuclear AROs at January 1, 2015	$	346		$	194		$	104		$	30		$	18		$	—	$	—	$	—	$	—
Net (decrease) increase 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^(d)	(2		)	(2		)	—			—			—			—		—		—		—
Payments	(5		)	(3		)	(2		)	—			—			—		—		—		—
Non-nuclear AROs at December 31, 2015^(e)	355			197			113			27			18			—		—		—		—
Merger with PHI ^(g)	8			1			—			—			—			—		—		—		—
Net increase (decrease) due to changes in, and timing of, estimated future cash flows^(a)	34			8			4			1			7			14		2		9		3
Development projects^(b)	11			11			—			—			—			—		—		—		—
Accretion expense^(c)	18			10			7			1			—			—		—		—		—
Sale of generating assets^(d)	(22		)	(22		)	—			—			—			—		—		—		—
Payments	(11		)	(6		)	(3		)	(1		)	(1		)	—		—		—		—
Non-nuclear AROs at December 31, 2016^(e)	$	393		$	199		$	121		$	28		$	24		$	14	$	2	$	9	$	3



	Predecessor
	PHI^(f)
Non-nuclear AROs at January 1, 2015	$	7
Accretion expense^(c)	1
Non-nuclear AROs at December 31, 2015	$	8

Non-nuclear AROs at March 23, 2016	$	8

________________________

(a)

During the year ended December 31, 2016, Generation recorded an increase of $1 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, 2016. 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.


(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)	Reflects a reduction to the ARO resulting primarily from the sales of the New Boston generating site and Upstream business in 2016 and Schuylkill generating station in 2015. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.


(e)	Excludes $1 million, $2 million and $3 million as the current portion of the ARO at December 31, 2016 for Generation, ComEd and BGE, respectively. Excludes $5 million, $2 million and $1 million as the current portion of the ARO at December 31, 2015 for Generation, ComEd and BGE, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.


(f)	For PHI, the successor period includes activity for the period of March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year ended December 31, 2015 and the period January 1, 2016 through March 23, 2016.


(g)	Following the completion of the PHI merger on March 23, 2016, PHI's AROs related to its unregulated business interests were transferred to Exelon and Generation.

Retirement Benefits (All Registrants)

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Retirement Benefits (All Registrants)

(All Registrants)

As of December 31, 2016, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all employees.

Effective March 23, 2016, Exelon became the sponsor of all of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. As a result, PHI's benefit plan net obligation and related regulatory assets were transferred to Exelon and remeasured at the merger date using current assumptions, including discount rates.

The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2016.

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program^(a)

Exelon Corporation Cash Balance Pension Plan^(a)

Exelon Corporation Pension Plan for Bargaining

Unit Employees^(a)

Exelon New England Union Employees Pension

Plan^(a)

Exelon Employee Pension Plan for Clinton, TMI

and Oyster Creek^(a)

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

Pension Plan of Constellation Energy Nuclear

Group, LLC^(c)

Nine Mile Point Pension Plan^(c)

Constellation Mystic Power, LLC Union Employees

Pension Plan Including Plan A and Plan B^(b)

Pepco Holdings LLC Retirement Plan^(d)

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit

Plan and 2000 Excess Benefit Plan^(a)

Exelon Corporation Supplemental Management

Retirement Plan^(a)

Constellation Energy Group, Inc. Senior Executive

Supplemental Plan^(b)

Constellation Energy Group, Inc. Supplemental

Pension Plan^(b)

Constellation Energy Group, Inc. Benefits

Restoration Plan^(b)

Constellation Energy Nuclear Plan, LLC Executive

Retirement Plan^(c)

Constellation Energy Nuclear Plan, LLC Benefits

Restoration Plan^(c)

Baltimore Gas & Electric Company Executive

Benefit Plan^(b)

Baltimore Gas & Electric Company Manager

Benefit Plan^(b)

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

Conectiv Supplemental Executive Retirement Plan^(d)

Pepco Holdings LLC Combined Executive Retirement Plan ^(d)

Atlantic City Electric Director Retirement Plan ^(d)

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Other Postretirement Benefit Plans



							Predecessor
			Exelon				PHI
			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2016		2015		2015
Equity securities	43	%	47	%	43	%	63	%
Fixed income securities	28	%	29		27		34
Alternative investments^(a)	29	%	24		30		3
Total			100	%	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, 2016. 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, 2016, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.

Fair Value Measurements

The following tables present pension and other postretirement benefit plan assets measured and recorded at fair value on the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2016 and 2015:

Exelon



At December 31, 2016(a)(d)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	325	$	—	$	—	$	—	$	325
Equities^(b)	3,144		—		2		2,535		5,681
Fixed income:
U.S. Treasury and agencies	1,008		192		—		—		1,200
State and municipal debt	—		64		—		—		64
Corporate debt	—		3,641		206		—		3,847
Other^(b)	—		340		—		748		1,088
Fixed income subtotal	1,008		4,237		206		748		6,199
Private equity	—		—		—		991		991
Hedge funds	—		—		—		1,962		1,962
Real estate	—		—		—		828		828
Private credit	—		—		—		833		833
Pension plan assets subtotal	$	4,477	$	4,237	$	208	$	7,897	$	16,819



At December 31, 2016(a)(d)	Level 1		Level 2		Level 3			Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	24	$	—	$	—		$	—	$	24
Equities	547		2		—			644		1,193
Fixed income:
U.S. Treasury and agencies	9		59		—			—		68
State and municipal debt	—		134		—			—		134
Corporate debt	—		43		—			—		43
Other	256		60		—			131		447
Fixed income subtotal	265		296		—		—	131		692
Hedge funds	—		—		—			445		445
Real estate	—		—		—			117		117
Private credit	—		—		—			107		107
Other postretirement benefit plan assets subtotal	$	836	$	298	$	—		$	1,444	$	2,578
Total pension and other postretirement benefit plan assets^(c)	$	5,313	$	4,535	$	208		$	9,341	$	19,397



At December 31, 2015(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	210	$	—	$	—	$	—	$	210
Equities^(b)	3,571		—		2		1,462		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)	—		146		—		452		598
Fixed income subtotal	1,001		3,187		165		452		4,805
Private equity	—		—		—		924		924
Hedge funds	—		—		—		1,924		1,924
Real estate	—		—		—		725		725
Private credit	—		—		—		699		699
Pension plan assets subtotal	$	4,782	$	3,187	$	167	$	6,186	$	14,322



At December 31, 2015(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	15	$	—	$	—	$	—	$	15
Equities	510		2		—		480		992
Fixed income:
U.S. Treasury and agencies	11		53		—		—		64
State and municipal debt	—		131		—		—		131
Corporate debt	—		44		—		—		44
Other	155		59		—		146		360
Fixed income subtotal	166		287		—		146		599
Hedge funds	—		—		—		451		451
Real estate	—		—		—		131		131
Private credit	—		—		—		103		103
Other postretirement benefit plan assets subtotal	$	691	$	289	$	—	$	1,311	$	2,291
Total pension and other postretirement benefit plan assets^(c)	$	5,473	$	3,476	$	167	$	7,497	$	16,613



	Predecessor
	December 31, 2015(a)
PHI	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	50	$	—	$	—	$	—	$	50
Equities	335		—		—		224		559
Fixed income:
U.S. Treasury and agencies	114		15		—		—		129
State and municipal debt	—		18		—		—		18
Corporate debt securities	—		625		—		—		625
Other	—		40		—		504		544
Fixed income subtotal	114		698		—		504		1,316
Private equity	—		—		—		38		38
Real estate	—		—		—		46		46
Pension plan assets subtotal	$	499	$	698	$	—	$	812	$	2,009



	Predecessor
	December 31, 2015(a)
PHI	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	8	$	—	$	—	$	—	$	8
Equities	197		—		—		22		219
Fixed income - other	121		—		—		—		121
Other postretirement benefit plan assets subtotal	$	326	$	—	$	—	$	22	$	348
Total pension and other postretirement benefit plan assets^(e)	$	825	$	698	$	—	$	834	$	2,357

____________________


(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 $1 million and $5 million, which have a total notional amount of $2,918 million and $1,774 million at December 31, 2016 and 2015, 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 liabilities of $28 million and net assets of $27 million at December 31, 2016 and 2015, 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.


(d)	Effective March 23, 2016, Exelon became sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets.


(e)	Excludes net assets of $9 million at December 31, 2015, 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 purchased.

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, 2016 and 2015:

Exelon



	Fixed income			Equities		Total
Pension Assets
Balance as of January 1, 2016	$	165		$	2	$	167
Actual return on plan assets:
Relating to assets still held at the reporting date	(2		)	—		(2		)
Purchases, sales and settlements:
Purchases	69			—		69
Sales	(14		)	—		(14		)
Settlements^(a)	(12		)	—		(12		)
Balance as of December 31, 2016	$	206		$	2	$	208



	Fixed income			Equities		Total
Pension Assets
Balance as of January 1, 2015	$	120		$	2	$	122
Actual return on plan assets:
Relating to assets still held at the reporting date	(8		)	—		(8		)
Purchases, sales and settlements:
Purchases	61			—		61
Settlements^(a)	(8		)	—		(8		)
Balance as of December 31, 2015	$	165		$	2	$	167

________________________


(a)	Represents cash settlements only.

There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2016 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 and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice and without further restrictions.

Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows and market based comparable data. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.

Real estate. Real estate funds are funds with a direct investment in pools of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. These valuation inputs are not highly observable. The fair value of real estate investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Private credit. Private credit investments primarily consist of limited partnerships that invest in private debt strategies. These investments are generally less liquid assets with an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator and include unobservable inputs such as cost, operating results, and discounted cash flows. The fair value of private credit investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Defined Contribution Savings Plan (All Registrants)

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and 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, 2016, 2015 and 2014:



For the Year Ended December 31,	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		BSC^(b)		Pepco^(c)		DPL^(c)		ACE		PHISCO^(c)
2016	$	164	$	79	$	34	$	10	$	12	$	19	$	3	$	2	$	2	$	6
2015	148		80		32		11		14		11		3		2		2		6
2014	103		51		26		8		8		10		3		2		1		6



	Successor		Predecessor
PHI	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015		For the Year Ended December 31, 2014
Saving Plan Matching Contributions	$	10	$	3	$	14	$	13

_________________________


(a)	Includes $13 million, $9 million and $5 million related to CENG for the years ended December 31, 2016, 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.


(c)	Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions at December 31, 2016.

Severance (All Registrants)

12 Months Ended

Dec. 31, 2016

Restructuring and Related Activities [Abstract]

Severance (All Registrants)

(All Registrants)

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

Ongoing Severance Plans

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

For the years ended December 31, 2016 and 2015, the Registrants recorded the following severance costs associated with ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:




	Exelon		Generation^(a)		ComEd^(a)		PECO^(a)		BGE^(a)
Year ended December 31,
2016	$	19	$	13	$	3	$	1	$	1
2015	18		15		2		—		1



	Successor		Predecessor
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015
PHI^(a)
Severance Benefits	$	1	$	—	$	—

_______


(a)	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.

Early Plant Retirement-Related Severance

On December 7, 2016 the Future Energy Jobs Bill was signed into law by the Governor of Illinois and included a ZES. With the passage of the IL ZES, Generation reversed its decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants and expects the plants to continue operation for at least another 10 years. As a result, Exelon and Generation reversed the associated severance benefit costs of $44 million in December 2016 which were previously recorded for expected employee severances.

Cost Management Program-Related Severance

In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of approximately 500 positions. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s business and industry, necessitating continued focus on cost management through enhanced efficiency and productivity. Exelon expects that approximately 250 corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated. The final amount of the severance charges related to the cost management program will ultimately depend on the specific employees severed.

For the year ended December 31, 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:



	Exelon		Generation		ComEd		PECO		BGE
Severance benefits^(a)	$	23	$	18	$	3	$	1	$	1

_______


(a)	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2016.

Severance Costs Related to the PHI Merger

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. Cash payments under the plan began in May 2016 and will continue through 2020.

For the year ended December 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco^(b)		DPL^(c)		ACE
Severance benefits^(a)	$	57	$	9	$	2	$	1	$	1	$	44	$	21	$	13	$	10

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the year ended December 31, 2016.


(b)	Pepco established a regulatory asset of $11 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.


(c)	DPL established a regulatory asset of $4 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.

Severance Liability

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



															Successor
Severance Liability	Exelon			Generation			ComEd			PECO		BGE			PHI^(b)			Pepco			DPL			ACE
Balance at December 31, 2014	$	50		$	34		$	2		$	—	$	2		$	—		$	1		$	—		$	—
Severance charges	16			10			2			—		—			—			—			—			—
Payments	(31		)	(21		)	(1		)	—		(1		)	—			(1		)	—			—
Balance at December 31, 2015	$	35		$	23		$	3		$	—	$	1		$	—		$	—		$	—		$	—
Severance charges^(a)	99			22			2			—		—			56			1			1			—
Payments	(46		)	(9		)	(2		)	—		(1		)	(27		)	(1		)	(1		)	—
Balance at December 31, 2016	$	88		$	36		$	3		$	—	$	—		$	29		$	—		$	—		$	—



	Predecessor
Severance Liability	PHI^(b)
Balance at December 31, 2014	$	3
Severance charges	—
Payments	(3		)
Balance at December 31, 2015	$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.


(b)	For PHI, the successor period includes activity for the period from March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year ended December 31, 2015 and the period January 1, 2016 through March 23, 2016. There was no activity in the 2016 PHI predecessor period.

Shareholder Equity (All Registrants)

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

Stockholders' Equity Note Disclosure [Text Block]

20. Shareholders' Equity (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

The following table presents common stock authorized and outstanding as of December 31, 2016 and 2015:



				December 31,
				2016	2015
	Par Value		Shares Authorized	Shares Outstanding
Common Stock
Exelon	no par value		2,000,000,000	924,035,059	919,924,742
ComEd	$	12.50	250,000,000	127,017,157	127,016,973
PECO	no par value		500,000,000	170,478,507	170,478,507
BGE	no par value		175,000,000	1,000	1,000
PHI Predecessor	$	0.01	400,000,000	n/a	254,289,261
Pepco	$	0.01	200,000,000	100	100
DPL	$	2.25	1,000	1,000	1,000
ACE	$	3.00	25,000,000	8,546,017	8,546,017

ComEd had 72,859 and 73,434 warrants outstanding to purchase ComEd common stock at December 31, 2016 and 2015, 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, 2016 and 2015, 24,286 and 24,478 shares of common stock, respectively, were reserved for the conversion of warrants.

Equity Securities Offering

In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreement by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. The net proceeds were used to fund the merger with PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of diluted EPS using the treasury stock method.

Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. 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, 2016. During 2016, 2015 and 2014, Exelon had no common stock repurchases.

Preferred and Preference Securities of Subsidiaries

At December 31, 2016 and 2015, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.

At December 31, 2016 and 2015, 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.

On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million, plus accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends. At December 31, 2016 and 2015, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and the outstanding amounts 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)		2016	2015	2016		2015
	Redemption Price ^(a)		Shares Outstanding		Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.00	—	400,000	$	—	$	40
6.97%, 1993 Series	100.00		—	500,000	—		50
6.70%, 1993 Series	100.00		—	400,000	—		40
6.99%, 1995 Series	100.00		—	600,000	—		60
Total preference stock			—	1,900,000	$	—	$	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.

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Stock-Based Compensation Plans

Stock-Based Compensation Plans (All Registrants)

12 Months Ended

Dec. 31, 2016

Common Stock [Abstract]

Stock-Based Compensation Plans (All Registrants)

Stock-Based Compensation Plans

Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2016, there were approximately 14 million shares authorized for issuance under the LTIP. For the years ended December 31, 2016, 2015 and 2014, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.

Beginning in 2014, ComEd, PECO and BGE grant cash awards. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable accounting guidance.

In connection with the acquisition of PHI in March 2016, PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.

The following tables present the stock-based compensation expense included in Exelon's and PHI’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2016, 2015 and 2014, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:



Exelon	Year Ended December 31,
Components of Stock-Based Compensation Expense	2016(a)			2015			2014
Performance share awards	$	93		$	41		$	59
Restricted stock units	75			71			61
Stock options	—			1			2
Other stock-based awards	7			6			5
Total stock-based compensation expense included in operating and maintenance expense	175			119			127
Income tax benefit	(68		)	(46		)	(47		)
Total after-tax stock-based compensation expense	$	107		$	73		$	80

____________________


(a)	2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

PHI



	Predecessor
	January 1 to March 23,			Years Ended December 31,
Components of Stock-Based Compensation Expense	2016			2015			2014
Time-based restricted stock units	$	2		$	7		$	5
Performance-based restricted stock units	1			5			8
Time-based restricted stock awards	—			1			5
Total stock-based compensation expense included in operating and maintenance expense	3			13			18
Income tax benefit	(1		)	(5		)	(7		)
Total after-tax stock-based compensation expense	$	2		$	8		$	11

The following tables present the Registrants' stock-based compensation expense (pre-tax) for the years ended December 31, 2016, 2015 and 2014, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:



	Years Ended December 31,
Subsidiaries	2016		2015		2014
Exelon	$	175	$	119	$	127
Generation	78		64		52
ComEd	8		6		7
PECO	3		3		3
BGE	1		3		5
BSC ^(a)	81		43		60
PHI ^(a)(b)	7		13		18



	Successor		Predecessor
	March 24 to December 31,		January 1 to March 23,		Years Ended December 31,
	2016		2016		2015		2014
PHI	$	4	$	3	$	13	$	18

____________________


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


(b)	Pepco's, DPL's and ACE's stock-based compensation expense for the year ended December 31, 2016 and for the period January 1, 2016 through March 23, 2016 was not material. PHI's stock-based compensation expense for the year ended December 31, 2016 includes $3 million of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.

There were no significant stock-based compensation costs capitalized during the years ended December 31, 2016, 2015 and 2014 for Exelon or PHI, or for PHI during the predecessor period January 1, 2016 to March 23, 2016.

Exelon and PHI receive 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 and PHI recognize the tax benefit related to compensation costs. The following tables present information regarding Exelon’s and PHI's tax benefits for the years ended December 31, 2016, 2015 and 2014 and PHI's predecessor period January 1, 2016 to March 23, 2016:



Exelon	Years Ended December 31,
	2016		2015		2014
Realized tax benefit when exercised/distributed:
Restricted stock units	$	27	$	30	$	17
Performance share awards	18		18		11

PHI



	Predecessor
	January 1 to March 23,		Years Ended December 31,
	2016		2015		2014
Realized tax benefit when exercised/distributed:
Time-based restricted stock units	$	—	$	2	$	3
Performance-based restricted stock units	—		5		4
Time-based restricted stock awards	—		—		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 2014, 2015 or 2016. For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years. As of December 31, 2016 all stock options are fully vested. 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 following table presents information with respect to stock option activity for the year ended December 31, 2016:



	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2015	15,572,757		$	46.68
Options exercised	(840,672	)	22.12
Options forfeited	—		—
Options expired	(2,200,494	)	58.60
Balance of shares outstanding at December 31, 2016	12,531,591		$	46.23	3.50	$	13
Exercisable at December 31, 2016 (a)	12,531,591		$	46.23	3.50	$	13

____________________


(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, 2016, 2015 and 2014:



	Years Ended December 31,
	2016		2015		2014
Intrinsic value^(a)	$	11	$	—	$	3
Cash received for exercise price	19		—		7

______________________


(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, 2016:



	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2015 (a)	82,250		$	39.81
Vested	(82,250	)	39.81
Nonvested at December 31, 2016 (a)	—		$	—

_____________________


(a)	Excludes 279,000 of stock options issued to retirement-eligible employees as of December 31, 2015 as they are fully vested. As of December 31, 2016, all stock options are fully vested.

At December 31, 2016, there was no unrecognized compensation costs related to nonvested stock options.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.

The following tables summarize Exelon’s and PHI's nonvested restricted stock unit activity for the year ended December 31, 2016 and PHI's for the predecessor period January 1, 2016 to March 23, 2016:

Exelon



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015 (a)	3,563,254		$	32.92
Granted	3,042,184		28.14
Vested	(1,797,536	)	32.44
Forfeited	(85,940	)	30.08
Undistributed vested awards^(b)	(897,546	)	28.35
Nonvested at December 31, 2016 (a)(c)	3,824,416		$	30.49

PHI



	Time-based Shares	Weighted Average Grant Date Fair Value (per share)		Performance-based Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015	628,514	$	24.71	$	408,638		$	18.56
Granted	152,928	26.01		305,856			25.41
Vested	—	—		(4,950		)	26.08
Forfeited	—	—		(1,238		)	26.08
Nonvested at March 23, 2016	781,442	$	24.96	$	708,306		$	21.45

______________________


(a)	Excludes 1,319,372 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.


(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2016.


(c)	2016 amounts include activity related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

For Exelon, the weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2016, 2015 and 2014 was $28.14, $36.55 and $28.71, respectively. At December 31, 2016 and 2015, Exelon had obligations related to outstanding restricted stock units not yet settled of $101 million and $97 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2016, 2015 and 2014, Exelon settled restricted stock units with fair value totaling $68 million, $75 million and $43 million, respectively. At December 31, 2016, $58 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.

For PHI, the weighted average grant date fair value (per share) of time-based restricted stock units granted for the years ended December 31, 2015 and 2014 was $27.40 and $19.77, respectively, and for performance-based restricted stock units was $26.08 and $18.53 for the same periods, respectively. At December 31, 2015 PHI had obligations related to outstanding time-based and performance-based restricted stock units not yet settled of $1 million each, which are included in common stock in PHI’s Consolidated Balance Sheet. For the years ended December 31, 2015 and 2014, PHI settled time-based restricted stock units with fair value totaling $6 million and $8 million, respectively, and settled performance-based restricted stock units with fair value totaling $15 million and $9 million, for the same periods, respectively. There were no settled restricted stock units for the predecessor period January 1, 2016 to March 23, 2016.

Performance Share Awards

Performance share awards are granted under the LTIP. The 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 vice presidents and higher officers that may be settled 100% in common stock, 100% in cash or 50%in common stock and 50% in cash if certain ownership requirements are satisfied.

The common stock portion of the performance share 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 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 tables summarize Exelon’s and PHI's nonvested performance share awards activity for the year ended December 31, 2016 and PHI's for the predecessor period January 1, 2016 to March 23, 2016:

Exelon



	Shares (c)		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015 (a)	2,557,159		$	31.88
Granted	2,319,407		28.85
Change in performance	627,303		30.04
Vested	(949,315	)	31.31
Forfeited	(70,876	)	30.90
Undistributed vested awards ^(b)	(1,367,417	)	28.33
Nonvested at December 31, 2016 (a)	3,116,261		$	30.77

PHI



	Time-based Shares	Weighted Average Grant Date Fair Value (per share)		Performance-based Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015	54,165	$	26.80	24,717		$	26.10
Vested	—	—		(24,717	)	26.10
Nonvested at March 23, 2016	54,165	$	26.80	—		$	—

________________


(a)	Excludes 2,443,409 and 1,817,883 of performance share awards issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.


(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2016.


(c)	2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.

For Exelon, the weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2016, 2015 and 2014 was $28.85, $35.88, and $28.75, respectively. During the years ended December 31, 2016, 2015 and 2014, Exelon settled performance shares with a fair value totaling $45 million, $46 million and $27 million, respectively, of which $28 million, $29 million and $13 million was paid in cash, respectively. As of December 31, 2016, $51 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 2 years.

For PHI, the weighted average grant date fair value (per share) of time-based restricted stock awards granted for the year ended December 31, 2014 was $26.80 and for performance-based restricted stock awards was $26.10 and $27.01 for the years ended December 31, 2015 and 2014, respectively. There were no time-based restricted stock awards granted for the year ended December 31, 2015. At December 31, 2015 PHI had no obligations related to vested time-based and performance-based restricted stock awards not yet settled. For the year ended December 31, 2014 PHI settled time-based shares with a fair value totaling $3 million. There were no time-based share settlements for the year-ended December 31, 2015 or the predecessor period January 1, 2016 to March 23, 2016 or performance-based share settlements for the predecessor period January 1, 2016 to March 23, 2016 and the years ended December 31, 2015 and 2014.

The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:



	December 31,
	2016		2015^(c)
Current liabilities^(a)	$	49	$	28
Deferred credits and other liabilities ^(b)	52		32
Common stock	40		35
Total	$	141	$	95

__________________________


(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.


(c)	Excludes $8 million of common stock for PHI at December 31, 2015.

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

Earnings Per Share and Equity (Exelon and BGE)

Earnings Per Share and Equity (Exelon and BGE)

12 Months Ended

Dec. 31, 2016

Earnings Per Share [Abstract]

(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:



	Years Ended December 31,
	2016		2015		2014
Net income attributable to common shareholders	$	1,134	$	2,269	$	1,623
Weighted average common shares outstanding—basic	924		890		860
Assumed exercise and/or distributions of stock-based awards	3		3		4
Weighted average common shares outstanding—diluted	927		893		864

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 12 million in 2016, 16 million in 2015, and 17 million in 2014. There were no equity units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the year ended December 31, 2016. 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 were 3 million and less than 1 million for the years ended December 31, 2015 and 2014. Refer to Note 20 — Shareholders' 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, 2016. In 2008, Exelon management decided to defer indefinitely any share repurchases.

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

12 Months Ended

Dec. 31, 2016

Equity [Abstract]

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

The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2016 and 2015:



For the Year Ended December 31, 2016	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Gains and (Losses) on Foreign Currency Items			AOCI of Equity Investments			Total
Exelon^(a)
Beginning balance	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)
OCI before reclassifications	(6		)	1		(182		)	5			(4		)	(186		)
Amounts reclassified from AOCI^(b)	8			—		137			5			—			150
Net current-period OCI	2			1		(45		)	10			(4		)	(36		)
Ending balance	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
Generation^(a)
Beginning balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	(6		)	1		—			5			(4		)	(4		)
Amounts reclassified from AOCI^(b)	8			—		—			5			—			13
Net current-period OCI	2			1		—			10			(4		)	9
Ending balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1
PHI Predecessor^(a)
Beginning balance January 1, 2016	$	(8	)	$	—	$	(28	)	$	—		$	—		$	(36	)
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		1			—			—			1
Net current-period OCI	—			—		1			—			—			1
Ending balance March 23, 2016^(c)	$	(8	)	$	—	$	(27	)	$	—		$	—		$	(35	)



For the Year Ended December 31, 2015	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan items			Gains and (Losses) on 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
PHI Predecessor^(a)
Beginning balance	$	(9	)	$	—	$	(37	)	$	—		$	—		$	(46	)
OCI before reclassifications	—			—		5			—			—			5
Amounts reclassified from AOCI^(b)	1			—		4			—			—			5
Net current-period OCI	1			—		9			—			—			10
Ending balance	$	(8	)	$	—	$	(28	)	$	—		$	—		$	(36	)

_______________________


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


(b)	See next tables for details about these reclassifications.


(c)	As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied to PHI.

ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2016 and 2015. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the years ended December 31, 2016 and 2015:

For the Year Ended December 31, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statements of Operations and Comprehensive Income
							Predecessor
							January 1, 2016 to March 23, 2016
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(13	)	$	(13	)	$	—		Interest expense
Total before tax	(13		)	(13		)	—
Tax benefit	5			5			—
Net of tax	$	(8	)	$	(8	)	$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	78		$	—		$	—
Actuarial losses^(b)	(302		)	—			(1		)
Total before tax	(224		)	—			(1		)
Tax benefit	87			—			—
Net of tax	$	(137	)	$	—		$	(1	)

Gains and (losses) of FX
Gains	$	(5	)	$	(5	)	$	—
Other	—			—			—
Total before tax	(5		)	(5		)	—
Tax benefit	—			—			—
Net of tax	$	(5	)	$	(5	)	$	—

Total Reclassifications	$	(150	)	$	(13	)	$	(1	)	Comprehensive income

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
							Predecessor
	Exelon			Generation			PHI
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		)	(1		)	Interest expense
Total before tax	(35		)	(9		)	(1		)
Tax benefit	14			4			—
Net of tax	$	(21	)	$	(5	)	$	(1	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	74		$	—		$	—
Actuarial losses^(b)	(361		)	—			(6		)
Total before tax	(287		)	—			(6		)
Tax benefit	112			—			2
Net of tax	$	(175	)	$	—		$	(4	)

Total Reclassifications	$	(196	)	$	(5	)	$	(5	)	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, 2016 and 2015:



	For the Years Ended December 31,
	2016			2015			2014
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	30		$	30		$	19
Actuarial loss reclassified to periodic cost	(118		)	(140		)	(93		)
Pension and non-pension postretirement benefit plan valuation adjustment	115			62			317
Change in unrealized (gain) loss on cash flow hedges	—			(6		)	96
Change in unrealized (gain) loss on equity investments	3			1			73
Total	$	30		$	(53	)	$	412

Generation
Change in unrealized loss on cash flow hedges	$	(2	)	$	2		$	84
Change in unrealized (gain) loss on equity investments	3			1			73
Total	$	1		$	3		$	157



	Predecessor
	January 1 to March 23,		For the Years Ended December 31,
PHI	2016		2015		2014
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	—	$	6	$	5

Commitments and Contingencies (All Registrants)

12 Months Ended

Dec. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies (All Registrants)

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 $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development of 285 - 300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years. 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 have incurred $454 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. During the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that the most likely outcome would involve Exelon and Generation 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 in Operating and maintenance expense related to this specific commitment that is included in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. On December 19, 2016, Generation paid $44 million to the Maryland Energy Administration in full satisfaction of this commitment. During the fourth quarter of 2016, given continued declines in projected energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount. The commitment will now most likely be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing renewable generating assets. As a result, Exelon and Generation recorded a pre-tax $50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.

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, 2016, Generation’s estimated commitment relating to its equity purchase agreements, including in-kind services contributions, is anticipated to be as follows:



	Total
2017	$	34
2018	5
Total	$	39

Commercial Commitments

Exelon’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1,614	$	1,355	$	246	$	—	$	13	$	—	$	—
Surety bonds^(b)	1,035		978		33		2		16		6		—
Financing trust guarantees ^(c)	628		—		—		—		—		—		628
Guaranteed lease residual values^(d)	20		—		—		—		—		—		20
Total commercial commitments	$	3,297	$	2,333	$	279	$	2	$	29	$	6	$	648

___________________________


(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)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $50 million, $14 million of which is a guarantee by Pepco, $17 million by DPL and $13 million by ACE. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Generation’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1,546	$	1,287	$	246	$	—	$	13	$	—	$	—
Surety bonds	945		918		27		—		—		—		—
Total commercial commitments	$	2,491	$	2,205	$	273	$	—	$	13	$	—	$	—

________________________


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

ComEd’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	14	$	14	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	11		9		2				—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	225	$	23	$	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.

PECO’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	23	$	23	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	9		9		—		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	210	$	32	$	—	$	—	$	—	$	—	$	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.

BGE’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	11		10		1		—		—		—		—
Financing trust guarantees	250		—		—		—		—		—		250
Total commercial commitments	$	263	$	12	$	1	$	—	$	—	$	—	$	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.

PHI commercial commitments (Successor) as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	16		14		2		—		—		—		—
Guaranteed lease residual values^(c)	20		—		—		—		—		—		20
Total commercial commitments	$	37	$	15	$	2	$	—	$	—	$	—	$	20

________________________


(a)	Letters of credit (non-debt)—PHI 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)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $50 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Pepco commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Surety bonds ^(a)	9		9		—		—		—		—		—
Guaranteed lease residual values^(b)	6		—		—		—		—		—		6
Total commercial commitments	$	15	$	9	$	—	$	—	$	—	$	—	$	6

________________________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $14 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

DPL commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Surety bonds ^(a)	4		3		1		—		—		—		—
Guaranteed lease residual values^(b)	7		—		—		—		—		—		7
Total commercial commitments	$	11	$	3	$	1	$	—	$	—	$	—	$	7

________________________


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

(b)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $17 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

ACE commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	3		2		1		—		—		—		—
Guaranteed lease residual values^(c)	5		—		—		—		—		—		5
Total commercial commitments	$	9	$	3	$	1	$	—	$	—	$	—	$	5

________________________


(a)	Letters of credit (non-debt)—ACE 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)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $13 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

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, 2016 were:



	Exelon ^(a)		Generation^(a)		ComEd ^(b)		PECO ^(b)		BGE ^(b)(c)(d)		PHI		Pepco		DPL ^(b)		ACE
2017	$	183	$	70	$	11	$	3	$	32	$	50	$	7	$	13	$	8
2018	179		75		6		3		34		49		6		17		8
2019	123		30		6		4		34		36		5		7		7
2020	140		48		3		4		34		38		4		10		6
2021	133		47		3		4		32		34		3		9		5
Remaining years	968		644		—		—		33		211		7		54		20
Total minimum future lease payments	$	1,726	$	914	$	29	$	18	$	199	$	418	$	32	$	110	$	54

______________________


(a)	Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.

(b)

Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, BGE’s and DPL's average annual obligation for these arrangements, included in each of the years 2017—2021, was $2 million, $4 million, $2 million and $2 million, respectively.


(c)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.


(d)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $21 million $25 million, $26 million , $27 million, $28 million, and $14 million related to years 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2016, 2015 and 2014:




For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE		Pepco		DPL		ACE
2016	$	777	$	667	$	15	$	7	$	22	$	8	$	15	$	13
2015	922		851		12		9		32		7		14		13
2014	865		806		15		14		12		8		14		12



	Successor		Predecessor
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016	For the Year Ended December 31, 2015	For the Year Ended December 31, 2014
PHI
Rental expense under operating leases	$	49	12	60	59

________________________

(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 $604 million, $798 million and $755 million during 2016, 2015 and 2014, 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, 2016, the current liability limit per incident is $13.4 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which provides the additional $13.0 billion per incident in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer would be approximately $2.7 billion, including CENG's related liability, however any amounts payable under this secondary layer would be capped at $400 million per year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 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 $21 million for 2016, and was $21 million for 2015 and $18 million for 2014. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments if any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $353 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by Exelon will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and 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, 2016, and December 31, 2015, Generation did not incur any expense in SNF disposal fees. For the year ended December 31, 2014, Generation incurred expense of $49 million 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 SNF and high-level radioactive waste.

In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued delays on the part of the DOE, Generation currently assumes the DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

Generation uses the 2030 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. A settlement agreement for Calvert Cliffs and Nine Mile Point was executed during 2011, pursuant to which the government agreed to reimburse the costs associated with SNF storage expended or to be expended during a term set by the agreement. The term was subsequently extended during 2014 to include SNF storage costs incurred at Calvert Cliffs and Nine Mile Point through December 31, 2016. A DOE settlement agreement for Ginna was also executed during 2011. During 2015, Ginna executed another DOE settlement agreement providing for the reimbursement of SNF storage costs incurred through December 31, 2016. Generation expects the terms for each of the settlement agreements to be extended during 2017 for another three years to cover SNF storage costs through December 31, 2019. 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:



	Total		Net ^(a)
Cumulative cash reimbursements ^(b)	$	1,038	$	887

_____________________________


(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, 2016, and 2015, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:



	December 31, 2016			December 31, 2015
DOE receivable - current ^(a)	$	109		$	76
DOE receivable - noncurrent ^(b)	15			14
Amounts owed to co-owners ^(a)(c)	(13		)	(5		)

_____________________________


(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, 2016, the unfunded SNF liability for the one-time fee with interest was $1,024 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, 2016, was 0.355%. 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 Remediation 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, BGE, and DPL have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.


•	ComEd has identified 42 sites, 18 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 24 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 2021.


•	PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 9 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 2022.

•

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 2 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.


•	DPL has identified 2 sites, all of which the remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources and Environmental Control.

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. DPL has historically received recovery of actual clean-up costs in distribution rates.

As of December 31, 2016 and 2015, 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, 2016	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation ^(a)
Exelon	$	429	$	325
Generation	72		—
ComEd	292		291
PECO	33		31
BGE ^(a)	2		2
PHI	30		1
Pepco	27		—
DPL	2		1
ACE	1		—



December 31, 2015	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	369	$	301
Generation	63		—
ComEd	266		264
PECO	37		35
BGE	3		2
PHI (Predecessor)	33		1
Pepco	24		—
DPL	3		1
ACE	1		—

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 2016, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of the study resulted in a $7 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO, respectively.

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

Benning Road Site NPDES Permit Limit Exceedances. Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date, which authorizes discharges from the Benning Road service facility. The 2009 permit for the first time imposed numerical limits on the allowable concentration of certain metals in storm water discharged from the site into the Anacostia River. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for all metals.

The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater, construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. The Consent Decree has been lodged with the Court and will be subject to a 30-day public comment period. It is expected that the Court will approve the Consent Decree in the first quarter of 2017. Pepco has established appropriate reserves for the liabilities under the Consent Agreement, which is included in the table above.

Solid and Hazardous Waste

Cotter Corporation. The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated cost of the landfill cover remediation for the site is approximately $90 million including escalation, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability, which is included in the table above. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil sampling as part of the supplemental feasibility study. The final supplemental feasibility study was completed in December of 2016 and will enable the EPA to propose a remedy for public comment. While the EPA has not yet formally announced a change in the schedule, the PRPs believe that the EPA announcement of the proposed remedy will take place in the third quarter of 2017 at the earliest. Thereafter, the EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. 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 believes that a partial excavation remedy is reasonably possible, and the partial excavation costs, inclusive of a landfill cover, could range from approximately $225 million to$650 million; such costs would likely be shared by the final group of identified PRPs. Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials are believed to have been disposed. Generation has accrued what it believes to be an adequate amount to cover its anticipated liability for this interim action. 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 PRP's, 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, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the 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. The legislation has not passed in the House. 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 FUSRAP. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2017 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, which is included in the table above.

Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. The complaints do not contain specific damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a 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 connection with BGE's 2000 corporate restructuring the responsibility for this liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation's responsibility. In March 2004, the 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 the PRPs 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.

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 $4 million, which has been fully reserved as of December 31, 2016 and is included in the table above.

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. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and BGE’s future results of operations and cash flows.

Riverside. In 2013, the MDE, at the request of 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 which included 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 and BGE anticipates completing the additional work requested by the end of the first quarter of 2017. BGE has established what it believes is an appropriate reserve based upon the investigation to date. The established reserve is included in the table above. As the investigation and potential remediation proceed, it is possible that resolution of this matter could have a material, unfavorable impact on Exelon's and BGE’s future results of operations and cash flows.

Benning Road Site. In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a consent decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15 acre portion of the adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with the site. The consent decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river that are determined to be attributable to past activities at the Benning Road site.

The initial RI field work began in January 2013 and was completed in December 2014. In April 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete the RI process (much of which was beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review in February 2016. Once the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Pepco Energy Services will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE.

Upon DOEE’s approval of the final remedial investigation and feasibility study Reports, Pepco and Pepco Energy Services will have satisfied their obligations under the consent decree. At that point, DOEE will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision identifying any further response actions determined to be necessary.

PHI, Pepco and Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is probable and an estimated liability for this issue has been accrued, which is included in the table above. As the remedial investigation proceeds and potential remedies are identified, it is possible that additional reserves could be established in amounts that could be material to PHI, Pepco and Pepco Energy Services. Pursuant to Exelon's March 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. The ultimate resolution of this matter is currently not expected to have any significant financial impact on Generation.

Anacostia River Tidal Reach. Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, DOEE and certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for public review and comment. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a “Consultative Working Group” to provide input into the process for future remedial actions addressing the entire tidal reach of the river and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road RI/FS. Pepco responded that it will participate in the Consultative Working Group but its participation is not an acceptance of any financial responsibility beyond the work that will be performed at the Benning Road site described above. DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation. DOEE has targeted June 2018 as the date for remedy selection for clean-up of sediments in this section of the river. The Consultative Working Group and the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon's and Pepco’s future results of operations and cash flows.

Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold the wholesale power generation business of Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and PHI has established an appropriate accrual for its share of the estimated clean-up costs, which is included in the table above. Pursuant to Exelon’s March 2016 acquisition of PHI, Conectiv Energy was transferred to Generation, however, the responsibility to indemnify Calpine remained at PHI. The ultimate resolution of this matter is currently not expected to have any significant financial impact on PHI.

Rock Creek Mineral Oil Release. In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach, resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately 80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29, 2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party excavators struck the Pepco underground transmission line while installing cable for another utility.

To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. Exelon, PHI and Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of operations or cash flows.

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

Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million, for which an appropriate reserve has been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from NRG under the 2000 sale agreement.

Litigation and Regulatory Matters

Asbestos Personal Injury Claims (Exelon, Generation, ComEd, 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, 2016 and 2015, Generation had reserved approximately $83 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2016, approximately $22 million of this amount related to 230 open claims presented to Generation, while the remaining $61 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, 2016.

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.

To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries

have been dismissed or resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.

Continuous Power Interruption (Exelon and 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, 2016 and 2015, ComEd did not have any material liabilities recorded for these storm events.

Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO, BGE, PEPCO, DPL and ACE)

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 BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid.

PEPCO is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. PEPCO is prohibited from paying a dividend on its common shares if (a) after the dividend payment, PEPCO's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the Board or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade.

DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the Board or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade.

ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the commissions and the Board or (b) ACE’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade.

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.

Conduit Lease with City of Baltimore (Exelon and BGE)

On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual rental fees for access to the Baltimore City underground conduit system effective November 1, 2015, from $12 million to $42 million, subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and payment for the underground conduit system. As a result of the settlement, the parties have entered into a six-year lease that reduces the annual expense to $25 million in the first three years and caps the annual expense in the last three years to not more than $29 million. BGE recorded a credit to Operating and maintenance expense in the fourth quarter of approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee true-up amounts.

Deere Wind Energy Assets (Exelon and Generation)

In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in favor of Deere. On January 17, 2017, Generation filed an appeal with the Supreme Court of Delaware. Generation has accrued an amount to cover its potential liability.

General (All Registrants)

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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 (All Registrants)

12 Months Ended

Dec. 31, 2016

Supplemental Financial Information [Abstract]

Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2016, 2015 and 2014.



																		Successor		Predecessor
																		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon		Generation		ComEd			PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Taxes other than income
Utility^(a)	$	753	$	122	$	242		$	136	$	85	$	312	$	18	$	—	$	253	$	78
Property	483		246		27			13		123		53		31		3		73		18
Payroll	226		117		28			15		17		8		5		3		23		8
Other	114		21		(4		)	—		4		4		1		1		5		1
Total taxes other than income	$	1,576	$	506	$	293		$	164	$	229	$	377	$	55	$	7	$	354	$	105



											Predecessor
For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	474	$	105	$	236	$	133	$	85	$	326	$	308	$	18	$	—
Property	407		250		27		11		119		94		57		28		3
Payroll	201		118		28		14		16		27		6		4		2
Other	118		16		5		2		4		8		5		1		2
Total taxes other than income	$	1,200	$	489	$	296	$	160	$	224	$	455	$	376	$	51	$	7



											Predecessor
For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	456	$	89	$	238	$	128	$	86	$	324	$	307	$	17	$	—
Property	396		240		25		15		114		85		51		24		3
Payroll	200		118		28		14		18		23		6		4		2
Other	102		18		2		2		3		5		5		1		(1		)
Total taxes other than income	$	1,154	$	465	$	293	$	159	$	221	$	437	$	369	$	46	$	4

_____________________

(a)

Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.



																						Successor			Predecessor
																						March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon			Generation			ComEd			PECO			BGE			Pepco		DPL		ACE		PHI			PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	237		$	237		$	—		$	—		$	—		$	—	$	—	$	—	$	—		$	—
Non-regulatory agreement units	126			126			—			—			—			—		—		—		—			—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	216			216			—			—			—			—		—		—		—			—
Non-regulatory agreement units	194			194			—			—			—			—		—		—		—			—
Net unrealized losses on pledged assets
Zion Station decommissioning	(1		)	(1		)	—			—			—			—		—		—		—			—
Regulatory offset to decommissioning trust fund-related activities^(b)	(372		)	(372		)	—			—			—			—		—		—		—			—
Total decommissioning-related activities	400			400			—			—			—			—		—		—		—			—
Investment income (loss)	17			8			—			(1		)	2		^(f)	1		—		1		1			—
Long-term lease income	4			—			—			—			—			—		—		—		—			—
Interest income related to uncertain income tax positions	13			—			—			—			—			1		—		—		(1		)	—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—			—		—		—		—			—
AFUDC—Equity	64			—			14			8			19			19		5		6		23			7
Loss on debt extinguishment	(3		)	(2		)	—			—			—			—		—		—		—			—
Other	24			(5		)	7			1			—			15		8		2		21			(11		)
Other, net	$	413		$	401		$	(65	)	$	8		$	21		$	36	$	13	$	9	$	44		$	(4	)



															Predecessor
For the year ended December 31, 2015	Exelon			Generation			ComEd		PECO			BGE			PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	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		^(f)	—		—		—		—
Long-term lease income	15			—			—		—			—			—		—		—		—
Interest income related to uncertain income tax positions	1			1			—		—			—			34		5		—		—
AFUDC—Equity	24			—			5		5			14			14		12		1		1
Terminated interest rate swaps^(d)	(26		)	—			—		—			—			—		—		—		—
PHI merger related debt exchange^(e)	(22		)	—			—		—			—			—		—		—		—
Other	17			(1		)	16		2			—			40		11		9		2
Other, net	$	(46	)	$	(60	)	$	21	$	5		$	18		$	88	$	28	$	10	$	3



																Predecessor
For the year ended December 31, 2014	Exelon			Generation			ComEd		PECO			BGE				PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	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 (loss)	1			1			—		(1		)	7			^(f)	1		—		—		—
Long-term lease income	24			—			—		—			—				—		—		—		—
Interest income related to uncertain income tax positions	40			54			—		—			—				—		1		—		1
AFUDC—Equity	21			—			3		6			12				13		10		2		1
Other	9			(9		)	14		2			(1		)		30		19		8		1
Other, net	$	455		$	406		$	17	$	7		$	18			$	44	$	30	$	10	$	3

_________________________


(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)	See Note 15—Income Taxes for discussion of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.

(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 AOCI to Other, net in Exelon's Consolidated Statements of Operations and Comprehensive Income.


(e)	See Note 14—Debt and Credit Agreements and Note 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.


(f)	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 Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2016, 2015 and 2014.



																	Successor		Predecessor
																	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	3,477	$	1,835	$	708	$	244	$	299	$	175	$	110	$	82	$	325	$	94
Regulatory assets	407		—		67		26		124		120		47		83		190		58
Amortization of intangible assets, net	52		44		—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	35		35		—		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,159		1,159		—		—		—		—		—		—		—		—
ARO accretion^(c)	446		446		—		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,576	$	3,519	$	775	$	270	$	423	$	295	$	157	$	165	$	515	$	152



																	Predecessor
For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	2,227	$	1,007	$	635	$	240	$	289	$	164	$	103	$	76	$	392
Regulatory assets	170		—		72		20		77		92		45		99		232
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 and accretion	$	3,987	$	2,589	$	707	$	260	$	366	$	256	$	148	$	175	$	624



																	Predecessor
For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	2,080	$	922	$	588	$	227	$	288	$	155	$	94	$	72	$	363
Regulatory assets	191		—		99		9		83		57		28		83		163
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 and accretion	$	3,868	$	2,519	$	687	$	236	$	371	$	212	$	122	$	155	$	526

________________________


(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.



																									Successor			Predecessor
																									March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI			PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	1,340		$	339		$	298		$	104		$	92		$	118		$	47		$	62		$	209		$	43
Income taxes (net of refunds)	(441		)	435			(444		)	64			31			216			115			200			258			11
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	619		$	218		$	166		$	33		$	67		$	31		$	18		$	15		$	86		$	23
Loss from equity method investments	24			25			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	155			19			41			30			1			29			23			32			65			16
Provision for excess and obsolete inventory	12			6			4			—			—			3			1			1			1			1
Stock-based compensation costs	111			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(384		)	(384		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(11		)	(11		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	9			—			4			1			—			2			1			1			3			1
Amortization of rate stabilization deferral	76			—			—			—			81			(12		)	2			—			(5		)	5
Amortization of debt fair value adjustment	(11		)	(11		)	—			—			—			—			—			—			—			—
Merger-related commitments ^(c)(d)	558			53			—			—			—			125			82			110			317			—
Severance costs	99			22			—			—			—			—			—			—			56			—
Asset retirement costs	2			—			—			—			—			—			1			2			2			—
Amortization of debt costs	35			17			4			3			1			—			—			—			1			—
Discrete impacts from EIMA^(e)	8			—			8			—			—			—			—			—			—			—
Lower of cost or market inventory adjustment	37			36			—			1			—			—			—			—			—			—
Baltimore City Conduit Lease Settlement	(28		)	—			—			—			(28		)	—			—			—			—			—
Cash Working Capital Order	(13		)	—			—			—			(13		)	—			—			—			—			—
Other	35			25			(12		)	(3		)	(21		)	5			(14		)	(6		)	(12		)	(3		)
Total other non-cash operating activities	$	1,333		$	15		$	215		$	65		$	88		$	183		$	114		$	155		$	514		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(128	)	$	50		$	(91	)	$	(11	)	$	(86	)	$	27		$	(12	)	$	11		$	21		$	11
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash	—			119			—			—			—			—			—			—			—			—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash ^(c)(f)	—			—			—			—			—			—			—			—			127			—
Fair value of pension obligation transferred in connection with the PHI Merger ^(c)(f)	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—



Change in PPE related to ARO update	191		191		—	—	—	—	—	—	—	—
Non-cash financing of capital projects	95		95		—	—	—	—	—	—	—	—
Indemnification of like-kind exchange position ^(h)	—		—		158	—	—	—	—	—	—	—
Sale of Upstream assets^(c)	37		37		—	—	—	—	—	—	—	—
Pending FitzPatrick Acquisition⁽ⁱ⁾	(54	)	(54	)	—	—	—	—	—	—	—	—

____________________________


(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)	See Note 4 - Mergers, Acquisitions, and Dispositions for more information.


(d)	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.


(e)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 3 — Regulatory Matters for more information.


(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


(g)	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.


(h)	See Note 15 — Income Taxes for discussion of the like-kind exchange tax position.


(i)	Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 4 - Mergers, Acquisitions, and Dispositions for more information.



																								Predecessor
For the year ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE		PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	930		$	348		$	308		$	94		$	120		$	116		$	47		$	63	$	268
Income taxes (net of refunds)	342			476			(265		)	64			73			(6		)	(5		)	—		(13		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	637		$	269		$	206		$	39		$	65		$	30		$	15		$	15	$	97
Loss from equity method investments	7			8			—			—			—			—			—			—		—
Provision for uncollectible accounts	120			22			53			30			15			21			20			20		61
Stock-based compensation costs	97			—			—			—			—			—			—			—		13
Other decommissioning-related activity^(a)	(82		)	(82		)	—			—			—			—			—			—		—
Energy-related options^(b)	21			21			—			—			—			—			—			—		—
Amortization of regulatory asset related to debt costs	7			—			5			2			—			2			1			1		5
Amortization of rate stabilization deferral	73			—			—			—			73			1			(3		)	—		(2		)
Amortization of debt fair value adjustment	(17		)	(17		)	—			—			—			—			—			—		—
Discrete impacts from EIMA^(c)	144			—			144			—			—			—			—			—		—
Amortization of debt costs	58			15			4			2			2			—			—			—		2
Provision for excess and obsolete inventory	10			9			1			—			—			—			—			—		1
Lower of cost or market inventory adjustment	23			23			—			—			—			—			—			—		—
Other	11			—			3			(3		)	(18		)	—			—			1		(10		)
Total other non-cash operating activities	$	1,109		$	268		$	416		$	70		$	137		$	54		$	33		$	37	$	167
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	96		$	82		$	34		$	(13	)	$	(9	)	$	(1	)	$	3		$	3	$	6
Nuclear fuel procurement^(d)	57			57			—			—			—			—			—			—		—
Change in PPE related to ARO update	885			885			—			—			—			—			—			—		—
Indemnification of like-kind exchange position^(e)	—			—			7			—			—			—			—			—		—
Non-cash financing of capital projects	77			77			—			—			—			—			—			—		—
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. 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.



																										Predecessor
For the year ended December 31, 2014	Exelon			Generation				ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	940		$	322			$	292		$	94		$	111		$	111		$	45		$	61		$	257
Income taxes (net of refunds)	314			227				(6		)	85			(21		)	(58		)	(43		)	(3		)	(2		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	560		$	249			$	162		$	36		$	64		$	22		$	7		$	13		$	58
Loss from equity method investments	22			20				—			—			—			—			—			—			—
Provision for uncollectible accounts	156			14				26			52			64			17			14			13			49
Provision for excess and obsolete inventory	5			5				—			—			—			—			—			—			—
Stock-based compensation costs	91			—				—			—			—			—			—			—			18
Other decommissioning-related activity^(a)	(132		)	(132		)		—			—			—			—			—			—			—
Energy-related options^(b)	122			122				—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	11			—				8			3			—			3			2			—			5
Amortization of rate stabilization deferral	65			—				—			—			65			3			(1		)	—			2
Amortization of debt fair value adjustment	(23		)	(23		)		—			—			—			—			—			—			—
Merger-related commitments	44			44				—			—			—			—			—			—			—
Discrete impacts from EIMA^(c)	53			—				53			—			—			—			—			—			—
Amortization of debt costs	53			12				4			2			2			—			—			—			1
Lower of cost or market inventory adjustment	29			29				—			—			—			—			—			—			—
Other	(2		)	6				2			(1		)	(15		)	(8		)	—			—			(6		)
Total other non-cash operating activities	$	1,054		$	346			$	255		$	92		$	180		$	37		$	22		$	26		$	127
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			10			8			9			28
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. 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 21 — 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.

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 years ended December 31, 2016 and 2015, PECO had no capital expenditures or reimbursements, as the DOE SGIG program was completed during 2014. 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, 2016 and 2015.



											Successor
December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8	$	—	$	—	$	—	$	—
Bloom	216		216		—		—		—		—		—		—		—
Net Power	57		57		—		—		—		—		—		—		—
Other equity method investments	16		15		—		—		—		—		—		—		—
Total equity method investments	311		288		6		8		8		—		—		—		—
Other investments:
Employee benefit trusts and investments (c)	232		44		—		17		4		133		102		—		—
Other cost method investments	52		52		—		—		—		—		—		—		—
Other available for sale investments	34		34		—		—		—		—		—		—		—
Total investments	$	629	$	418	$	6	$	25	$	12	$	133	$	102	$	—	$	—



											Predecessor
December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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		80		68		—		—
Other cost method investments	55		55		—		—		—		—		—		—		—
Other available for sale investments	29		29		—		—		—		—		—		—		—
Total investments	$	639	$	210	$	6	$	28	$	12	$	80	$	68	$	—	$	—

_________________________


(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, 2016 and 2015.



											Successor
December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	1,199	$	557	$	199	$	67	$	64	$	112	$	30	$	17	$	11
Taxes accrued	723		239		330		4		78		65		48		4		9
Interest accrued	1,234		82		609		30		31		49		21		8		12
Severance accrued	44		15		2		—		—		19		—		—		—
Other accrued expenses	260		96		110		3		2		27		14		7		6
Total accrued expenses	$	3,460	$	989	$	1,250	$	104	$	175	$	272	$	113	$	36	$	38

											Predecessor
December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	1,014	$	547	$	183	$	66	$	57	$	88	$	26	$	14	$	8
Taxes accrued	293		186		63		4		23		77		56		3		23
Interest accrued	915		77		443		35		27		54		23		8		13
Severance accrued	21		11		3		—		1		—		—		—		—
Other accrued expenses	133		114		14		4		2		47		14		6		26
Total accrued expenses	$	2,376	$	935	$	706	$	109	$	110	$	266	$	119	$	31	$	70

_______________________


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

Segment Information (All Registrants)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Segment Information (All Registrants)

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

In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE. As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI's three reportable segments consisting of Pepco, DPL, and ACE, and Generation’s six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO, BGE, Pepco, DPL and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL and ACE based on net income and return on equity.

Effective with the consummation of the PHI Merger, PHI's reportable segments have changed based on the information used by the CODM to evaluate performance and allocate resources. PHI's reportable segments consist of Pepco, DPL and ACE. PHI's Predecessor periods' segment information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI's reported consolidated revenues or net income. PHI's CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net income and return on equity.

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


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

•

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


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


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


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


•	Other Power Regions:

•

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


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


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

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

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the years ended December 31, 2016, 2015, and 2014 is as follows:



									Successor
	Generation ^(a)		ComEd		PECO		BGE		PHI ^(e)		Other ^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2016
Competitive businesses electric revenues	$	15,390	$	—	$	—	$	—	$	—	$	—	$	(1,430	)	$	13,960
Competitive businesses natural gas revenues	2,146		—		—		—		—		—		—			2,146
Competitive businesses other revenues	215		—		—		—		—		—		(4		)	211



Rate-regulated electric revenues	—			5,254		2,531		2,609		3,506		—		(31		)	13,869
Rate-regulated natural gas revenues	—			—		463		624		92		—		(13		)	1,166
Shared service and other revenues	—			—		—		—		45		1,648		(1,686		)	7
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
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
Intersegment revenues^(d):
2016	$	1,428		$	15	$	8	$	21	$	45	$	1,647	$	(3,159	)	$	5
2015	745			4		2		14		—		1,367		(2,127		)	5
2014	762			4		2		25		—		1,280		(2,067		)	6
Depreciation and amortization:
2016	$	1,879		$	775	$	270	$	423	$	515	$	74	$	—		$	3,936
2015	1,054			707		260		366		—		63		—			2,450
2014	967			687		236		371		—		53		—			2,314
Operating expenses ^(c):
2016	$	16,856		$	4,056	$	2,292	$	2,683	$	3,549	$	1,928	$	(3,164	)	$	28,200
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
Equity in earnings (losses) of unconsolidated affiliates:
2016	$	(25	)	$	—	$	—	$	—	$	—	$	1	$	—		$	(24	)
2015	(8		)	—		—		—		—		1		—			(7		)
2014	(20		)	—		—		—		—		—		—			(20		)
Interest expense, net:
2016	$	364		$	461	$	123	$	103	$	195	$	290	$	—		$	1,536
2015	365			332		114		99		—		123		—			1,033
2014	356			321		113		106		—		169		—			1,065
Income (loss) before income taxes:



2016	$	873	$	679	$	587	$	468	$	(58	)	$	(555	)	$	(5	)	$	1,989
2015	1,850		706		521		477		—			(219		)	(5		)	3,330
2014	1,226		676		466		351		—			(227		)	(6		)	2,486
Income taxes:
2016	$	290	$	301	$	149	$	174	$	3		$	(156	)	$	—		$	761
2015	502		280		143		189		—			(41		)	—			1,073
2014	207		268		114		140		—			(63		)	—			666
Net income (loss):
2016	$	558	$	378	$	438	$	294	$	(61	)	$	(398	)	$	(5	)	$	1,204
2015	1,340		426		378		288		—			(177		)	(5		)	2,250
2014	1,019		408		352		211		—			(164		)	(6		)	1,820
Capital expenditures:
2016	$	3,078	$	2,734	$	686	$	934	$	1,008		$	113		$	—		$	8,553
2015	3,841		2,398		601		719		—			65			—			7,624
2014	3,012		1,689		661		620		—			95			—			6,077
Total assets:
2016	$	46,974	$	28,335	$	10,831	$	8,704	$	21,025		$	10,369		$	(11,334	)	$	114,904
2015	46,529		26,532		10,367		8,295		—			15,389			(11,728		)	95,384

__________________________

(a)

Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended December 31, 2016, intersegment revenues for Generation include revenue from sales to PECO of $290 million, sales to BGE of $608 million, sales to Pepco of $295 million, sales to DPL of $154 million and sales to ACE of $37 million in the Mid-Atlantic region, and sales to ComEd of $47 million in the Midwest region, which eliminate upon consolidation. 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, 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, 2016, 2015 and 2014, utility taxes of $122 million, $105 million and $89 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $242 million, $236 million and $238 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $136 million, $133 million and $128 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $85 million, $85 million and $86 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.


(e)	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the years ended December 31, 2015 and December 31, 2014.

Successor and Predecessor PHI:



	Pepco		DPL		ACE		Other^(b)		Intersegment Eliminations			PHI
Operating revenues^(a):
March 24, 2016 to December 31, 2016 - Successor
Rate-regulated electric revenues	$	1,675	$	850	$	989	$	5	$	(13	)	$	3,506
Rate-regulated natural gas revenues	—		92		—		—		—			92
Shared service and other revenues	—		—		—		45		—			45
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues	$	511	$	279	$	268	$	42	$	(4	)	$	1,096
Rate-regulated natural gas revenues	—		56		—		1		—			57
Shared service and other revenues	—		—		—		—		—			—
December 31, 2015 - Predecessor
Rate-regulated electric revenues	$	2,129	$	1,138	$	1,295	$	210	$	(2	)	$	4,770



Rate-regulated natural gas revenues	—		164			—			1			—			165
Shared service and other revenues	—		—			—			—			—			—
December 31, 2014 - Predecessor
Rate-regulated electric revenues	$	2,055	$	1,088		$	1,210		$	264		$	(3	)	$	4,614
Rate-regulated natural gas revenues	—		194			—			—			—			194
Shared service and other revenues	—		—			—			—			—			—
Intersegment revenues:
March 24, 2016 to December 31, 2016 - Successor	$	4	$	5		$	2		$	47		$	(13	)	$	45
January 1, 2016 to March 23, 2016 - Predecessor	1		2			1			—			(4		)	—
December 31, 2015 - Predecessor	5		6			4			—			(15		)	—
December 31, 2014 - Predecessor	5		7			4			—			(16		)	—
Depreciation and amortization:
March 24, 2016 to December 31, 2016 - Successor	$	224	$	120		$	128		$	43		$	—		$	515
January 1, 2016 to March 23, 2016 - Predecessor	71		37			37			11			(4		)	152
December 31, 2015 - Predecessor	256		148			175			45			—			624
December 31, 2014 - Predecessor	212		122			155			38			(1		)	526
Operating expenses:
March 24, 2016 to December 31, 2016 - Successor	$	1,577	$	952		$	1,000		$	33		$	(13	)	$	3,549
January 1, 2016 to March 23, 2016 - Predecessor	443		284			251			73			(3		)	1,048
December 31, 2015 - Predecessor	1,790		1,137			1,161			220			—			4,308
December 31, 2014 - Predecessor	1,706		1,075			1,073			350			(1		)	4,203
Interest expense, net:
March 24, 2016 to December 31, 2016 - Successor	$	98	$	38		$	47		$	12		$	—		$	195
January 1, 2016 to March 23, 2016 - Predecessor	29		12			15			11			(2		)	65
December 31, 2015 - Predecessor	124		50			64			43			(1		)	280
December 31, 2014 - Predecessor	115		48			64			42			—			269
Income (loss) before income taxes:
March 24, 2016 to December 31, 2016 - Successor	$	36	$	(30	)	$	(51	)	$	(84	)	$	71		$	(58	)
January 1, 2016 to March 23, 2016 - Predecessor	47		43			5			59			(118		)	36
December 31, 2015 - Predecessor	289		125			73			23			(29		)	481
December 31, 2014 - Predecessor	264		169			76			306			(435		)	380
Income taxes:
March 24, 2016 to December 31, 2016 - Successor	$	26	$	5		$	(5	)	$	(23	)	$	—		$	3
January 1, 2016 to March 23, 2016 - Predecessor	15		17			1			(16		)	—			17
December 31, 2015 - Predecessor	102		49			33			(48		)	27			163
December 31, 2014 - Predecessor	93		65			30			(228		)	178			138
Net income (loss):
March 24, 2016 to December 31, 2016 - Successor	$	10	$	(35	)	$	(47	)	$	(34	)	$	45		$	(61	)
January 1, 2016 to March 23, 2016 - Predecessor	32		26			5			(44		)	—			19
December 31, 2015 - Predecessor	187		76			40			25			(1		)	327
December 31, 2014 - Predecessor	171		104			46			(78		)	(1		)	242
Capital Expenditures:
March 24, 2016 to December 31, 2016 - Successor	$	489	$	277		$	218		$	24		$	—		$	1,008
January 1, 2016 to March 23, 2016 - Predecessor	97		72			93			11			—			273
December 31, 2015 - Predecessor	544		352			300			34			—			1,230
December 31, 2014 - Predecessor	567		352			225			79			—			1,223
Total assets:
December 31, 2016 - Successor	$	7,335	$	4,153		$	3,457		$	10,804		$	(4,724	)	$	21,025
December 31, 2015 - Predecessor	6,908		3,969			3,387			7,162			(5,238		)	16,188

_________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 25 — Supplemental Financial Information for total utility taxes for the year ended December 31, 2016 and 2015


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

Generation total revenues:



	2016							2015							2014
	Revenues from external customers^(b)		Intersegment revenues			Total revenues		Revenues from external customers^(b)		Intersegment revenues			Total revenues		Revenues from external customers^(b)(d)		Intersegment revenues^(d)			Total revenues
Mid-Atlantic ^(a)	$	6,212	$	(33	)	$	6,179	$	5,974	$	(74	)	$	5,900	$	5,414	$	(155	)	$	5,259
Midwest	4,402		10			4,412		4,712		(2		)	4,710		4,488		(13		)	4,475
New England	1,778		(9		)	1,769		2,217		(5		)	2,212		1,468		(46		)	1,422
New York ^(a)	1,198		(42		)	1,156		996		(11		)	985		846		(3		)	843
ERCOT	831		6			837		863		(6		)	857		938		(3		)	935
Other Power Regions	969		(62		)	907		1,182		(80		)	1,102		1,379		(70		)	1,309
Total Revenues for Reportable Segments	$	15,390	$	(130	)	$	15,260	$	15,944	$	(178	)	$	15,766	$	14,533	$	(290	)	$	14,243
Other ^(c)	2,361		130			2,491		3,191		178			3,369		2,860		290			3,150
Total Generation Consolidated Operating Revenues	$	17,751	$	—		$	17,751	$	19,135	$	—		$	19,135	$	17,393	$	—		$	17,393

_______________________


(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 the Utility Registrants.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $52 million decrease to revenues, a $7 million increase to revenues, and a $289 million decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2016, 2015, and 2014, respectively, unrealized mark-to-market losses of $500 million, gains of $203 million, and losses of $174 million for the years ended December 31, 2016, 2015, and 2014, respectively, and elimination of intersegment revenues.

(d)

Exelon corrected an error in the December 31, 2014 balances within Intersegment revenues and Revenues from external customers for an overstatement of Intersegment revenues for Reportable Segments of $284 million for the year ended December 31, 2014, an understatement of Revenues from external customers for Reportable Segments of $284 million for the year ended December 31, 2014, an understatement of Intersegment revenues for Other of $284 million for the year ended December 31, 2014, and an overstatement of Revenues from external customers for Other of $284 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 Total Revenues.

Generation total revenues net of purchased power and fuel expense:



	2016							2015							2014
	RNF from external customers^(b)		Intersegment RNF			Total RNF		RNF from external customers^(b)		Intersegment RNF			Total RNF		RNF from external customers^(b)(d)			Intersegment RNF^(d)			Total RNF
Mid-Atlantic ^(a)	$	3,282	$	35		$	3,317	$	3,556	$	15		$	3,571	$	3,544		$	(113	)	$	3,431
Midwest	2,969		2			2,971		2,912		(20		)	2,892		2,607			(8		)	2,599
New England	467		(29		)	438		519		(58		)	461		450			(99		)	351
New York ^(a)	761		(19		)	742		584		50			634		439			44			483
ERCOT	412		(131		)	281		425		(132		)	293		573			(256		)	317
Other Power Regions	483		(147		)	336		440		(190		)	250		517			(190		)	327
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	8,374	$	(289	)	$	8,085	$	8,436	$	(335	)	$	8,101	$	8,130		$	(622	)	$	7,508
Other ^(c)	547		289			836		678		335			1,013		(662		)	622			(40		)
Total Generation Revenues net of purchased power and fuel expense	$	8,921	$	—		$	8,921	$	9,114	$	—		$	9,114	$	7,468		$	—		$	7,468

____________________________


(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 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 the Utility Registrants.

(c)

Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $57 million decrease in RNF, a $8 million increase in RNF, and a $124 million decrease in RNF for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2016, 2015, and 2014, respectively, unrealized mark-to-market losses of $41 million, gains of $257 million, and losses of $591 million for the years ended December 31, 2016, 2015, and 2014, respectively, accelerated nuclear fuel amortization associated with the initial early retirement decision for Clinton and Quad Cities as discussed in Note 9 - Early Nuclear Plant Retirements of $60 million for the year ended December 31, 2016, and the elimination of intersegment revenues net of purchased power and fuel expense.

(d)

Exelon corrected an error in the December 31, 2014 balances within Intersegment RNF and RNF from external customers for an understatement of $8 million of Intersegment RNF for Reportable Segments for the year ended December 31, 2014, an understatement of RNF from external customers for Reportable Segments of $11 million for the year ended December 31, 2014, an overstatement of $8 million of Intersegment RNF for Other for the year ended December 31, 2014, and an overstatement of RNF from external customers for Other of $11 million for the year ended December 31, 2014. 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 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
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Quarterly Data (Unaudited) (All Registrants)

Related Party Transactions (All Registrants)

12 Months Ended

Dec. 31, 2016

(All Registrants)

Exelon

The financial statements of Exelon include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016			2015			2014
Operating revenues from affiliates:
PECO ^(a)	$	1		$	1		$	1
CENG ^(b)	—			—			17
BGE ^(a)	4			4			5
Other	5			4			—
Total operating revenues from affiliates	$	10		$	9		$	23
Purchase power and fuel from affiliates:
CENG^(c)	$	—		$	—		$	282
Keystone Fuels, LLC ^(d)	—			—			138
Conemaugh Fuels, LLC ^(d)	—			—			99
Safe Harbor Water Power Corp ^(d)	—			—			12
Total purchase power and fuel from affiliates	$	—		$	—		$	531
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	)
Qualifying facilities and domestic power projects	(25		)	(8		)	(1		)
Other	1			1			—
Total losses in equity method investments	$	(24	)	$	(7	)	$	(20	)



	December 31,
	2016		2015
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 Statements 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,BGE, PHI, Pepco, DPL and ACE are further described in the tables below.

Generation

The financial statements of Generation include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016			2015			2014
Operating revenues from affiliates:
ComEd ^(a)	$	47		$	18		$	176
PECO ^(b)	290			224			198
BGE ^(c)	608			502			387
Pepco ^(d)	295			—			—
DPL ^(e)	154			—			—
ACE^(f)	37			—			—
CENG ^(g)	—			—			17
BSC	2			1			1
Other	6			4			—
Total operating revenues from affiliates	$	1,439		$	749		$	779
Purchase power and fuel from affiliates:
ComEd	$	—		$	—		$	1
BGE	12			14			25
CENG ^(h)	—			—			282
Keystone Fuels, LLC ^(l)	—			—			138
Conemaugh Fuels, LLC ^(l)	—			—			99
Safe Harbor Water Power Corporation^(l)	—			—			12
Total purchase power and fuel from affiliates	$	12		$	14		$	557
Operating and maintenance from affiliates:
ComEd ⁽ⁱ⁾	$	7		$	4		$	3
PECO ⁽ⁱ⁾	3			2			2
BGE ⁽ⁱ⁾	1			—			—
PHI	1			—			—
Pepco	1			—			—
BSC ^(j)	650			614			618
Total operating and maintenance from affiliates	$	663		$	620		$	623
Interest expense to affiliates, net:
Exelon Corporate ^(m)	$	39		$	43		$	53
Earnings (losses) in equity method investments
CENG^(k)	$	—		$	—		$	(19	)
Qualifying facilities and domestic power projects	(25		)	(8		)	(1		)
Total losses in equity method investments	$	(25	)	$	(8	)	$	(20	)
Capitalized costs
BSC ^(j)	$	98		$	76		$	91
Cash distribution paid to member	$	922		$	2,474		$	645
Contribution from member	$	142		$	47		$	53



	December 31,
	2016		2015
Receivables from affiliates (current):
ComEd ^(a)	$	14	$	15
PECO ^(b)	33		36
BGE ^(c)	26		31
Pepco ^(d)	44		—
DPL ^(e)	16		—
ACE ^(f)	9		—
PHISCO ^(j)	5		—
PCI	8		—
Other	1		1
Total receivables from affiliates (current)	$	156	$	83
Intercompany money pool (current):
Exelon Corporate	$	—	$	1,252
PCI	55		—
Total intercompany money pool (current)	$	55	$	1,252
Payables to affiliates (current):
Exelon Corporate ^(m)	$	22	$	16
BSC ^(j)	99		78
ComEd	9		9
Other	7		1
Total payables to affiliates (current)	$	137	$	104
Long-term debt due to affiliates (noncurrent):
Exelon Corporate ^(o)	$	922	$	933
Payables to affiliates (noncurrent):
BSC ^(g)	$	1	$	—
ComEd ⁽ⁿ⁾	2,169		2,172
PECO ⁽ⁿ⁾	438		405
Total payables to affiliates (noncurrent)	$	2,608	$	2,577

_______________________


(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 a ten-year agreement with PECO to sell solar AECs. 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)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. See Note 3—Regulatory Matters for additional information.


(e)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.


(f)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. See Note 3—Regulatory Matters for additional information.

(g)

(h)


(i)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.


(j)	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(k)

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.


(l)	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.


(m)	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.


(n)	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.

(o)

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,
	2016		2015		2014
Operating revenues from affiliates
Generation	$	7	$	4	$	4
BSC	6		—		—
PECO	1		—		—
BGE	1		—		—
Total operating revenues from affiliates	$	15	$	4	$	4
Purchased power from affiliate
Generation ^(a)	$	47	$	18	$	176
Operating and maintenance from affiliates
BSC ^(b)	$	225	$	195	$	166
PECO	1		—		—
BGE	1		—		—
Total operating and maintenance from affiliates	227		195		166
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC ^(b)	$	112	$	103	$	77
Cash dividends paid to parent	$	369	$	299	$	307
Contribution from parent	$	315	$	202	$	273



	December 31,
	2016		2015
Prepaid voluntary employee beneficiary association trust ^(c)	$	5	$	11
Receivable from affiliates (current):
Voluntary employee beneficiary association trust	$	2	$	2
Generation	9		9
Exelon Corporate ^(e)	345		188
Total receivable from affiliates (current)	$	356	$	199
Receivable from affiliates (noncurrent):
Generation ^(d)	$	2,169	$	2,172
Other	1		—
Total receivable from affiliates (noncurrent)	$	2,170	$	2,172
Payables to affiliates (current):
Generation ^(a)	$	14	$	15
BSC ^(b)	42		39
ComEd Financing III	4		4
PECO	2		2
Exelon Corporate	3		2
Total payables to affiliates (current)	$	65	$	62
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.

PECO

The financial statements of PECO include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
Generation ^(a)	$	3	$	2	$	2
BSC	3		—		—
ComEd	1		—		—
BGE	1		—		—
Total operating revenues from affiliates	$	8	$	2	$	2
Purchased power from affiliate
Generation^(b)	$	287	$	220	$	194
Operating and maintenance from affiliates:
BSC ^(c)	$	142	$	107	$	96
Generation	2		3		3
ComEd	1		—		—
BGE	1		—		$	—
Total operating and maintenance from affiliates	$	146	$	110	$	99
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)	$	57	$	40	$	39
Cash dividends paid to parent	$	277	$	279	$	320
Contribution from parent	$	18	$	16	$	24



	December 31,
	2016		2015
Prepaid voluntary employee beneficiary association trust ^(d)	$	1	$	2
Receivable from affiliate (current):
ComEd	$	2	$	2
BGE	2		—
Total receivable from affiliates (current)	$	4	$	2
Receivable from affiliate (noncurrent):
Generation ^(e)	$	438	$	405
Payables to affiliates (current):
Generation^(b)	$	33	$	36
BSC^(c)	28		17
Exelon Corporate	1		1
PECO Trust III	1		1
Total payables to affiliates (current)	$	63	$	55
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,
	2016		2015		2014
Operating revenues from affiliates:
Generation ^(a)	$	13	$	14	$	25
BSC	6		—		—
ComEd	1		—		—
PECO	1		—		—
Total operating revenues from affiliates	$	21	$	14	$	25
Purchased power from affiliate
Generation ^(b)	$	604	$	498	$	382
Operating and maintenance from affiliates:
BSC ^(c)	$	130	$	118	$	103
ComEd	1		—		—
PECO	1		—		—
Total operating and maintenance from affiliates	$	132	$	118	$	103
Interest expense to affiliates, net:
BGE Capital Trust II	$	16	$	16	$	16
Capitalized costs
BSC ^(c)	$	36	$	28	$	19
Cash dividends paid to parent	$	179	$	158	$	—
Contribution from parent	$	61	$	7	$	—



	December 31,
	2016		2015
Payables to affiliates (current):
Generation ^(b)	$	26	$	31
BSC ^(c)	22		17
Exelon Corporate	1		1
PECO	2		—
BGE Capital Trust II	3		3
Other	1		—
Total payables to affiliates (current)	$	55	$	52
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.

PHI

The financial statements of PHI include related party transactions as presented in the tables below:



	Successor
	March 24, 2016 to December 31, 2016
	March 24, 2016 to December 31, 2016
Operating revenues from affiliates:
BSC	$	44
Generation	1
Total operating revenues from affiliates	$	45
Purchased power from affiliate
Generation	$	486
Operating and maintenance from affiliates:
BSC	$	86
PCI	3
Total operating and maintenance from affiliates	$	89

Cash dividends paid to parent	$	273
Contribution from member	$	1,251




	December 31,
	2016
	Successor
Payables to affiliates (current):
Generation	$	74
BSC	10
Exelon Corporate	6
PHI Corporate	4
Total payables to affiliates (current)	$	94

Pepco

The financial statements of Pepco include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
Generation ^(a)	$	1	$	—	$	—
PHISCO	4		5		5
Total operating revenues from affiliates	$	5	$	5	$	5
Purchased power from affiliate
Generation ^(b)	$	295	$	—	$	—
Operating and maintenance:
PHISCO ^(c)	$	263	$	240	$	220
PES ^(d)	39		26		30
Total operating and maintenance	$	302	$	266	$	250
Operating and maintenance from affiliates:
BSC ^(c)	$	31	$	—	$	—
PHISCO ^(c)	4		4		4
Total operating and maintenance from affiliates	$	35	$	4	$	4
Cash dividends paid to parent	$	136	$	146	$	86
Contribution from parent	$	187	$	112	$	80



	December 31,
	2016		2015
Payables to affiliates (current):
Generation ^(b)	$	44	$	—
BSC ^(c)	4		—
DPL	1		—
PHISCO ^(c)	25		25
PES ^(e)	—		4
Other	—		1
Total payables to affiliates (current)	$	74	$	30

______________________


(a)	Pepco provides energy to Generation for Generation’s own use.


(b)	Pepco procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.


(c)	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(d)	PES performs underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.


(e)	Pepco bills customers on behalf of PES where PES has performed work for certain government agencies under a General Services Administration area-wide agreement on behalf of Pepco.

DPL

The financial statements of DPL include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
PHISCO	$	5	$	5	$	6
Other	2		1		1
Total operating revenues from affiliates	$	7	$	6	$	7
Purchased power from affiliate
Generation ^(a)	$	154	$	—	$	—
Operating and maintenance:
PHISCO ^(b)	$	194	$	179	$	163
PES ^(c)	8		3		—
Total operating and maintenance	$	202	$	182	$	163
Operating and maintenance from affiliates:
BSC ^(b)	$	18	$	—	$	—
Other	1		1		1
Total operating and maintenance from affiliates	$	19	$	1	$	1
Cash dividends paid to parent	$	54	$	92	$	100
Contribution from parent	$	152	$	75	$	130



	December 31,
	2016		2015
Receivables from affiliates (current):
Pepco	$	1	$	—
ACE	2		—
Total receivable from affiliates (current)	$	3	$	—
Payables to affiliates (current):
Generation ^(a)	$	16	$	—
BSC ^(b)	3		—
PHISCO ^(b)	19		19
Other	—		1
Total payables to affiliates (current)	$	38	$	20

______________________


(a)	DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.


(b)	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.


(c)	PES performs underground transmission construction services, including services that are treated as capital costs, for DPL.

ACE

The financial statements of ACE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
PHISCO	$	2	$	2	$	1
Other	1		2		3
Total operating revenues from affiliates	$	3	$	4	$	4
Purchased power from affiliate
Generation ^(a)	$	37	$	—	$	—
Operating and maintenance:
PHISCO ^(b)	$	155	$	143	$	124
Operating and maintenance from affiliates:
BSC ^(b)	$	15	$	—	$	—
Other	3		3		3
Total operating and maintenance from affiliates	$	18	$	3	$	3
Cash dividends paid to parent	$	63	$	12	$	26
Contribution from parent	$	139	$	95	$	—



	December 31,
	2016		2015
Payables to affiliates (current):
Generation ^(a)	$	9	$	—
BSC ^(b)	2		—
DPL	2		—
PHISCO ^(b)	16		15
Other	—		1
Total payables to affiliates (current)	$	29	$	16

______________________


(a)	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. See Note 3—Regulatory Matters for additional information.


(b)	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Quarterly Data (Unaudited) (All Registrants)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Data [Abstract]

(Unaudited) (All Registrants)

Exelon

The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income Attributable to Common Shareholders
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	7,573	$	8,830	$	483	$	1,366	$	173	$	693
June 30	6,910		6,514		647		1,134		267		638
September 30	9,002		7,401		1,267		1,200		490		629
December 31	7,875		6,702		714		707		204		309



	Average Basic Shares Outstanding (in millions)		Net Income per Basic Share
	2016	2015	2016		2015
Quarter ended:
March 31	923	862	$	0.19	$	0.80
June 30	924	863	0.29		0.74
September 30	925	913	0.53		0.69
December 31	925	921	0.22		0.34
	Average Diluted Shares Outstanding (in millions)		Net Income per Diluted Share
	2016	2015	2016		2015
Quarter ended:
March 31	925	867	$	0.19	$	0.80
June 30	926	866	0.29		0.74
September 30	927	915	0.53		0.69
December 31	928	924	0.22		0.33

The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:



	2016								2015
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	36.36	$	37.70	$	36.37	$	35.95	$	31.37	$	34.44	$	34.98	$	38.25
Low price	29.82		32.86		33.18		26.26		25.09		28.41		31.28		31.71
Close	35.49		33.29		36.36		35.86		27.77		29.70		31.42		33.61
Dividends	0.318		0.318		0.318		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 Attributable to Membership Interest
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	4,739	$	5,840	$	415		$	719	$	310		$	443
June 30	3,589		4,232		(13		)	703		(8		)	398
September 30	5,035		4,768		342			622		236			377
December 31	4,388		4,294		94			230		(41		)	154

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
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	1,249	$	1,185	$	274	$	230	$	115	$	90
June 30	1,286		1,148		324		243		145		99
September 30	1,497		1,376		389		327		37		149
December 31	1,223		1,196		217		217		80		87

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 Attributable to Common Shareholders
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	841	$	985	$	196	$	223	$	124	$	139
June 30	664		661		152		124		100		70
September 30	788		740		204		154		122		90
December 31	701		645		150		128		92		79

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
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	929	$	1,036	$	187	$	204	$	98	$	106
June 30	680		628		59		99		31		44
September 30	812		725		115		110		54		51
December 31	812		746		190		144		103		74

PHI

The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:



	Successor			Predecessor		Successor				Predecessor		Successor				Predecessor
	Operating Revenues					Operating (Loss) Income						Net (Loss) Income Attributable to Membership Interest
	2016			2015		2016				2015		2016				2015
Quarter ended:
March 31	$	105	^(a)	$	1,354	$	(411	)	^(a)	$	142	$	(309	)	^(a)	$	53
June 30	1,066			1,119		136				139		52				53
September 30	1,394			1,336		279				184		166				91
December 31	1,078			1,126		90				208		30				130



	Predecessor
	Operating Revenues	Operating Income	Net Income Attributable to Membership Interest

January 1, 2016 - March 23, 2016	1,153	105	19

____________________________


(a)	Amounts for March 31, 2016 reflect the PHI Successor activity for the period March 24, 2016 to March 31, 2016.

Pepco

The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income					Net (Loss) Income Attributable to Common Shareholders
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	551	$	545	$	(105	)	$	63	$	(108	)	$	26
June 30	509		504		97			83		49			42
September 30	635		592		132			115		79			60
December 31	491		488		51			123		23			59

DPL

The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income					Net (Loss) Income Attributable to Common Shareholders
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	362	$	421	$	(72	)	$	63	$	(72	)	$	32
June 30	281		271		30			24		12			8
September 30	331		314		72			32		44			15
December 31	303		296		20			46		7			21

ACE

The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income					Net (Loss) Income Attributable to Common Shareholders
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	291	$	334	$	(121	)	$	29	$	(100	)	$	9
June 30	270		285		19			25		3			6
September 30	421		386		83			51		47			22
December 31	275		291		26			29		8			3

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)

12 Months Ended

Dec. 31, 2016

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)	2016			2015			2014
Operating expenses
Operating and maintenance	$	221		$	—		$	9
Operating and maintenance from affiliates	51			43			38
Other	4			4			3
Total operating expenses	276			47			50
Operating loss	(276		)	(47		)	(50		)
Other income and (deductions)
Interest expense, net	(312		)	(168		)	(237		)
Equity in earnings of investments	1,521			2,461			1,779
Interest income from affiliates, net	39			43			53
Other, net	7			(43		)	(2		)
Total other income	1,255			2,293			1,593
Income before income taxes	979			2,246			1,543
Income taxes	(155		)	(23		)	(80		)
Net income	$	1,134		$	2,269		$	1,623
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs	$	(48	)	$	(46	)	$	(30	)
Actuarial loss reclassified to periodic cost	184			220			147
Pension and non-pension postretirement benefit plan valuation adjustment	(181		)	(99		)	(497		)
Unrealized gain (loss) on cash flow hedges	2			9			(148		)
Unrealized gain on marketable securities	1			—			1
Unrealized (loss) gain on equity investments	(4		)	(3		)	8
Unrealized gain (loss) on foreign currency translation	10			(21		)	(9		)
Reversal of CENG equity method AOCI	—			—			(116		)
Other comprehensive (loss) income	(36		)	60			(644		)
Comprehensive income	$	1,098		$	2,329		$	979

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)	2016			2015			2014
Net cash flows provided by operating activities	$	1,029		$	3,071		$	806
Cash flows from investing activities
Return on investment of direct financing lease termination	—			—			335
Changes in Exelon intercompany money pool	1,390			(1,217		)	(83		)
Note receivable from affiliates	—			550			—
Capital expenditures	—			—			1
Investment in affiliates	(1,757		)	(212		)	(70		)
Acquisition of business	(6,962		)	—			—
Other investing activities	5			(55		)	(126		)
Net cash flows (used in) provided by investing activities	(7,324		)	(934		)	57
Cash flows from financing activities
Issuance of long-term debt	1,800			4,200			1,150
Retirement of long-term debt	(46		)	(2,263		)	(23		)
Issuance of common stock	—			1,868			—
Dividends paid on common stock	(1,166		)	(1,105		)	(1,065		)
Proceeds from employee stock plans	55			32			35
Other financing activities	(20		)	(58		)	(84		)
Net cash flows provided by financing activities	623			2,674			13
(Decrease) Increase in cash and cash equivalents	(5,672		)	4,811			876
Cash and cash equivalents at beginning of period	5,690			879			3
Cash and cash equivalents at end of period	$	18		$	5,690		$	879

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)	2016		2015
ASSETS
Current assets
Cash and cash equivalents	$	18	$	5,690
Deposit with IRS	1,250		—
Accounts receivable, net
Other accounts receivable	73		272
Accounts receivable from affiliates	48		20
Notes receivable from affiliates	88		1,478
Regulatory assets	263		241
Other	—		5
Total current assets	1,740		7,706
Property, plant and equipment, net	51		53
Deferred debits and other assets
Regulatory assets	4,033		3,072
Investments in affiliates	34,869		26,119
Deferred income taxes	2,107		2,036
Non-pension postretirement benefit asset	—		108
Notes receivable from affiliates	922		933
Other	256		404
Total deferred debits and other assets	42,187		32,672
Total assets	$	43,978	$	40,431

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)	2016			2015
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings	$	—		$	188
Long-term debt due within one year	570			60
Accounts payable	2			5
Accrued expenses	489			440
Payables to affiliates	706			—
Regulatory liabilities	16			63
Pension obligations	58			52
Other	50			1
Total current liabilities	1,891			809
Long-term debt	7,193			6,017
Deferred credits and other liabilities
Regulatory liabilities	31			31
Pension obligations	8,608			7,520
Non-pension postretirement benefit obligations	7			—
Deferred income taxes	226			134
Other	182			122
Total deferred credits and other liabilities	9,054			7,807
Total liabilities	18,138			14,633
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2000 shares authorized, 924 shares and 920 shares outstanding at December 31, 2016 and 2015, respectively)	18,797			18,678
Treasury stock, at cost (35 shares at December 31, 2016 and 2015, respectively)	(2,327		)	(2,327		)
Retained earnings	12,030			12,068
Accumulated other comprehensive loss, net	(2,660		)	(2,624		)
Total shareholders’ equity	25,840			25,795
BGE preference stock not subject to mandatory redemption	—			3
Total liabilities and shareholders’ equity	$	43,978		$	40,431

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. BGE redeemed all of its outstanding preferred stock in 2016.

Mergers

On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub) and Pepco Holdings, Inc. (PHI). As a result of that merger, Merger Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (EEDC), a wholly owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO and BGE (through a special purpose subsidiary in the case of BGE). See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the PHI Merger.

Debt and Credit Agreements

Short-Term Borrowings

Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper borrowings at both December 31, 2016 and December 31, 2015.

Credit Agreements

On May 30, 2014, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank commitments of $600 million through May 2019. As of December 31, 2016, Exelon Corporation had available capacity under those commitments of $571 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, 2016 and December 31, 2015:



					Maturity Date	December 31,
	Rates				Maturity Date	2016			2015
Long-term debt
Junior subordinated notes			6.5	%	2024	$	1,150		$	1,150
Contract payment - junior subordinated notes			2.5	%	2017	19			64
Senior unsecured notes ^(a)	1.6	%	7.6	%	2017 - 2046	6,439			4,639
Total long-term debt						7,608			5,853
Unamortized debt discount and premium, net						(8		)	(4		)
Unamortized debt issuance costs						(57		)	(47		)
Fair value adjustment of consolidated subsidiary						220			275
Long-term debt due within one year						(570		)	(60		)
Long-term debt						$	7,193		$	6,017

___________


(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 2017, 2018, 2019, 2020, 2021 and thereafter are as follows:



2017	$	570
2018	—
2019	—
2020	1,450
2021	300
Remaining years	5,288
Total long-term debt	$	7,608

Commitments and Contingencies

See Note 24—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)	2016			2015			2014
Operating and maintenance from affiliates:
BSC ^(a)	$	51		$	43		$	38
Interest income from affiliates, net:
Generation	$	39		$	43		$	53
Equity in earnings (losses) of investments:
Exelon Energy Delivery Company, LLC ^(b)	$	1,041		$	1,079		$	958
PCI	6			—			—
BSC	1			—			—
Exelon Ventures Company, LLC ^(c)	—			—			926
UII, LLC	(9		)	20			(6		)
Exelon Transmission Company, LLC	(13		)	(8		)	(7		)
Exelon Enterprise	(1		)	(1		)	(1		)
Generation	496			1,371			(91		)
Total equity in earnings of investments	$	1,521		$	2,461		$	1,779

Cash contributions received from affiliates	$	1,912		$	3,209		$	1,370



	December 31,
(in millions)	2016			2015
Accounts receivable from affiliates (current):
BSC ^(a)	$	15		$	—
Generation	22			16
ComEd	3			2
PECO	1			1
BGE	1			1
PHISCO	6			—
Total accounts receivable from affiliates (current)	$	48		$	20
Notes receivable from affiliates (current):
BSC ^(a)	$	88		$	226
Generation ^(d)	—			1,252
Total notes receivable from affiliates (current):	$	88		$	1,478
Investments in affiliates:
BSC ^(a)	$	194		$	191
Exelon Energy Delivery Company, LLC ^(b)	23,003			14,163
PCI	77			—
UII, LLC	92			102
Exelon Transmission Company, LLC	5			3
Voluntary Employee Beneficiary Association trust	(5		)	7
Exelon Enterprises	21			22
Generation	11,488			11,637
Other	(6		)	(6		)
Total investments in affiliates	$	34,869		$	26,119
Notes receivable from affiliates (non-current):
Generation ^(d)	$	922		$	933
Notes payable to affiliates (current):
ComEd	$	—		$	188
Accounts payable to affiliates (current):
ComEd	$	345		$	—
UII, LLC	361			—
Total accounts payable to affiliates (current)	$	706		$	—

_____________________


(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.


(b)	Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.


(c)	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.

The entire disclosure for condensed financial information, including the financial position, cash flows, and the results of operations of the registrant (parent company) as of the same dates or for the same periods for which audited consolidated financial statements are being presented. Alternatively, the details of this disclosure can be reported by the specific parent company taxonomy elements, indicating the appropriate date and period contexts in an instance document.

Valuation and Qualifying Accounts [Abstract]

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2016

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, 2016
Allowance for uncollectible accounts ^(a)	$	284	$	162	$	99		^(b) (c)	$	211	^(d)	$	334
Deferred tax valuation allowance	13		—		10			^(b)	3			20
Reserve for obsolete materials	105		12		1			^(b)	5			113
For the year ended December 31, 2015
Allowance for uncollectible accounts ^(a)	$	311	$	113	$	27		^(c)	$	167	^(d)	$	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		^(c)	$	205	^(d)	$	311
Deferred tax valuation allowance	13		—		37				—			50
Reserve for obsolete materials	58		5		34				2			95

___________________


(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $23 million, $8 million, and $8 million for the years ended December 31, 2016, 2015, and 2014, respectively.


(b)	Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger


(c)	Includes charges for late payments and non-service receivables.


(d)	Write-off of individual accounts receivable.

Exelon Generation Company, LLC and Subsidiary Companies

Generation



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Balance Sheets at December 31, 2016 and 2015

		Consolidated Statements of Changes in Equity for the Years Ended December 31, 2016, 2015 and 2014

		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, 2016
Allowance for uncollectible accounts	$	77	$	19	$	3		$	8		$	91
Deferred tax valuation allowance	11		—		—			2			9
Reserve for obsolete materials	102		6		—			2			106
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

Commonwealth Edison Company and Subsidiary Companies

ComEd



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Balance Sheets at December 31, 2016 and 2015

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014

		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, 2016
Allowance for uncollectible accounts	$	75	$	45	$	23	^(a)	$	73	^(b)	$	70
Reserve for obsolete materials	3		4		1			4			4
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

_____________________


(a)	Primarily charges for late payments and non-service receivables.


(b)	Write-off of individual accounts receivable.

PECO Energy Company and Subsidiary Companies

PECO



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Balance Sheets at December 31, 2016 and 2015

		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2016, 2015 and 2014

		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, 2016
Allowance for uncollectible accounts ^(a)	$	83	$	32	$	7	^(b)	$	61	^(c)	$	61
Reserve for obsolete materials	1		1		—			—			2
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

_____________________


(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $23 million, $8 million, and $8 million for the years ended December 31, 2016, 2015, and 2014, respectively.


(b)	Primarily charges for late payments.


(c)	Write-off of individual accounts receivable.

Baltimore Gas and Electric Company and Subsidiary Companies

BGE



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Balance Sheets at December 31, 2016 and 2015

		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014

		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, 2016
Allowance for uncollectible accounts	$	49	$	1	$	9	^(b)	$	27	^(a)	$	32
Deferred tax valuation allowance	1		—		—			—			1
Reserve for obsolete materials	—		—		—			—			—
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			—

_____________________


(a)	Write-off of individual accounts receivable.


(b)	Primarily charges for late payments.

Pepco Holdings LLC and Subsidiary Companies

PHI



1.		Successor Company Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statement of Operations and Comprehensive Income for the Periods March 24, 2016 to December 31, 2016

		Consolidated Statement of Cash Flows for the Periods March 24, 2016 to December 31, 2016

		Consolidated Balance Sheet at December 31, 2016

		Consolidated Statement of Changes in Equity for the Periods March 24, 2016 to December 31, 2016

		Notes to Consolidated Financial Statements

		Predecessor Company Financial Statements:

		Report of Independent Registered Public Accounting Firm date February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Period January 1, 2016 to March 23, 2016 and the Years Ended December 31, 2015 and 2014

		Consolidated Statements of Cash Flows for the Period January 1, 2016 to March 23, 2016 and for the Years Ended December 31, 2015 and 2014 (Predecessor)

		Consolidated Balance Sheet at December 31, 2015

		Consolidated Statements of Changes in Equity for the Period January 1, 2016 to March 23, 2016 and for the Years Ended December 31, 2015 and 2014

		Notes to Consolidated Financial Statements

2.		Successor Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts - For the Period March 24, 2016 to December 31, 2016

		Predecessor Financial Statement Schedules:

		Schedule II – Valuation and Qualifying Accounts - For the Period January 1, 2016 to March 23, 2016 and For the Years Ended December 31, 2015 and 2014

		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto

Pepco Holdings LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C						Column D				Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts				Deductions				Balance at End of Period
	(in millions)
March 24, 2016 to December 31, 2016 (Successor)
Allowance for uncollectible accounts	$	52	$	65	$	5		^(a)	$	42		^(b)	$	80
Deferred tax valuation allowance	63		—		(53		)		—				10
Reserve for obsolete materials	—		1		—				(1		)		2

January 1, 2016 to March 23, 2016 (Predecessor)
Allowance for uncollectible accounts	$	56	$	16	$	2		^(a)	$	22		^(b)	$	52
Deferred tax valuation allowance	63		—		—				—				63
Reserve for obsolete materials	—		—		—				—				—
For the Year Ended December 31, 2015 (Predecessor)
Allowance for uncollectible accounts	$	40	$	59	$	5		^(a)	$	48		^(b)	$	56
Deferred tax valuation allowance	61		—		2				—				63
Reserve for obsolete materials	—		—		—				—				—
For the Year Ended December 31, 2014 (Predecessor)
Allowance for uncollectible accounts	$	38	$	46	$	9		^(a)	$	53		^(b)	$	40
Deferred tax valuation allowance	21		—		40				—				61
Reserve for obsolete materials	—		—		—				—				—


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Potomac Electric Power Company

Pepco



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Balance Sheets at December 31, 2016 and 2015

		Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2016, 2015 and 2014

		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

Potomac Electric Power Company

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	17	$	29	$	3	^(a)	$	20	^(b)	$	29
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		3		—			2			1
For the year ended December 31, 2015
Allowance for uncollectible accounts	$	16	$	20	$	1	^(a)	$	20	^(b)	$	17
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		—		—			—			—
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	16	$	17	$	2	^(a)	$	19	^(b)	$	16
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		—		—			—			—


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Power & Light Company

DPL



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Balance Sheets at December 31, 2016 and 2015

		Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2016, 2015 and 2014

		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

Delmarva Power & Light Company

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	17	$	23	$	2	^(a)	$	18	^(b)	$	24
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		1		—			1			—
For the year ended December 31, 2015
Allowance for uncollectible accounts	$	11	$	20	$	2	^(a)	$	16	^(b)	$	17
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		—		—			—			—
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	12	$	13	$	4	^(a)	$	18	^(b)	$	11
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		—		—			—			—


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Atlantic City Electric Company and Subsidiary Company

ACE



1.		Financial Statements:

		Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP

		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

		Consolidated Balance Sheets at December 31, 2016 and 2015

		Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2016, 2015 and 2014

		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

Atlantic City Electric Company and Subsidiary Company

Schedule II – Valuation and Qualifying Accounts



Column A	Column B		Column C					Column D			Column E
			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts			Deductions			Balance at End of Period
	(in millions)
For the year ended December 31, 2016
Allowance for uncollectible accounts	$	17	$	32	$	2	^(a)	$	24	^(b)	$	27
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		1		—			—			1
For the year ended December 31, 2015
Allowance for uncollectible accounts	$	9	$	18	$	2	^(a)	$	12	^(b)	$	17
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		—		—			—			—
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	10	$	12	$	3	^(a)	$	16	^(b)	$	9
Deferred tax valuation allowance	—		—		—			—			—
Reserve for obsolete materials	—		—		—			—			—


(a)	Primarily charges for late payments.


(b)	Write-off of individual accounts receivable.

Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2016

Accounting Policies [Abstract]

Description of Business (All Registrants)

The energy generation business includes:


•	Generation: Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing business, Constellation. Generation also sells renewable energy and other energy-related products and services. 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 electric distribution and transmission services in northern Illinois, including the City of Chicago.


•	PECO: Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas distribution services in the Pennsylvania counties surrounding the City of Philadelphia.


•	BGE: Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas distribution services in central Maryland, including the City of Baltimore.


•	Pepco: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of Columbia and major portions of Prince George's County and Montgomery County in Maryland.


•	DPL: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in northern Delaware.


•	ACE: Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in southern New Jersey.

Basis of Presentation (All Registrants)

For financial statement purposes, beginning on March 24, 2016, disclosures that had solely related to PHI, Pepco, DPL or ACE activities now also apply to Exelon, unless otherwise noted.

Use Of Estimates (All Registrants)

Use of Estimates (All Registrants)

Reclassifications (Exelon, ComEd, and BGE)

Reclassifications (All Registrants)

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

Accounting for the Effects of Regulation (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)

Revenues (All Registrants)

Income Taxes (All Registrants)

Taxes Directly Imposed on Revenue-Producing Transactions (All Registrants)

Cash and Cash Equivalents (All Registrants)

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

Restricted Cash and Cash Equivalents (All Registrants)

Allowance for Uncollectible Accounts (All Registrants)

Variable Interest Entities (All Registrants)

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 has a controlling financial interest, meaning (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.

See Note 2 — Variable Interest Entities for additional information.

Inventories (All Registrants)

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

Marketable Securities (All Registrants)

Property Plant And Equipment (All Registrants)

Property, Plant and Equipment (All Registrants)

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)

Capitalized Software Costs (All Registrants)

Depreciation, Depletion, and Amortization (All Registrants)

Depreciation, Depletion and Amortization (All Registrants)

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

Asset Retirement Obligations (All Registrants)

Capitalized Interest (All Registrants)

Capitalized Interest and AFUDC (All Registrants)

Allowance For Funds Used During Construction (Exelon, Generation, ComEd, PECO and BGE)

Guarantees (All Registrants)

Long-lived Assets (All Registrants)

Goodwill (All Registrants)

Equity Method Investments (All Registrants)

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

Direct Financing Lease Investments (Exelon, Generation, ComEd, PECO and BGE)

Derivatives Financial Instruments (All Registrants)

Derivative Financial Instruments (All Registrants)

Retirement Benefits (All Registrants)

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

Investment, Policy [Policy Text Block]

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

Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2016

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		Pepco			DPL		ACE
December 31, 2016	$	808	$	173	$	213	$	91	$	164	$	1		$	1	$	1
December 31, 2015	633		180		172		86		178		—			1		1

Amortization of capitalized software costs	Exelon		Generation		ComEd		PECO		BGE		Pepco			DPL		ACE
2016	$	255	$	72	$	62	$	33	$	44	$	—		$	—	$	—
2015	208		73		47		33		46		(2		)	—		—
2014	186		59		45		28		43		2			—		—



	Successor		Predecessor
PHI	December 31, 2016		December 31, 2015
Net unamortized software costs	$	153	$	172

	Successor		Predecessor
PHI	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015		For the Year Ended December 31, 2014
Amortization of capitalized software costs	$	29	$	8	$	36	$	30

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		Pepco		DPL		ACE
2016	Total incurred interest^(b)	$	1,678	$	472	$	469	$	127	$	114	$	137	$	52	$	65
	Capitalized interest	108		107		—		—		—		—		—		—
	Credits to AFUDC debt and equity	98		—		22		11		30		29		7		9
2015	Total incurred interest^(b)	$	1,170	$	445	$	336	$	116	$	113	$	131	$	51	$	65
	Capitalized interest	79		79		—		—		—		—		—		—
	Credits to AFUDC debt and equity	44		—		9		7		28		19		2		2
2014	Total incurred interest^(b)	$	1,144	$	419	$	323	$	115	$	118	$	121	$	49	$	65
	Capitalized interest	63		63		—		—		—		—		—		—
	Credits to AFUDC debt and equity	37		—		5		8		24		16		3		2



	Successor		Predecessor
PHI	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015		For the Year Ended December 31, 2014
Total incurred interest^(b)	$	207	$	68	$	289	$	277
Credits to AFUDC debt and equity	35		10		23		21

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2016

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities



	December 31, 2016										December 31, 2015
							Successor										Predecessor
	Exelon ^(a)(b)		Generation		BGE		PHI ^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Current assets	$	954	$	916	$	23	$	14	9		$	909	$	881	$	23	$	12	$	12
Noncurrent assets	8,563		8,525		3		35		23		8,009		8,004		3		18		18
Total assets	$	9,517	$	9,441	$	26	$	49	$	32	$	8,918	$	8,885	$	26	$	30	$	30
Current liabilities	$	885	$	802	$	42	$	42	37		$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities	2,713		2,612		—		101		89		2,927		2,884		41		124		124
Total liabilities	$	3,598	$	3,414	$	42	$	143	$	126	$	3,400	$	3,271	$	122	$	172	$	172

_______________________

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

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



December 31, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	638	$	567	$	1,205
Total liabilities^(a)	215		287		502
Exelon's ownership interest in VIE^(a)	—		248		248
Other ownership interests in VIE^(a)	423		32		455
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		264		264
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	9		—		9



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

___________________


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

(b)

As of December 31, 2016 and December 31, 2015, these assets and liabilities primarily consisted of the following:



		December 31, 2016										December 31, 2015
								Successor										Predecessor
		Exelon ^(a)(b)		Generation		BGE		PHI ^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents		$	150	$	150	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash		59		27		23		9		9		100		77		23		12		12
Accounts receivable, net
	Customer	371		371		—		—		—		219		219		—		—		—
	Other	48		48		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets		31		31		—		—		—		140		140		—		—		—
Inventory
	Materials and supplies	199		199		—		—		—		181		181		—		—		—
Other current assets		50		44		—		5		—		35		30		—		—		—
	Total current assets	908		870		23		14		9		882		854		23		12		12

Property, plant and equipment, net		5,415		5,415		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds		2,185		2,185		—		—		—		2,036		2,036		—		—		—
Goodwill		47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets		23		23		—		—		—		53		53		—		—		—
Other noncurrent assets		315		277		3		35		23		90		85		3		18		18
	Total noncurrent assets	7,985		7,947		3		35		23		7,386		7,381		3		18		18
	Total assets	$	8,893	$	8,817	$	26	$	49	$	32	$	8,268	$	8,235	$	26	$	30	$	30

Long-term debt due within one year		$	181	$	99	$	41	$	40	$	35	$	111	$	27	$	79	$	46	$	46
Accounts payable		269		269		—		—		—		216		216		—		—		—
Accrued expenses		119		116		1		2		2		115		113		2		2		2
Mark-to-market derivative liabilities		60		60		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities		15		15		—		—		—		12		12		—		—		—
Other current liabilities		30		30		—		—		—		13		13		—		—		—
	Total current liabilities	674		589		42		42		37		472		386		81		48		48

	Long-term debt	641		540		—		101		89		666		623		41		124		124
	Asset retirement obligations	1,904		1,904		—		—		—		1,999		1,999		—		—		—
	Pension obligation^(c)	9		9		—		—		—		9		9		—		—		—
	Unamortized energy contract liabilities	22		22		—		—		—		39		39		—		—		—
	Other noncurrent liabilities	106		106		—		—		—		79		79		—		—		—
	Noncurrent liabilities	2,682		2,581		—		101		89		2,792		2,749		41		124		124
	Total liabilities	$	3,356	$	3,170	$	42	$	143	$	126	$	3,264	$	3,135	$	122	$	172	$	172

___________

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

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

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

Public Utilities General Disclosures [Table Text Block]

Regulatory Matters (Tables)

12 Months Ended

Dec. 31, 2016

Regulated Operations [Abstract]

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



	ComEd									BGE
Annual Transmission Filings	2016			2015			2014			2016			2015			2014
Initial revenue requirement increase	$	90		$	68		$	36		$	12		$	—		$	9
Annual reconciliation increase (decrease)	4			18			(14		)	3			(3		)	5
Dedicated facilities increase ^(a)	—			—			—			13			13			3
Total revenue requirement increase	$	94		$	86		$	22		$	28		$	10		$	17

Allowed return on rate base ^(c)	8.47		%	8.61		%	8.62		%	8.09		%	8.46		%	8.53		%
Allowed ROE ^(d)	11.50		%	11.50		%	11.50		%	10.50		%	11.30		%	11.30		%

Effective date of rates	June 2016			June 2015			June 2014			June 2016			June 2015			June 2014



	Pepco									DPL									ACE
Annual Transmission Filings	2016			2015			2014			2016			2015			2014			2016			2015			2014
Initial revenue requirement increase (decrease)	$	2		$	10		$	(9	)	$	8		$	15		$	4		$	8		$	10		$	4
Annual reconciliation (decrease) increase	(10		)	(3		)	(1		)	(10		)	(1		)	6			(14		)	2			3
MAPP abandonment recovery (decrease) increase ^(b)	(15		)	(2		)	17			(12		)	(2		)	15			—			—			—
Total revenue requirement (decrease) increase	$	(23	)	$	5		$	7		$	(14	)	$	12		$	25		$	(6	)	$	12		$	7

Allowed return on rate base ^(c)	7.88		%	8.36		%	8.60		%	7.21		%	7.80		%	8.05		%	7.83		%	8.51		%	8.66		%
Allowed ROE^(d)	10.50		%	11.30		%	11.30		%	10.50		%	11.30		%	11.30		%	10.50		%	11.30		%	11.30		%

Effective date of rates^(e)	June 2016			June 2015			June 2014			June 2016			June 2015			June 2014			June 2016			June 2015			June 2014

____________

(a) BGE's transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE.

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



Annual Electric Distribution Filings	2016				2015				2014
ComEd's requested total revenue requirement increase (decrease)	$	138			$	(50	)		$	269

Final ICC Order
Initial revenue requirement increase	$	134			$	85			$	160
Annual reconciliation (decrease) increase	(7		)		(152		)		72
Total revenue requirement increase (decrease)	$	127		^(a)	$	(67	)		$	232

Allowed Return on Rate Base:
Initial revenue requirement	6.71		%		7.05		%		7.06		%
Annual reconciliation	6.69		%		7.02		%		7.04		%
Allowed ROE:
Initial revenue requirement	8.64		%		9.14		%		9.25		%
Annual reconciliation	8.59		%	^(b)	9.09		%	^(b)	9.20		%	^(b)

Effective date of rates	January 2017				January 2016				January 2015

__________________

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



	ComEd									BGE
Annual Transmission Filings	2016			2015			2014			2016			2015			2014
Initial revenue requirement increase	$	90		$	68		$	36		$	12		$	—		$	9
Annual reconciliation increase (decrease)	4			18			(14		)	3			(3		)	5
Dedicated facilities increase ^(a)	—			—			—			13			13			3
Total revenue requirement increase	$	94		$	86		$	22		$	28		$	10		$	17

Allowed return on rate base ^(c)	8.47		%	8.61		%	8.62		%	8.09		%	8.46		%	8.53		%
Allowed ROE ^(d)	11.50		%	11.50		%	11.50		%	10.50		%	11.30		%	11.30		%

Effective date of rates	June 2016			June 2015			June 2014			June 2016			June 2015			June 2014

Regulatory Construction Commitment

will work with PJM to continue to evaluate the scope and timing of any required construction projects. The Utility Registrant's estimated commitments are as follows:



	Total		2017		2018		2019		2020		2021
ComEd	$	97	$	64	$	28	$	5	$	—	$	—
PECO	34		14		10		7		2		1
BGE	226		113		55		44		14		—
Pepco	104		6		39		40		19		—
DPL	63		47		16		—		—		—
ACE	93		36		39		18		—		—

Schedule of Regulatory Assets



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	4,162	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	2,016		75		1,583		98		260		171		38		51
AMI programs	701		164		49		230		258		174		84		—
Under-recovered distribution service costs	188		188		—		—		—		—		—		—
Debt costs	124		42		1		7		81		17		9		6
Fair value of long-term debt	812		—		—		—		671		—		—		—
Fair value of PHI's unamortized energy contracts	1,085		—		—		—		1,085		—		—		—
Severance	5		—		—		5		—		—		—		—
Asset retirement obligations	111		76		23		12		—		—		—		—
MGP remediation costs	305		278		26		1		—		—		—		—
Under-recovered uncollectible accounts	56		56		—		—		—		—		—		—
Renewable energy	260		258		—		—		2		—		—		2
Energy and transmission programs	89		23		—		38		28		6		5		17
Deferred storm costs	36		—		—		1		35		12		5		18
Electric generation-related regulatory asset	10		—		—		10		—		—		—		—
Rate stabilization deferral	7		—		—		7		—		—		—		—
Energy efficiency and demand response programs	621		—		1		285		335		250		85		—
Merger integration costs	25		—		—		10		15		11		4		—
Under-recovered revenue decoupling	27		—		—		3		24		21		3		—
COPCO acquisition adjustment	8		—		—		—		8		—		8		—
Recoverable workers compensation and long-term disability costs	34		—		—		—		34		34		—		—
Vacation accrual	31		—		7		—		24		—		14		10
Securitized stranded costs	138		—		—		—		138		—		—		138
CAP arrearage	11		—		11		—		—		—		—		—
Removal costs	477		—		—		—		477		134		88		255
Other	49		7		9		5		29		22		5		4
Total regulatory assets	11,388		1,167		1,710		712		3,504		852		348		501
Less: current portion	1,342		190		29		208		653		162		59		96
Total noncurrent regulatory assets	$	10,046	$	977	$	1,681	$	504	$	2,851	$	690	$	289	$	405



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt	162		—		—		—		—		—		—		—
Severance	9		—		—		9		—		—		—		—
Asset retirement obligations	108		67		22		19		1		1		—		—
MGP remediation costs	286		255		30		1		—		—		—		—
Under-recovered uncollectible accounts	52		52		—		—		—		—		—		—
Renewable energy	247		247		—		—		6		—		1		5
Energy and transmission programs	84		43		1		40		33		9		11		13
Deferred storm costs	2		—		—		2		43		19		6		18
Electric generation-related regulatory asset	20		—		—		20		—		—		—		—
Rate stabilization deferral	87		—		—		87		—		—		—		—
Energy efficiency and demand response programs	279		—		1		278		401		289		111		1
Merger integration costs	6		—		—		6		—		—		—		—
Conservation voltage reduction	3		—		—		3		—		—		—		—
Under-recovered revenue decoupling	30		—		—		30		14		10		4		—
COPCO acquisition adjustment	—		—		—		—		—		—		13		—
Workers compensation and long-term disability costs	—		—		—		—		31		31		—		—
Vacation accrual	6		—		6		—		23		—		14		9
Securitized stranded costs	—		—		—		—		202		—		—		202
CAP arrearage	7		—		7		—		—		—		—		—
Removal costs	—		—		—		—		369		92		69		208
Other	29		10		13		3		32		14		9		8
Total regulatory assets	6,824		1,113		1,617		781		2,582		801		371		512
Less: current portion	759		218		34		267		305		140		72		98
Total noncurrent regulatory assets	$	6,065	$	895	$	1,583	$	514	$	2,277	$	661	$	299	$	414

Schedule of Regulatory Liabilities



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	94	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,577		2,172		405		—		—		—		—		—
Removal costs	1,527		1,332		—		195		150		21		129		—
Energy efficiency and demand response programs	92		52		40		—		1		—		—		1
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		27		16		19		8
Over-recovered revenue decoupling	1		—		—		1		—		—		—		—
Other	16		5		2		8		35		7		12		16
Total regulatory liabilities	4,570		3,614		639		222		213		44		160		25
Less: current portion	369		155		112		38		66		15		49		18
Total noncurrent regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7



									Successor
December 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory liabilities
Other postretirement benefits	$	47	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,607		2,169		438		—		—		—		—		—
Removal costs	1,601		1,324		—		141		136		18		118		—
Deferred rent	39		—		—		—		39		—		—		—
Energy efficiency and demand response programs	185		141		41		—		3		3		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	76		—		76		—		—		—		—		—
Gas distribution tax repairs	20		—		20		—		—		—		—		—
Energy and transmission programs	134		60		56		—		18		8		5		5
Other	72		4		5		19		41		2		17		20
Total regulatory liabilities	4,789		3,698		644		160		237		31		140		25
Less: current portion	602		329		127		50		79		11		43		25
Total noncurrent regulatory liabilities	$	4,187	$	3,369	$	517	$	110	$	158	$	20	$	97	$	—



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt	162		—		—		—		—		—		—		—
Severance	9		—		—		9		—		—		—		—
Asset retirement obligations	108		67		22		19		1		1		—		—
MGP remediation costs	286		255		30		1		—		—		—		—
Under-recovered uncollectible accounts	52		52		—		—		—		—		—		—
Renewable energy	247		247		—		—		6		—		1		5
Energy and transmission programs	84		43		1		40		33		9		11		13
Deferred storm costs	2		—		—		2		43		19		6		18
Electric generation-related regulatory asset	20		—		—		20		—		—		—		—
Rate stabilization deferral	87		—		—		87		—		—		—		—
Energy efficiency and demand response programs	279		—		1		278		401		289		111		1
Merger integration costs	6		—		—		6		—		—		—		—
Conservation voltage reduction	3		—		—		3		—		—		—		—
Under-recovered revenue decoupling	30		—		—		30		14		10		4		—
COPCO acquisition adjustment	—		—		—		—		—		—		13		—
Workers compensation and long-term disability costs	—		—		—		—		31		31		—		—
Vacation accrual	6		—		6		—		23		—		14		9
Securitized stranded costs	—		—		—		—		202		—		—		202
CAP arrearage	7		—		7		—		—		—		—		—
Removal costs	—		—		—		—		369		92		69		208
Other	29		10		13		3		32		14		9		8
Total regulatory assets	6,824		1,113		1,617		781		2,582		801		371		512
Less: current portion	759		218		34		267		305		140		72		98
Total noncurrent regulatory assets	$	6,065	$	895	$	1,583	$	514	$	2,277	$	661	$	299	$	414

Purchase Of Receivables

December 31, 2016 and December 31, 2015.



													Successor
As of December 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables ^(c)	$	313		$	87		$	72		$	59		$	95		$	63		$	10		$	22
Allowance for uncollectible accounts ^(a)	(37		)	(14		)	(6		)	(4		)	(13		)	(7		)	(2		)	(4		)
Purchased receivables, net	$	276		$	73		$	66		$	55		$	82		$	56		$	8		$	18

													Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL			ACE
Purchased receivables ^(b)(c)	$	229		$	103		$	67		$	59		$	100		$	70		$	11		$	19
Allowance for uncollectible accounts ^(a)	(31		)	(16		)	(7		)	(8		)	(6		)	(4		)	—			(2		)
Purchased receivables, net	$	198		$	87		$	60		$	51		$	94		$	66		$	11		$	17

_________________________

Mergers, Acquisitions and Dispositions (Tables)

12 Months Ended

Dec. 31, 2016

Dec. 31, 2014

Finite-Lived and Indefinite-Lived Intangible Assets Acquired as Part of Business Combination [Table Text Block]

Business Combination, Separately Recognized Transactions [Table Text Block]



(In millions of dollars, except per share data)	Total Consideration
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)	$	6,933
Cash paid for PHI preferred stock^(a)	180
Cash paid for PHI stock-based compensation equity awards^(b)	29
Total purchase price	$	7,142

_____________


(a)	As of December 31, 2015, the preferred stock was included in Other non-current assets on Exelon's Consolidated Balance Sheets.

(b)



	Expected Payment Period							Successor
Description	Expected Payment Period	Pepco^(a)		DPL^(a)		ACE^(a)		PHI^(a)		Exelon^(a)
Rate credits	2016 - 2017	$	91	$	67	$	101	$	259	$	259
Energy efficiency	2016 - 2021	—		—		—		—		111
Charitable contributions	2016 - 2026	28		12		10		50		50
Delivery system modernization	Q2 2016	—		—		—		—		22
Green sustainability fund	Q2 2016	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		24
Other		7		7		—		14		33
Total		$	126	$	86	$	111	$	323	$	513

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



Preliminary Purchase Price Allocation
Current assets	$	1,441
Property, plant and equipment	11,088
Regulatory assets	5,015
Other assets	248
Goodwill	4,005
Total assets	$	21,797

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,447
Pension and OPEB liabilities	821
Other liabilities	187
Total liabilities	$	14,655
Total purchase price	$	7,142



Total consideration transferred	$	257

Identifiable assets acquired and liabilities assumed
Working capital assets	$	204
Property, plant and equipment	2
Mark-to-market derivative assets	6
Unamortized energy contract assets	100
Customer relationships	9
Other assets	1
Total assets	$	322

Mark-to-market derivative liabilities	$	(65	)
Total liabilities	$	(65	)
Total net identifiable assets, at fair value	$	257

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

Business Acquisition, Pro Forma Information, Nonrecurring Adjustments [Table Text Block]



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

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

______________


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


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

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

)

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

Restructuring and Related Costs [Table Text Block]



	For the Year Ended December 31,
Acquisition, Integration and Financing Costs^(a)	2016			2015
Exelon^(b)	$	143		$	87
Generation	37			24
ComEd^(c)	(6		)	9
PECO	5			4
BGE^(c)	(1		)	5
Pepco^(c)	28			3
DPL^(c)	20			2
ACE	19			1



	Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015
PHI^(c)	$	69	$	29	$	19

______________


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


(b)	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.


(c)	For the year ended December 31, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million, $4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco^(b)		DPL^(c)		ACE
Severance benefits^(a)	$	57	$	9	$	2	$	1	$	1	$	44	$	21	$	13	$	10

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the year ended December 31, 2016.


(b)	Pepco established a regulatory asset of $11 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.


(c)	DPL established a regulatory asset of $4 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.

and 2015, the Registrants recorded the following severance costs associated with ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:




	Exelon		Generation^(a)		ComEd^(a)		PECO^(a)		BGE^(a)
Year ended December 31,
2016	$	19	$	13	$	3	$	1	$	1
2015	18		15		2		—		1



	Successor		Predecessor
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015
PHI^(a)
Severance Benefits	$	1	$	—	$	—

_______


(a)	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.

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



															Successor
Severance Liability	Exelon			Generation			ComEd			PECO		BGE			PHI^(b)			Pepco			DPL			ACE
Balance at December 31, 2014	$	50		$	34		$	2		$	—	$	2		$	—		$	1		$	—		$	—
Severance charges	16			10			2			—		—			—			—			—			—
Payments	(31		)	(21		)	(1		)	—		(1		)	—			(1		)	—			—
Balance at December 31, 2015	$	35		$	23		$	3		$	—	$	1		$	—		$	—		$	—		$	—
Severance charges^(a)	99			22			2			—		—			56			1			1			—
Payments	(46		)	(9		)	(2		)	—		(1		)	(27		)	(1		)	(1		)	—
Balance at December 31, 2016	$	88		$	36		$	3		$	—	$	—		$	29		$	—		$	—		$	—



	Predecessor
Severance Liability	PHI^(b)
Balance at December 31, 2014	$	3
Severance charges	—
Payments	(3		)
Balance at December 31, 2015	$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.


(b)	For PHI, the successor period includes activity for the period from March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year ended December 31, 2015 and the period January 1, 2016 through March 23, 2016. There was no activity in the 2016 PHI predecessor period.

, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:



	Exelon		Generation		ComEd		PECO		BGE
Severance benefits^(a)	$	23	$	18	$	3	$	1	$	1

_______


(a)	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2016.

Investment in Constellation Energy Nuclear Group, LLC (Tables)

12 Months Ended

Dec. 31, 2016

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

)

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, 2016

Receivables [Abstract]

Schedule Of Accounts Notes Loans And Financing Receivable



																		Successor
2016	Exelon			Generation				ComEd			PECO				BGE			PHI				Pepco				DPL				ACE
Unbilled customer revenues	$	1,673		$	910		^(a)	$	219		$	140			$	182		$	222			$	123			$	58			$	41
Allowance for uncollectible accounts ^(b)	(334		)	(91		)		(70		)	(61		)	^(c)	(32		)	(80		)	^(d)	(29		)	^(d)	(24		)	^(d)	(27		)	^(d)



																		Predecessor
2015	Exelon			Generation				ComEd			PECO				BGE			PHI			Pepco			DPL			ACE
Unbilled customer revenues	$	1,203		$	732		^(a)	$	218		$	105			$	148		$	177		$	93		$	45		$	39
Allowance for uncollectible accounts^(b)	(284		)	(77		)		(75		)	(83		)	^(c)	(49		)	(56		)	(17		)	(17		)	(17		)

_________________________


(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 $23 million and $8 million at December 31, 2016 and 2015, respectively, related to PECO’s current installment plan receivables described below.

(d)

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—generation	3-56	$	27,193	$	25,615
Nuclear fuel ^(a)	1-8	6,546		6,384
Construction work in progress	N/A	2,332		2,017
Other property, plant and equipment ^(b)	4	76		466
Total property, plant and equipment		36,147		34,482
Less: accumulated depreciation ^(c)		10,562		8,639
Property, plant and equipment, net		$	25,585	$	25,843

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,326 million and $1,266 million at December 31, 2016 and 2015, respectively.

(b)


(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 million and $2,861 million as of December 31, 2016 and 2015, respectively

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-80	$	22,636	$	20,576
Construction work in progress	N/A	569		572
Other property, plant and equipment ^{(a), (b)}	37-50	67		64
Total property, plant and equipment		23,272		21,212
Less: accumulated depreciation		3,937		3,710
Property, plant and equipment, net		$	19,335	$	17,502

_________________________


(a)	Includes buildings under capital lease with a net carrying value at both December 31, 2016 and 2015 of $7 million. The original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2016 and 2015.


(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, 2016 and 2015:



	Average Service life	2016			2015
Asset Category
Electric—transmission and distribution	5-68	$	3,574		$	3,431
Gas—distribution	5-75	580			547
Common—electric and gas	4-40	115			108
Construction work in progress	N/A	163			107
Other property, plant and equipment ^(a)	10-43	16			16
Total property, plant and equipment		4,448			4,209
Less: accumulated depreciation		1,175		—	1,139
Property, plant and equipment, net		$	3,273		$	3,070

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016			2015
Asset Category
Electric—transmission and distribution	5-86	$	8,018		$	7,682
Construction work in progress	N/A	537			318
Other property, plant and equipment^(a)	10-33	66			91
Total property, plant and equipment		8,621			8,091
Less: accumulated depreciation		3,050		—	2,929
Property, plant and equipment, net		$	5,571		$	5,162

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-65	$	7,591	$	7,230
Gas—transportation and distribution	5-70	2,348		2,206
Common—electric and gas	5-50	670		631
Construction work in progress	N/A	188		154
Other property, plant and equipment ^(a)	50	21		21
Total property, plant and equipment		10,818		10,242
Less: accumulated depreciation		3,253		3,101
Property, plant and equipment, net		$	7,565	$	7,141

_________________________


(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, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-90	$	45,698	$	32,546
Electric—generation	3-56	27,193		25,615
Gas—transportation and distribution	5-90	4,642		3,864
Common—electric and gas	4-50	1,312		1,149
Nuclear fuel ^(a)	1-8	6,546		6,384
Construction work in progress	N/A	4,306		3,075
Other property, plant and equipment ^(b)	3-50	1,027		1,181
Total property, plant and equipment		90,724		73,814
Less: accumulated depreciation ^(c)		19,169		16,375
Property, plant and equipment, net		$	71,555	$	57,439

_________________________


(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,326 million and $1,266 million at December 31, 2016 and 2015, respectively.

(b)


(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $3,186 million and $2,861 million as of December 31, 2016 and 2015, respectively

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016			2015
Asset Category
Electric—transmission and distribution	5-55	$	3,341		$	3,105
Construction work in progress	N/A	169			158
Other property, plant and equipment ^(a)	13-15	27			28
Total property, plant and equipment		3,537			3,291
Less: accumulated depreciation		1,016		—	969
Property, plant and equipment, net		$	2,521		$	2,322

_______________________


(a)

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



		Successor			Predecessor
	Average Service Life (years)	2016			2015
Asset Category
Electric—transmission and distribution	5-86	$	10,315		$	14,563
Gas—distribution	5-75	414			547
Common—electric and gas	4-40	65			164
Construction work in progress	N/A	892			591
Other property, plant and equipment ^(a)	3-43	107			339
Total property, plant and equipment		11,793			16,204
Less: accumulated depreciation		195		—	5,340
Property, plant and equipment, net		$	11,598		$	10,864

_______________________


(a)	Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.

The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:



	Average Service Life (years)	2016		2015
Asset Category
Electric—transmission and distribution	5-90	$	7,067	$	6,663
Gas—distribution	5-90	2,170		1,951
Common—electric and gas	5-40	707		655
Construction work in progress	N/A	318		312
Other property, plant and equipment ^(a)	20	32		32
Total property, plant and equipment		10,294		9,613
Less: accumulated depreciation		3,254		3,016
Property, plant and equipment, net		$	7,040	$	6,597

_______________________


(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	2016		2015		2014
Electric—transmission and distribution	2.32	%	2.39	%	2.55	%
Gas	1.82	%	1.87	%	1.84	%
Common—electric and gas	5.11	%	5.16	%	5.16	%

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	2016		2015		2014
Electric—transmission and distribution	2.49	%	2.44	%	2.41	%
Gas	2.57	%	2.55	%	2.48	%
Common—electric and gas	4.99	%	4.24	%	4.08	%

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	2016		2015		2014
Electric—transmission and distribution	2.56	%	2.62	%	2.96	%
Gas	2.45	%	2.50	%	2.47	%
Common—electric and gas	9.45	%	10.35	%	9.49	%

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	2016		2015		2014
Electric—transmission and distribution	2.52	%	2.48	%	2.42	%
Gas	2.57	%	2.55	%	2.48	%
Common—electric and gas	8.12	%	5.19	%	4.55	%

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	2016			2015		2014
Electric—transmission and distribution	2.73	%		2.83	%	2.93	%
Electric—generation	5.94	%	^(a)	3.47	%	3.50	%
Gas	2.17	%		2.17	%	2.13	%
Common—electric and gas	7.41	%		7.79	%	7.32	%

Impairment of Long-Lived assets (Tables)	12 Months Ended
Impairment of Long-Lived assets (Tables)	Dec. 31, 2016
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Schedule of Capital Leased Assets	As of December 31, 2016, all the long-term leases had been terminated and no residual and net investment value was outstanding. At December 31, 2015, the components of the net investment in the long-term leases consisted of estimated residual value of $639 million, unearned income of $287 million and a resulting net investment of $352 million.

Early Nuclear Plant Retirements Early Nuclear Plant Retirements (Tables)

12 Months Ended

Dec. 31, 2016

Implications of Potential Early Plant Retirements [Abstract]

Implications of Potential Early Plant Retirement [Table Text Block] [Table Text Block]



(in millions)	TMI
Asset Balances
Materials and supplies inventory	$	39
Nuclear fuel inventory, net	83
Completed plant, net	1,015
Construction work in progress	37

Liability Balances
Asset retirement obligation	(565		)

NRC License Renewal Term	2034

Jointly Owned Electric Utility Plant (Tables)

12 Months Ended

Dec. 31, 2016

Public Utilities, Property, Plant and Equipment [Abstract]

Schedule of Jointly Owned Utility Plants

Exelon's, Generation's, PECO's, BGE's, PHI's and ACE's undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2016 and 2015 were as follows:



	Nuclear Generation												Fossil Fuel Generation			Transmission				Other
	Quad Cities			Peach Bottom			Salem^(a)			Nine Mile Point Unit 2			Wyman			PA^(b)		NJ/ DE^(c)		Other^(d)
Operator	Generation			Generation			PSEG Nuclear			Generation			FP&L			First Energy		PSEG/ DPL		various
Ownership interest	75.00		%	50.00		%	42.59		%	82.00		%	5.89		%	various		various		various
Exelon’s share at December 31, 2016:
Plant^(e)	$	1,054		$	1,384		$	596		$	830		$	3		$	27	$	97	$	15
Accumulated depreciation^(e)	515			407			186			68			3			15		52		13
Construction work in progress	—			16			41			37			—			—		—		—
Exelon’s share at December 31, 2015:
Plant^(e)	$	1,035		$	1,345		$	566		$	756		$	3		$	27	$	93	$	15
Accumulated depreciation^(e)	309			368			167			42			3			15		52		13
Construction work in progress	11			18			40			56			—			—		—		—

________________________


(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, 2016 and 2015.


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


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


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


(e)	Excludes asset retirement costs.

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2016

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule Of Goodwill



	Balance at January 1, 2015		Impairment losses		Balance at December 31, 2015		Goodwill from business combination		Impairment losses		Measurement period adjustments^(b)			Balance at December 31, 2016
Exelon
Gross amount	$	4,655	$	—	$	4,655	$	4,016	$	—	$	(11	)	$	8,660
Accumulated impairment loss	1,983		—		1,983		—		—		—			1,983
Carrying amount	2,672		—		2,672		4,016		—		(11		)	6,677
Generation
Gross amount	47		—		47		—		—		—			47
Carrying amount	47		—		47		—		—		—			47
ComEd^(a)
Gross amount	4,608		—		4,608		—		—		—			4,608
Accumulated impairment loss	1,983		—		1,983		—		—		—			1,983
Carrying amount	2,625		—		2,625		—		—		—			2,625
DPL
Gross amount	8		—		8		—		—		—			8
Carrying amount	8		—		8		—		—		—			8



March 24, 2016 to December 31, 2016	Beginning Balance		Goodwill from business combination		Impairment losses			Measurement period adjustments^(b)			Ending Balance
PHI - Successor
Gross amount	$	—	$	4,016	$	—		$	(11	)	$	4,005
Accumulated impairment loss	—		—		—			—			—
Carrying amount	—		4,016		—			(11		)	4,005

January 1, 2016 to March 23, 2016
PHI - Predecessor
Gross amount	1,418		—		—			—			1,418
Accumulated impairment loss	12		—		—			—			12
Carrying amount	1,406		—		—			—			1,406

For the Year Ended December 31, 2015
PHI - Predecessor
Gross amount	1,425		—		(7		)	—			1,418
Accumulated impairment loss	18		—		(6		)	—			12
Carrying amount	1,407		—		(1		)	—			1,406

______________________


(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 ^(l)										Estimated amortization expense
		Gross			Accumulated Amortization			Net			2017			2018			2019			2020			2021
Exelon
Software License Agreement ^(a)	10.0	$	95		$	(15	)	$	80		$	10		$	10		$	10		$	10		$	10
Generation
Unamortized Energy Contracts ^(b)
Exelon Wind ^(c)	18.0	224			(83		)	141			14			14			14			10			10
Antelope Valley^(d)	25	190			(28		)	162			8			8			8			8			8
Constellation ^(e)	1.5	1,499			(1,440		)	59			(21		)	11			8			10			10
CENG ^(f)	1.7	(97		)	59			(38		)	(15		)	(18		)	(15		)	(8		)	(4		)
Integrys ^(g)	2.4	5			(3		)	2			1			1			—			—			—
ConEdison ^(h)	1.5	100			(53		)	47			37			7			2			1			—
Service Contract Backlog
PES ^(h)	1.0	9			(7		)	2			2			—			—			—			—
Customer Relationships ⁽ⁱ⁾
Constellation ^(e)	12.4	214			(94		)	120			18			18			17			17			17
Integrys ^(g)	10.0	50			(11		)	39			5			5			5			5			5
PES ^(h)	15.0	12			(1		)	11			1			1			1			1			1
ConEdison ^(h)	10.0	9			—			9			1			1			1			1			1
Trade Names
Constellation ^(e)	10.0	243			(125		)	118			23			23			23			23			23
ComEd
Chicago settlement—1999 agreement ^(j)	21.8	100			(86		)	14			3			3			3			3			—
Chicago settlement—2003 agreement ^(k)	17.9	62			(47		)	15			4			4			4			4			—
PHI
Unamortized Energy Contracts^(h)	6.8	(1,515		)	430			(1,085		)	(335		)	(189		)	(119		)	(115		)	(92		)
Pepco
DC Sponsorship Agreement ^(m)	0	25			—			25			—			—			—			—			—

Total		$	1,225		$	(1,504	)	$	(279	)	$	(244	)	$	(101	)	$	(38	)	$	(30	)	$	(11	)

_________________________


(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 735 MWs 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 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)	On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc.


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


(i)	Excludes $11 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 2017 to 2021.

(j)

(k)


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


(m)	In the third quarter of 2015, Pepco entered into a sponsorship agreement with the District of Columbia for future naming rights associated with public property within the District of Columbia to be determined over time through future negotiations. Amortization of the intangible asset will begin once the terms of the naming rights are defined.

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, 2016, 2015 and 2014:




For the Year Ended December 31,	Exelon ^(a)		Generation ^(a)		ComEd
2016	$	87	$	79	$	7
2015	76		69		7
2014	179		179		7

________________________

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2016

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Text Block]

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2016 and 2015:



																			Successor
	Generation															ComEd			PHI ^(c)						Exelon
For the year ended December 31, 2016	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(a)			Life Insurance Contracts			Eliminated in Consolidation			Total
Balance as of January 1, 2016	$	670		$	22		$	1,051			$	33	$	1,776		$	(247	)	$	—		$	—		$	1,529
Included due to merger	—			—			—				—		—			—			20			—			20
Total realized / unrealized gains (losses)
Included in net income	7			—			(568		)	^(b)	1		(560		)	—			3			—			(557		)
Included in noncurrent payables to affiliates	16			—			—				—		16			—			—			(16		)	—
Included in regulatory assets/liabilities	—			—			—				—		—			(11		)	—			16			5
Change in collateral	—			—			(141		)		—		(141		)	—			—			—			(141		)
Purchases, sales, issuances and settlements																			—
Purchases	143			2			342			^(d)	7		494			—			—			—			494
Sales	(1		)	(5		)	(9		)		—		(15		)	—			—			—			(15		)
Issuances	—			—			—				—		—			—			(3		)	—			(3		)
Settlements	(144		)	—			—				—		(144		)	—			—			—			(144		)
Transfers into Level 3	—			—			1				1		2			—			—			—			2
Transfers out of Level 3	(14		)	—			(183		)		—		(197		)	—			—			—			(197		)
Balance as of December 31, 2016	$	677		$	19		$	493			$	42	$	1,231		$	(258	)	$	20		$	—		$	993
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2016	$	5		$	—		$	109			$	—	$	114		$	—		$	2		$	—		$	116




	Generation																ComEd						Exelon
For the year ended December 31, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives ^(d)				Other Investments			Total Generation			Mark-to-Market Derivatives^(a)			Eliminated in Consolidation			Total
Balance as of January 1, 2015	$	605		$	50		$	1,050			$	3		$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income	4			—			22			^(b)	1			27			—			—			27
Included in noncurrent payables to affiliates	18			—			—				—			18			—			(18		)	—
Included in payable for Zion Station decommissioning	—			(2		)	—				—			(2		)	—			—			(2		)
Included in regulatory assets/liabilities	—			—			—				—			—			(40		)	18			(22		)
Change in collateral	—			—			29				—			29			—			—			29
Purchases, sales, issuances and settlements
Purchases	146			2			144				30			322			—			—			322
Sales	(8		)	(28		)	(25		)		—			(61		)	—			—			(61		)
Settlements	(95		)	—			—				—			(95		)	—			—			(95		)
Transfers into Level 3	4			—			80				—			84			—			—			84
Transfers out of Level 3	(4		)	—			(249		)		(1		)	(254		)	—			—			(254		)
Balance as of December 31, 2015	$	670		$	22		$	1,051			$	33		$	1,776		$	(247	)	$	—		$	1,529
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, 2015	$	2		$	—		$	856			$	—		$	858		$	—		$	—		$	858

_________________________

(a)


(b)	Includes a reduction for the reclassification of $677 million and $834 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2016 and 2015, respectively.


(c)	Successor period represents activity from March 24, 2016 to December 31, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco and DPL for the year ended December 31, 2016.


(d)	Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.



	Successor			Predecessor
	March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016					December 31, 2015
PHI	Life Insurance Contracts			Preferred Stock			Life Insurance Contracts		Preferred Stock		Life Insurance Contracts
Beginning Balance	$	20		$	18		$	19	$	3	$	19
Total realized / unrealized gains (losses)
Included in net income	3			(18		)	1		15		5
Purchases, sales, issuances and settlements
Issuances	(3		)	—			—		—		(3		)
Settlements	—			—			—		—		(2		)
Ending Balance	$	20		$	—		$	20	$	18	$	19
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	2		$	—		$	1	$	15	$	3



	December 31, 2016					December 31, 2015
	Pepco			DPL		Pepco			DPL
	Life Insurance Contracts			Life Insurance Contracts		Life Insurance Contracts			Life Insurance Contracts
Balance as of December 31	$	19		$	—	$	18		$	1
Total realized / unrealized gains (losses)
Included in net income	3			—		5			—
Purchases, sales, issuances and settlements
Issuances	(3		)	—		(3		)	—
Settlements	—			—		(1		)	(1		)
Balance as of December 31	$	19		$	—	$	19		$	—
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period	$	3		$	—	$	3		$	—

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of December 31, 2016	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	20	$	—		$	—		$	20		$	45	$	—		$	—	$	45		$	36	$	—		$	—	$	36
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			4		—			—		4
Total assets	20		—			—			20			52		10			—		62			40		—			—		40
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities ^(b)	—		—			(258		)	(258		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(258		)	(266		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	20	$	(8	)	$	(258	)	$	(246	)	$	52	$	(1	)	$	—	$	51		$	40	$	(4	)	$	—	$	36



	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 ^(a)	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			4		—			—		4
Life insurance contracts	—		—			—			—			—		12			—		12			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		12			—		20			4		—			—		4
Total assets	29		—			—			29			279		12			—		291			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	$	—		$	—	$	279		$	29	$	(4	)	$	—	$	25

_________________________

(a)


(b)	The Level 3 balance consists of the current and noncurrent liability of $19 million and $239 million, respectively, at December 31, 2016, and $23 million and $224 million, respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.



	Generation										Exelon
As of December 31, 2016	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling			Total
Assets
Cash equivalents ^(a)	$	39	$	—	$	—	$	—	$	39	$	373	$	—	$	—	$	—		$	373
NDT fund investments
Cash equivalents ^(b)	110		19		—		—		129		110		19		—		—			129
Equities	3,551		452		—		2,011		6,014		3,551		452		—		2,011			6,014
Fixed income
Corporate debt	—		1,554		250		—		1,804		—		1,554		250		—			1,804
U.S. Treasury and agencies	1,291		29		—		—		1,320		1,291		29		—		—			1,320
Foreign governments	—		37		—		—		37		—		37		—		—			37
State and municipal debt	—		264		—		—		264		—		264		—		—			264
Other ^(c)	—		59		—		493		552		—		59		—		493		—	552
Fixed income subtotal	1,291		1,943		250		493		3,977		1,291		1,943		250		493			3,977
Middle market lending	—		—		427		71		498		—		—		427		71			498
Private equity	—		—		—		148		148		—		—		—		148			148
Real estate	—		—		—		326		326		—		—		—		326			326
NDT fund investments subtotal ^(d)	4,952		2,414		677		3,049		11,092		4,952		2,414		677		3,049			11,092
Pledged assets for Zion Station decommissioning
Cash equivalents	11		—		—		—		11		11		—		—		—			11
Equities	—		2		—		—		2		—		2		—		—			2
Fixed Income - U.S. Treasury and agencies	16		1		—		—		17		16		1		—		—			17
Middle market lending	—		—		19		64		83		—		—		19		64			83
Pledged assets for Zion Station decommissioning subtotal ^(e)	27		3		19		64		113		27		3		19		64			113
Rabbi trust investments
Cash equivalents	2		—		—		—		2		74		—		—		—			74
Mutual funds	19		—		—		—		19		50		—		—		—			50



	Generation														Exelon
As of December 31, 2016	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Fixed income	—			—			—			—		—			—			16			—			—		16
Life insurance contracts	—			18			—			—		18			—			64			20			—		84
Rabbi trust investments subtotal	21			18			—			—		39			124			80			20			—		224
Commodity derivative assets
Economic hedges	1,356			2,505			1,229			—		5,090			1,358			2,505			1,229			—		5,092
Proprietary trading	3			50			23			—		76			3			50			23			—		76
Effect of netting and allocation of collateral ^(f)	(1,162		)	(2,142		)	(481		)	—		(3,785		)	(1,164		)	(2,142		)	(481		)	—		(3,787		)
Commodity derivative assets subtotal	197			413			771			—		1,381			197			413			771			—		1,381
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			16			—			—		16
Economic hedges	—			28			—			—		28			—			28			—			—		28
Proprietary trading	3			2			—			—		5			3			2			—			—		5
Effect of netting and allocation of collateral	(2		)	(19		)	—			—		(21		)	(2		)	(19		)	—			—		(21		)
Interest rate and foreign currency derivative assets subtotal	1			11			—			—		12			1			27			—			—		28
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,237			2,859			1,509			3,113		12,718			5,674			2,937			1,529			3,113		13,253
Liabilities
Commodity derivative liabilities
Economic hedges	(1,267		)	(2,378		)	(794		)	—		(4,439		)	(1,267		)	(2,378		)	(1,052		)	—		(4,697		)
Proprietary trading	(3		)	(50		)	(26		)	—		(79		)	(3		)	(50		)	(26		)	—		(79		)
Effect of netting and allocation of collateral ^(f)	1,233			2,339			542			—		4,114			1,233			2,339			542			—		4,114
Commodity derivative liabilities subtotal	(37		)	(89		)	(278		)	—		(404		)	(37		)	(89		)	(536		)	—		(662		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(10		)	—			—		(10		)	—			(10		)	—			—		(10		)
Economic hedges	—			(21		)	—			—		(21		)	—			(21		)	—			—		(21		)
Proprietary trading	(4		)	—			—			—		(4		)	(4		)	—			—			—		(4		)
Effect of netting and allocation of collateral	4			19			—			—		23			4			19			—			—		23
Interest rate and foreign currency derivative liabilities subtotal	—			(12		)	—			—		(12		)	—			(12		)	—			—		(12		)
Deferred compensation obligation	—			(34		)	—			—		(34		)	—			(136		)	—					(136		)
Total liabilities	(37		)	(135		)	(278		)	—		(450		)	(37		)	(237		)	(536		)	—		(810		)
Total net assets	$	5,200		$	2,724		$	1,231		$	3,113	$	12,268		$	5,637		$	2,700		$	993		$	3,113	$	12,443



	Generation										Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents ^(a)	$	104	$	—	$	—	$	—	$	104	$	5,766	$	—	$	—	$	—	$	5,766
NDT fund investments
Cash equivalents ^(b)	219		92		—		—		311		219		92		—		—		311
Equities	3,008		—		—		1,894		4,902		3,008		—		—		1,894		4,902



	Generation									Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
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)	—		147		—		390	537		—		147		—		390	537
Fixed income subtotal	1,323		2,373		242		390	4,328		1,323		2,373		242		390	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		2,465		670		2,660	10,345		4,550		2,465		670		2,660	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	—		—		22		105	127		—		—		22		105	127
Pledged assets for Zion Station decommissioning subtotal ^(e)	7		71		22		105	205		7		71		22		105	205
Rabbi trust investments
Mutual funds	17		—		—		—	17		48		—		—		—	48
Life insurance contracts	—		13		—		—	13		—		36		—		—	36
Rabbi trust investments subtotal	17		13		—		—	30		48		36		—		—	84
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 ^(f)	(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		3,473		1,898		2,765	12,815		10,372		3,521		1,898		2,765	18,556
Liabilities
Commodity derivative liabilities



	Generation														Exelon
As of December 31, 2015	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
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 ^(f)	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
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		$	3,208		$	1,776		$	2,765	$	12,453		$	10,397		$	3,187		$	1,529		$	2,765	$	17,878

_________________________

(a)


(b)	Includes $29 million and $52 million of cash received from outstanding repurchase agreements at December 31, 2016 and 2015, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

(d)


(e)	Excludes net assets of less than $1 million and $1 million at December 31, 2016 and 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)

PHI, Pepco, DPL and ACE



	Successor											Predecessor
	As of December 31, 2016											As of December 31, 2015
PHI	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	217		$	—		$	—	$	217		$	42		$	—		$	—	$	42
Mark-to-market derivative assets ^(b)(c)	2			—			—		2			—			—			18		18
Effect of netting and allocation of collateral	(2		)	—			—		(2		)	—			—			—		—
Mark-to-market derivative assets subtotal	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			16			—		16			—			15			—		15
Life insurance contracts	—			22			20		42			—			27			19		46
Rabbi trust investments subtotal	73			38			20		131			12			42			19		73
Total assets	290			38			20		348			54			42			37		133
Liabilities
Deferred compensation obligation	—			(28		)	—		(28		)	—			(30		)	—		(30		)
Mark-to-market derivative liabilities ^(b)	—			—			—		—			(2		)	—			—		(2		)
Effect of netting and allocation of collateral	—			—			—		—			2			—			—		2
Mark-to-market derivative liabilities subtotal	—			—			—		—			—			—			—		—
Total liabilities	—			(28		)	—		(28		)	—			(30		)	—		(30		)
Total net assets	$	290		$	10		$	20	$	320		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of December 31, 2016	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents ^(a)	$	33	$	—		$	—	$	33		$	42		$	—		$	—	$	42		$	130	$	—	$	—	$	130
Mark-to-market derivative assets ^(b)	—		—			—		—			2			—			—		2			—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		16			—		16			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			19		41			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		38			19		100			—			—			—		—			—		—		—		—
Total assets	76		38			19		133			42			—			—		42			130		—		—		130
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	76	$	33		$	19	$	128		$	42		$	(1	)	$	—	$	41		$	130	$	—	$	—	$	130



	Pepco										DPL											ACE
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 ^(a)	$	2	$	—		$	—	$	2		$	—		$	—		$	—	$	—		$	30	$	—	$	—	$	30
Rabbi trust investments
Cash equivalents	11		—			—		11			—			—			—		—			—		—		—		—
Fixed income	—		15			—		15			—			—			—		—			—		—		—		—
Life insurance contracts	—		23			19		42			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	11		38			19		68			—			—			—		—			—		—		—		—
Total assets	13		38			19		70			—			—			—		—			30		—		—		30
Liabilities
Deferred compensation obligation	—		(6		)	—		(6		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities ^(b)	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			2			—			—		2			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(6		)	—		(6		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	13	$	32		$	19	$	64		$	—		$	(1	)	$	—	$	(1	)	$	30	$	—	$	—	$	30

_______

(a)


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


(c)	Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 19 - Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.

Fair value of financial liabilities recorded at the carrying amount

Exelon



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,267	$	—	$	1,267	$	—	$	1,267
Long-term debt (including amounts due within one year) ^(a)	34,005		1,113		31,741		1,959		34,813
Long-term debt to financing trusts ^(b)	641		—		—		667		667
SNF obligation	1,024		—		732		—		732



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

Generation



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	699	$	—	$	699	$	—	$	699
Long-term debt (including amounts due within one year) ^(a)	9,241		—		7,482		1,670		9,152
SNF obligation	1,024		—		732		—		732



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

ComEd



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	7,033	$	—	$	7,585	$	—	$	7,585
Long-term debt to financing trusts ^(b)	205		—		—		215		215



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

PECO



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	2,580	$	—	$	2,794	$	—	$	2,794
Long-term debt to financing trusts	184		—		—		192		192



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

BGE



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	45	$	—	$	45	$	—	$	45
Long-term debt (including amounts due within one year) ^(a)	2,322		—		2,467		—		2,467
Long-term debt to financing trusts ^(b)	252		—		—		260		260



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

PHI



	December 31, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	522	$	—	$	522	$	—	$	522
Long-term debt (including amounts due within one year) ^(a)	5,898		—		5,520		289		5,809



	December 31, 2015
	Carrying Amount		Fair Value
Predecessor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	958	$	—	$	958	$	—	$	958
Long-term debt (including amounts due within one year) ^(a)	5,279		—		5,231		586		5,817
Preferred stock	183		—		—		183		183

Pepco



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	23	$	—	$	23	$	—	$	23
Long-term debt (including amounts due within one year) ^(a)	2,349		—		2,788		8		2,796



	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	64	$	—	$	64	$	—	$	64
Long-term debt (including amounts due within one year) ^(a)	2,351		—		2,673		—		2,673

DPL



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	1,340	$	—	$	1,383	$	—	$	1,383



	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	105	$	—	$	105	$	—	$	105
Long-term debt (including amounts due within one year) ^(a)	1,265		—		1,185		103		1,288

ACE



	December 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year) ^(a)	$	1,155	$	—	$	1,007	$	280	$	1,287



	December 31, 2015
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	5	$	—	$	5	$	—	$	5
Long-term debt (including amounts due within one year) ^(a)	1,201		—		1,044		280		1,324

________

(a)


(b)	Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million and $6 million for Exelon, ComEd and BGE, respectively, as of December 31, 2016 and December 31, 2015.

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

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of December 31, 2016	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	20	$	—		$	—		$	20		$	45	$	—		$	—	$	45		$	36	$	—		$	—	$	36
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts	—		—			—			—			—		10			—		10			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		10			—		17			4		—			—		4
Total assets	20		—			—			20			52		10			—		62			40		—			—		40
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities ^(b)	—		—			(258		)	(258		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(258		)	(266		)	—		(11		)	—		(11		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	20	$	(8	)	$	(258	)	$	(246	)	$	52	$	(1	)	$	—	$	51		$	40	$	(4	)	$	—	$	36



	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 ^(a)	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			4		—			—		4
Life insurance contracts	—		—			—			—			—		12			—		12			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		12			—		20			4		—			—		4
Total assets	29		—			—			29			279		12			—		291			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	$	—		$	—	$	279		$	29	$	(4	)	$	—	$	25

_________________________

(a)


(b)	The Level 3 balance consists of the current and noncurrent liability of $19 million and $239 million, respectively, at December 31, 2016, and $23 million and $224 million, respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.



	Generation										Exelon
As of December 31, 2016	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling			Total
Assets
Cash equivalents ^(a)	$	39	$	—	$	—	$	—	$	39	$	373	$	—	$	—	$	—		$	373
NDT fund investments
Cash equivalents ^(b)	110		19		—		—		129		110		19		—		—			129
Equities	3,551		452		—		2,011		6,014		3,551		452		—		2,011			6,014
Fixed income
Corporate debt	—		1,554		250		—		1,804		—		1,554		250		—			1,804
U.S. Treasury and agencies	1,291		29		—		—		1,320		1,291		29		—		—			1,320
Foreign governments	—		37		—		—		37		—		37		—		—			37
State and municipal debt	—		264		—		—		264		—		264		—		—			264
Other ^(c)	—		59		—		493		552		—		59		—		493		—	552
Fixed income subtotal	1,291		1,943		250		493		3,977		1,291		1,943		250		493			3,977
Middle market lending	—		—		427		71		498		—		—		427		71			498
Private equity	—		—		—		148		148		—		—		—		148			148
Real estate	—		—		—		326		326		—		—		—		326			326
NDT fund investments subtotal ^(d)	4,952		2,414		677		3,049		11,092		4,952		2,414		677		3,049			11,092
Pledged assets for Zion Station decommissioning
Cash equivalents	11		—		—		—		11		11		—		—		—			11
Equities	—		2		—		—		2		—		2		—		—			2
Fixed Income - U.S. Treasury and agencies	16		1		—		—		17		16		1		—		—			17
Middle market lending	—		—		19		64		83		—		—		19		64			83
Pledged assets for Zion Station decommissioning subtotal ^(e)	27		3		19		64		113		27		3		19		64			113
Rabbi trust investments
Cash equivalents	2		—		—		—		2		74		—		—		—			74
Mutual funds	19		—		—		—		19		50		—		—		—			50



	Generation														Exelon
As of December 31, 2016	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Fixed income	—			—			—			—		—			—			16			—			—		16
Life insurance contracts	—			18			—			—		18			—			64			20			—		84
Rabbi trust investments subtotal	21			18			—			—		39			124			80			20			—		224
Commodity derivative assets
Economic hedges	1,356			2,505			1,229			—		5,090			1,358			2,505			1,229			—		5,092
Proprietary trading	3			50			23			—		76			3			50			23			—		76
Effect of netting and allocation of collateral ^(f)	(1,162		)	(2,142		)	(481		)	—		(3,785		)	(1,164		)	(2,142		)	(481		)	—		(3,787		)
Commodity derivative assets subtotal	197			413			771			—		1,381			197			413			771			—		1,381
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			16			—			—		16
Economic hedges	—			28			—			—		28			—			28			—			—		28
Proprietary trading	3			2			—			—		5			3			2			—			—		5
Effect of netting and allocation of collateral	(2		)	(19		)	—			—		(21		)	(2		)	(19		)	—			—		(21		)
Interest rate and foreign currency derivative assets subtotal	1			11			—			—		12			1			27			—			—		28
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,237			2,859			1,509			3,113		12,718			5,674			2,937			1,529			3,113		13,253
Liabilities
Commodity derivative liabilities
Economic hedges	(1,267		)	(2,378		)	(794		)	—		(4,439		)	(1,267		)	(2,378		)	(1,052		)	—		(4,697		)
Proprietary trading	(3		)	(50		)	(26		)	—		(79		)	(3		)	(50		)	(26		)	—		(79		)
Effect of netting and allocation of collateral ^(f)	1,233			2,339			542			—		4,114			1,233			2,339			542			—		4,114
Commodity derivative liabilities subtotal	(37		)	(89		)	(278		)	—		(404		)	(37		)	(89		)	(536		)	—		(662		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(10		)	—			—		(10		)	—			(10		)	—			—		(10		)
Economic hedges	—			(21		)	—			—		(21		)	—			(21		)	—			—		(21		)
Proprietary trading	(4		)	—			—			—		(4		)	(4		)	—			—			—		(4		)
Effect of netting and allocation of collateral	4			19			—			—		23			4			19			—			—		23
Interest rate and foreign currency derivative liabilities subtotal	—			(12		)	—			—		(12		)	—			(12		)	—			—		(12		)
Deferred compensation obligation	—			(34		)	—			—		(34		)	—			(136		)	—					(136		)
Total liabilities	(37		)	(135		)	(278		)	—		(450		)	(37		)	(237		)	(536		)	—		(810		)
Total net assets	$	5,200		$	2,724		$	1,231		$	3,113	$	12,268		$	5,637		$	2,700		$	993		$	3,113	$	12,443



	Generation										Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents ^(a)	$	104	$	—	$	—	$	—	$	104	$	5,766	$	—	$	—	$	—	$	5,766
NDT fund investments
Cash equivalents ^(b)	219		92		—		—		311		219		92		—		—		311
Equities	3,008		—		—		1,894		4,902		3,008		—		—		1,894		4,902



	Generation									Exelon
As of December 31, 2015	Level 1		Level 2		Level 3		Not subject to leveling	Total		Level 1		Level 2		Level 3		Not subject to leveling	Total
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)	—		147		—		390	537		—		147		—		390	537
Fixed income subtotal	1,323		2,373		242		390	4,328		1,323		2,373		242		390	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		2,465		670		2,660	10,345		4,550		2,465		670		2,660	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	—		—		22		105	127		—		—		22		105	127
Pledged assets for Zion Station decommissioning subtotal ^(e)	7		71		22		105	205		7		71		22		105	205
Rabbi trust investments
Mutual funds	17		—		—		—	17		48		—		—		—	48
Life insurance contracts	—		13		—		—	13		—		36		—		—	36
Rabbi trust investments subtotal	17		13		—		—	30		48		36		—		—	84
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 ^(f)	(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		3,473		1,898		2,765	12,815		10,372		3,521		1,898		2,765	18,556
Liabilities
Commodity derivative liabilities



	Generation														Exelon
As of December 31, 2015	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
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 ^(f)	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
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		$	3,208		$	1,776		$	2,765	$	12,453		$	10,397		$	3,187		$	1,529		$	2,765	$	17,878

_________________________

(a)


(b)	Includes $29 million and $52 million of cash received from outstanding repurchase agreements at December 31, 2016 and 2015, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.

(c)

(d)


(e)	Excludes net assets of less than $1 million and $1 million at December 31, 2016 and 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)

PHI, Pepco, DPL and ACE



	Successor											Predecessor
	As of December 31, 2016											As of December 31, 2015
PHI	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents ^(a)	$	217		$	—		$	—	$	217		$	42		$	—		$	—	$	42
Mark-to-market derivative assets ^(b)(c)	2			—			—		2			—			—			18		18
Effect of netting and allocation of collateral	(2		)	—			—		(2		)	—			—			—		—
Mark-to-market derivative assets subtotal	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			16			—		16			—			15			—		15
Life insurance contracts	—			22			20		42			—			27			19		46
Rabbi trust investments subtotal	73			38			20		131			12			42			19		73
Total assets	290			38			20		348			54			42			37		133
Liabilities
Deferred compensation obligation	—			(28		)	—		(28		)	—			(30		)	—		(30		)
Mark-to-market derivative liabilities ^(b)	—			—			—		—			(2		)	—			—		(2		)
Effect of netting and allocation of collateral	—			—			—		—			2			—			—		2
Mark-to-market derivative liabilities subtotal	—			—			—		—			—			—			—		—
Total liabilities	—			(28		)	—		(28		)	—			(30		)	—		(30		)
Total net assets	$	290		$	10		$	20	$	320		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of December 31, 2016	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents ^(a)	$	33	$	—		$	—	$	33		$	42		$	—		$	—	$	42		$	130	$	—	$	—	$	130
Mark-to-market derivative assets ^(b)	—		—			—		—			2			—			—		2			—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		16			—		16			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			19		41			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		38			19		100			—			—			—		—			—		—		—		—
Total assets	76		38			19		133			42			—			—		42			130		—		—		130
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	76	$	33		$	19	$	128		$	42		$	(1	)	$	—	$	41		$	130	$	—	$	—	$	130



	Pepco										DPL											ACE
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 ^(a)	$	2	$	—		$	—	$	2		$	—		$	—		$	—	$	—		$	30	$	—	$	—	$	30
Rabbi trust investments
Cash equivalents	11		—			—		11			—			—			—		—			—		—		—		—
Fixed income	—		15			—		15			—			—			—		—			—		—		—		—
Life insurance contracts	—		23			19		42			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	11		38			19		68			—			—			—		—			—		—		—		—
Total assets	13		38			19		70			—			—			—		—			30		—		—		30
Liabilities
Deferred compensation obligation	—		(6		)	—		(6		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities ^(b)	—		—			—		—			(2		)	—			—		(2		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			2			—			—		2			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(6		)	—		(6		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	13	$	32		$	19	$	64		$	—		$	(1	)	$	—	$	(1	)	$	30	$	—	$	—	$	30

_______

(a)


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


(c)	Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 19 - Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.

Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis



	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, 2016	$	(477	)	$	(91	)	$	7	$	(477	)	$	(91	)	$	10
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2016	$	154		$	(45	)	$	5	$	154		$	(45	)	$	7



	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	)	$	2	$	858	$	(2	)	$	2



	Successor		Predecessor
	PHI		PHI					Pepco
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016			December 31, 2015		December 31, 2016		December 31, 2015
	Other, net		Other, net					Other, net
Total (losses) gains included in net income	$	3	$	(17	)	$	20	$	3	$	5
Change in the unrealized gains (losses) relating to assets and liabilities held	2		1			18		3		3

________________________


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

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, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Exelon and Generation) ^(a)(c)	$	435		Discounted Cash Flow	Forward power price	$11	-	$130
					Forward gas price	$1.72	-	$9.20
				Option Model	Volatility percentage	8%	-	173%

Mark-to-market derivatives—Proprietary trading (Exelon and Generation) ^(a)(c)	$	(3	)	Discounted Cash Flow	Forward power price	$19	-	$79

Mark-to-market derivatives (Exelon and ComEd)	$	(258	)	Discounted Cash Flow	Forward heat rate ^(b)	8x	-	9x
					Marketability reserve	3%	-	8%
					Renewable factor	89%	-	121%

_________________________


(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 $61 million as of December 31, 2016.



Type of trade	Fair Value at December 31, 2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives—Economic hedges (Exelon and Generation) ^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11	-	$88
					Forward gas price	$1.18	-	$8.95
				Option Model	Volatility percentage	5%	-	152%

Mark-to-market derivatives— Proprietary trading (Exelon and Generation) ^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13	-	$78

Mark-to-market derivatives (Exelon and 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

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016:



	Generation															Exelon Corporate		Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments		Total
Mark-to-market derivative assets (current assets)	$	—		$	17		$	4		$	(13	)	$	8		$	—	$	8
Mark-to-market derivative assets (noncurrent assets)	—			11			1			(8		)	4			16		20
Total mark-to-market derivative assets	—			28			5			(21		)	12			16		28
Mark-to-market derivative liabilities (current liabilities)	(7		)	(13		)	(2		)	14			(8		)	—		(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(3		)	(8		)	(2		)	9			(4		)	—		(4		)
Total mark-to-market derivative liabilities	(10		)	(21		)	(4		)	23			(12		)	—		(12		)
Total mark-to-market derivative net assets (liabilities)	$	(10	)	$	7		$	1		$	2		$	—		$	16	$	16

_________________________

(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, 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		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 derivative fair value balances recorded by the Registrants as of December 31, 2016:



																							Successor
	Generation												ComEd			DPL							PHI		Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)		Collateral and Netting^(a)			Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	3,623		$	55		$	(2,769	)	$	909		$	—		$	2	$	(2	)	$	—	$	—	$	909
Mark-to-market derivative assets (noncurrent assets)	1,467			21			(1,016		)	472			—			—		—			—		—		472
Total mark-to-market derivative assets	5,090			76			(3,785		)	1,381			—			2		(2		)	—		—		1,381
Mark-to-market derivative liabilities (current liabilities)	(3,165		)	(54		)	2,964			(255		)	(19		)	—		—			—		—		(274		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,274		)	(25		)	1,150			(149		)	(239		)	—		—			—		—		(388		)
Total mark-to-market derivative liabilities	(4,439		)	(79		)	4,114			(404		)	(258		)	—		—			—		—		(662		)
Total mark-to-market derivative net assets (liabilities)	$	651		$	(3	)	$	329		$	977		$	(258	)	$	2	$	(2	)	$	—	$	—	$	719

______________________

(a)


(b)	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.


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


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

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2015:



																												Predecessor
	Generation												ComEd			Exelon			DPL							PHI Corporate		PHI
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Total Derivatives			Economic Hedges^(e)			Collateral and Netting^(a)		Subtotal		Other^(d)		Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,236		$	108		$	(3,994	)	$	1,350		$	—		$	1,350		$	—		$	—	$	—	$	18	$	18
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			—			—		—		18		18
Mark-to-market derivative liabilities (current liabilities)	(4,907		)	(94		)	4,827			(174		)	(23		)	(197		)	(2		)	2		—		—		—
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		)	(2		)	2		—		—		—
Total mark-to-market derivative net assets (liabilities)	$	516		$	3		$	1,234		$	1,753		$	(247	)	$	1,506		$	(2	)	$	2	$	—	$	18	$	18

______________________

(a)

Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit 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.


(d)	Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31, 2015. See Note 19 - Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23, 2016.


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

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	2016			2015			2014			2016		2015		2014
	Income Statement Location	Gain (Loss) on Swaps									Gain (Loss) on Borrowings
Generation	Interest expense^(a)	$	—		$	(1	)	$	(16	)	$	—	$	—	$	2
Exelon	Interest expense	$	(9	)	$	3		$	14		$	23	$	14	$	(1	)

______________________


(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

The tables below provide the activity of OCI related to cash flow hedges for the years ended December 31, 2016 and 2015, 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 OCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
For the Year Ended December 31, 2016	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
AOCI derivative loss at December 31, 2015		$	(21	)		$	(19	)
Effective portion of changes in fair value		(6		)		(6		)
Reclassifications from AOCI to net income	Interest expense	8			^(a)	8			^(a)
AOCI derivative loss at December 31, 2016		$	(19	)		$	(17	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
For the Year Ended December 31, 2015	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2014		$	(18	)		$	(28	)
Effective portion of changes in fair value		(8		)		(12		)
Reclassifications from AOCI to net income	Other, net	—				16			^(b)
Reclassifications from AOCI to net income	Interest Expense	7			^(c)	7			^(c)
Reclassifications from AOCI to net income	Operating Revenues	(2		)		(2		)
Accumulated OCI derivative loss at December 31, 2015		$	(21	)		$	(19	)

_______________________


(a)	Amount is net of related income tax expense of $5 million for the year ended December 31, 2016.


(b)	Amount is net of related income tax expense 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.



	For the Years Ended December 31,
	2016			2015			2014
Change in fair value of commodity positions	$	23		$	8		$	(1	)
Reclassification to realized at settlement of commodity positions	(21		)	(14		)	(29		)
Net commodity mark-to-market gains (losses)	2			(6		)	(30		)
Change in fair value of treasury positions	(1		)	8			1
Reclassification to realized at settlement of treasury positions	—			(10		)	3
Net treasury mark-to market gains (losses)	(1		)	(2		)	4
Net mark-to market gains (losses)	$	1		$	(8	)	$	(26	)



	Generation								Exelon
Year Ended December 31, 2016	Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	5		$	208	$	213		$	213
Reclassification to realized at settlement of commodity positions	(495		)	251		(244		)	(244		)
Net commodity mark-to-market gains (losses)	(490		)	459		(31		)	(31		)
Change in fair value of treasury positions	(2		)	—		(2		)	(2		)
Reclassification to realized at settlement of treasury positions	(8		)	—		(8		)	(8		)
Net treasury mark-to-market gains (losses)	(10		)	—		(10		)	(10		)
Net mark-to-market gains (losses)	$	(500	)	$	459	$	(41	)	$	(41	)



	Generation									Exelon Corporate		Exelon
Year Ended December 31, 2015	Operating Revenues			Purchased Power and Fuel			Total			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												Exelon Corporate			Exelon
Year Ended December 31, 2014	Operating Revenues			Purchased Power and Fuel			Interest Expense			Total			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	)

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



	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2016			2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(960	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	627			684
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(333	)	$	(248	)

__________________________


(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.

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. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $14 million, $33 million $26 million, $44 million, $16 million and $9 million as of December 31, 2016, respectively.



Rating as of December 31, 2016	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	$	995	$	—	$	995	1	$	328
Non-investment grade	118		16		102		—	—
No external ratings
Internally rated — investment grade	352		1		351		—	—
Internally rated — non-investment grade	72		8		64		—	—
Total	$	1,537	$	25	$	1,512	1	$	328



Net Credit Exposure by Type of Counterparty	December 31, 2016
Financial institutions	$	116
Investor-owned utilities, marketers, power producers	689
Energy cooperatives and municipalities	636
Other	71
Total	$	1,512

______________________


(a)	As of December 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $9 million of cash and $16 million of letters of credit.

Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2016

Debt Disclosure [Abstract]

Schedule of Short-term Debt



Exelon
	2016			2015			2014
Average borrowings	$	1,125		$	499		$	571
Maximum borrowings outstanding	3,076			739			1,164
Average interest rates, computed on a daily basis	0.88		%	0.53		%	0.32		%
Average interest rates, at December 31	1.12		%	0.88		%	0.53		%
Generation
	2016			2015			2014
Average borrowings	$	536		$	1		$	93
Maximum borrowings outstanding	1,735			50			552
Average interest rates, computed on a daily basis	0.94		%	0.49		%	0.32		%
Average interest rates, at December 31	1.14		%	n.a.			n.a.



ComEd
	2016			2015			2014
Average borrowings	$	256		$	461		$	415
Maximum borrowings outstanding	755			684			597
Average interest rates, computed on a daily basis	0.77		%	0.53		%	0.33		%
Average interest rates, at December 31	n.a.			0.89		%	0.50		%
BGE
	2016			2015			2014
Average borrowings	$	143		$	37		$	64
Maximum borrowings outstanding	369			210			180
Average interest rates, computed on a daily basis	0.77		%	0.48		%	0.29		%
Average interest rates, computed at December 31	0.95		%	0.87		%	0.61		%
PHI
	Successor			Predecessor
	2016			2015			2014
Average borrowings	$	153		$	444		$	153
Maximum borrowings outstanding	559			784			369
Average interest rates, computed on a daily basis	1.03		%	0.90		%	0.56		%
Average interest rates, computed at December 31	n.a.			1.22		%	0.78		%
Pepco
	2016			2015			2014
Average borrowings	$	4		$	34		$	37
Maximum borrowings outstanding	73			190			209



Average interest rates, computed on a daily basis	0.71		%	0.44		%	0.28		%
Average interest rates, computed at December 31	0.90		%	0.68		%	0.46		%
DPL
	2016			2015			2014
Average borrowings	$	33		$	81		$	69
Maximum borrowings outstanding	116			179			177
Average interest rates, computed on a daily basis	0.68		%	0.47		%	0.26		%
Average interest rates, computed at December 31	n.a.			0.79		%	0.42		%
ACE
	2016			2015			2014
Average borrowings	$	—		$	175		$	112
Maximum borrowings outstanding	5			253			259
Average interest rates, computed on a daily basis	0.65		%	0.46		%	0.27		%
Average interest rates, computed at December 31	n.a.			0.65		%	0.52		%

December 31, 2016 and December 31, 2015:



	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	2016 (a)(b)		2015 (a)(b)		2016		2015		2016		2015
Exelon Corporate	$	600	$	500	$	—	$	—	0.70	%	n.a.
Generation	5,300		5,450		620		—		0.94	%	0.49	%
ComEd	1,000		1,000		—		294		0.77	%	0.53	%
PECO	600		600		—		—		n.a		n.a.
BGE	600		600		45		210		0.77	%	0.48	%
PHI Corporate	—		875		—		484		1.03	%	0.80	%
Pepco	500		500		23		64		0.71	%	0.44	%
DPL	500		500		—		105		0.68	%	0.47	%
ACE	350		350		—		5		0.65	%	0.46	%
Total	$	9,450	$	10,375	$	688	$	1,162

_____________________


(a)	Excludes $500 million and $275 million in bilateral credit facilities that do not back Generation's commercial paper program at December 31, 2016 and 2015, respectively.

(b)

Schedule of Line of Credit Facilities

The adders for the prime based borrowings and LIBOR-based borrowings are presented in the following table:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Prime based borrowings	27.5	27.5	7.5	0.0	0.0	7.5	7.5	7.5
LIBOR-based borrowings	127.5	127.5	107.5	90.0	100.0	107.5	107.5	107.5

At December 31, 2016, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit facilities:



								Available Capacity at December 31, 2016
Borrower	Facility Type	Aggregate Bank Commitment ^(a)(b)		Facility Draws		Outstanding Letters of Credit^(c)		Actual		To Support Additional Commercial Paper ^(d)
Exelon Corporate	Syndicated Revolver	$	600	$	—	$	29	$	571	$	571
Generation	Syndicated Revolver	5,300		—		1,170		4,130		3,510
Generation	Bilaterals	500		75		306		119		—
ComEd	Syndicated Revolver	1,000		—		2		998		998
PECO	Syndicated Revolver	600		—		2		598		598
BGE	Syndicated Revolver	600		—		—		600		555
Pepco	Syndicated Revolver	300		—		—		300		277
DPL	Syndicated Revolver	300		—		—		300		300
ACE	Syndicated Revolver	300		—		1		299		299
Total		$	9,500	$	75	$	1,510	$	7,915	$	7,108

_______________________

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

(b)


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


(d)	Excludes $500 million in bilateral credit facilities that do not back Generation’s commercial paper program.

Schedule Of Credit Agreement Covenants

The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2016:

Exelon

Generation

ComEd

PECO

BGE

Pepco

DPL

ACE

Credit agreement threshold

2.50 to 1

3.00 to 1

2.00 to 1

At December 31, 2016, the interest coverage ratios at the Registrants were as follows:



	Exelon	Generation	ComEd	PECO	BGE	Pepco	DPL	ACE
Interest coverage ratio	7.03	11.81	6.89	8.77	10.47	6.24	8.42	5.84

Schedule of Long-term Debt Instruments

ACE



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds^(a)	3.38	%	-	7.75	%	2018 - 2036	$	1,038		$	1,039
Transition bonds ^(b)	5.05	%	-	5.55	%	2020 - 2023	124			171
Total long-term debt							1,162			1,210
Unamortized debt discount and premium, net							(1		)	(1		)
Unamortized debt issuance costs							(6		)	(8		)
Long-term debt due within one year							(35		)	(48		)
Long-term debt							$	1,120		$	1,153

___________________


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


(b)	Maturities of ACE's Transition Bonds outstanding at December 31, 2016 are $35 million in 2017, $31 million in 2018, $18 million in 2019, $19 million in 2020 and $21 million in 2021.

PECO



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds ^(a)	1.70	%	-	5.95	%	2018 - 2044	$	2,600		$	2,600
Total long-term debt							2,600			2,600
Unamortized debt discount and premium, net							(5		)	(5		)
Unamortized debt issuance costs							(15		)	(15		)
Long-term debt due within one year							—			(300		)
Long-term debt							$	2,580		$	2,280
Long-term debt to financing trusts ^(b)
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)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

ComEd



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds ^(a)	2.15	%	-	6.45	%	2017 - 2046	$	6,954		$	6,419
Notes payable and other^(b)	6.95	%	-	7.49	%	2018 - 2053	147			148
Total long-term debt							7,101			6,567
Unamortized debt discount and premium, net							(22		)	(20		)
Unamortized debt issuance costs							(46		)	(38		)
Long-term debt due within one year							(425		)	(665		)
Long-term debt							$	6,608		$	5,844
Long-term debt to financing trust ^(c)
Subordinated debentures to ComEd Financing III				6.35	%	2033	$	206		$	206
Total long-term debt to financing trusts							206			206
Unamortized debt issuance costs							(1		)	(1		)
Long-term debt to financing trusts							$	205		$	205

______________________


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


(b)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2016 and 2015, respectively. Lease payments of less than $1 million will be made from 2017 through expiration at 2053.


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

BGE



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
Rate stabilization bonds	5.82	%	-	5.82	%	2017	$	41		$	120
Senior unsecured notes	2.40	%	-	6.35	%	2021 - 2046	2,300			1,750
Total long-term debt							2,341			1,870
Unamortized debt discount and premium, net							(4		)	(3		)
Unamortized debt issuance costs							(15		)	(9		)
Long-term debt due within one year							(41		)	(378		)
Long-term debt							$	2,281		$	1,480
Long-term debt to financing trusts ^(a)
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							(6		)	(6		)
Long-term debt to financing trusts							$	252		$	252

___________________


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

DPL



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds^(a)	3.50	%	-	4.15	%	2023 - 2045	$	1,196		$	1,121
Unsecured Tax-Exempt Bonds				5.40	%	2031	112			112
Medium-Terms Notes (unsecured)	6.81	%	-	7.72	%	2017 - 2027	40			40
Total long-term debt							1,348			1,273
Unamortized debt discount and premium, net							2			2
Unamortized debt issuance costs							(10		)	(10		)
Long-term debt due within one year							(119		)	(204		)
Long-term debt							$	1,221		$	1,061

Generation



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
Senior unsecured notes	2.00	%	-	7.60	%	2017 - 2042	$	5,971		$	5,971
Pollution control notes	2.50	%	-	2.70	%	2025 - 2036	435			435
Nuclear fuel procurement contracts	3.15	%	-	3.35	%	2018 - 2020	105			127
Notes payable and other ^(a)(b)	1.43	%	-	7.83	%	2017 - 2035	382			166
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%	2031 - 2037	1,400			1,162
Variable rates	3.18	%	-	5.00	%	2019 - 2021	915			1,058
Total long-term debt							9,208			8,919
Fair value adjustment							115			127
Unamortized debt discount and premium, net							(17		)	(17		)
Unamortized debt issuance costs							(65		)	(70		)
Long-term debt due within one year							(1,117		)	(90		)
Long-term debt							$	8,124		$	8,869

______________________


(a)	Includes Generation’s capital lease obligations of $22 million and $21 million at December 31, 2016 and 2015, respectively. Generation will make lease payments of $5 million, $5 million, $6 million and $5 million and $1 million in 2017, 2018, 2019, 2020 and 2021 respectively.

PHI



							Successor			Predecessor
						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
Notes (unsecured)	6.13	%	-	7.45	%	2017 - 2032	$	266		$	456
First mortgage bonds	3.05	%	-	7.90	%	2018 - 2045	4,569			4,495
Unsecured Tax-Exempt Bonds				5.40	%	2031	112			112
Medium-Terms Notes (unsecured)	6.81	%	-	7.72	%	2017 - 2027	40			40
Transition bonds^(a)	5.05	%	-	5.55	%	2020 - 2023	124			171
Notes payable and other^(b)	6.20	%	-	8.88	%	2019 - 2021	46			57
Total long-term debt							5,157			5,331
Unamortized debt discount and premium, net							1			(2		)
Unamortized debt issuance costs							(2		)	(50		)
Fair value adjustment							742			—
Long-term debt due within one year							(253		)	(456		)
Long-term debt							$	5,645		$	4,823

________________


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

Pepco



						Maturity Date	December 31,
	Rates					Maturity Date	2016			2015
Long-term debt
First mortgage bonds^(a)	3.05	%	-	7.90	%	2022 - 2043	$	2,335		$	2,335
Notes payable and other^(b)	6.20	%	-	8.88	%	2019 - 2021	46			50
Total long-term debt							2,381			2,385
Unamortized debt discount and premium, net							(2		)	(3		)
Unamortized debt issuance costs							(30		)	(31		)
Long-term debt due within one year							(16		)	(11		)
Long-term debt							$	2,333		$	2,340

The following tables present the outstanding long-term debt at the Registrants as of December 31, 2016 and 2015:

Exelon



							Maturity Date	December 31,
	Rates						Maturity Date	2016			2015
Long-term debt
Rate stabilization bonds	5.82	%	-	5.82	%		2017	$	41		$	120
First mortgage bonds ^(a)	1.70	%	-	7.90	%		2017 - 2046	14,123			9,019
Senior unsecured notes	1.55	%	-	7.60	%		2017 - 2046	11,868			9,803
Unsecured bonds	2.40	%	-	6.35	%		2021 - 2046	2,300			1,750
Pollution control notes	2.50	%	-	2.70	%		2025 - 2036	435			435
Nuclear fuel procurement contracts	3.15	%	-	3.35	%		2018 - 2020	105			127
Notes payable and other ^(b)(c)	1.43	%	-	7.83	%		2017 - 2053	576			314
Junior subordinated notes				6.50	%		2024	1,150			1,150
Contract payment - junior subordinated notes				2.50	%		2017	19			64
Long-term software licensing agreement				3.95	%		2024	103			111
Unsecured Tax-Exempt Bonds				5.40	%	—	2031	112			—
Medium-Terms Notes (unsecured)	6.81	%	-	7.72	%	—	2017 - 2027	40			—
Transition bonds	5.05	%	-	5.55	%	—	2020 - 2023	124			—
Nonrecourse debt:
Fixed rates	2.29	%	-	6.00	%		2031 - 2037	1,400			1,162
Variable rates	3.18	%	-	5.00	%		2019 - 2021	915			1,058
Total long-term debt								33,311			25,113
Unamortized debt discount and premium, net								(68		)	(63		)
Unamortized debt issuance costs								(200		)	(180		)
Fair value adjustment								962			275
Long-term debt due within one year								(2,430		)	(1,500		)
Long-term debt								$	31,575		$	23,645
Long-term debt to financing trusts ^(d)
Subordinated debentures to ComEd Financing III				6.35	%		2033	$	206		$	206
Subordinated debentures to PECO Trust III				7.38	%		2028	81			81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103			103
Subordinated debentures to BGE Capital Trust II				6.20	%		2043	258			258
Total long-term debt to financing trusts								648			648
Unamortized debt issuance costs								(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, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.


(b)	Includes capital lease obligations of $69 million and $29 million at December 31, 2016 and 2015, respectively. Lease payments of $17 million, $18 million, $20 million, $5 million, $1 million, and $8 million will be made in 2017, 2018, 2019, 2020, 2021 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, 2016, $198 million was outstanding.


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

Schedule of Maturities of Long-term Debt

Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2017 through 2021 and thereafter are as follows:



Year	Exelon			Generation		ComEd			PECO			BGE			PHI		Pepco		DPL		ACE
2017	$	2,430		$	1,117	$	425		$	—		$	41		253		16		119		35
2018	1,742			104		840			500			—			298		13		4		281
2019	1,060			606		300			—			—			154		124		12		18
2020	3,331			1,912		500			—			—			19		—		—		19
2021	2,400			888		350			300			300			262		2		—		260
Thereafter	22,996		^(a)	4,581		4,892		^(b)	1,984		^(c)	2,258		^(d)	4,171		2,226		1,213		549
Total	$	33,959		$	9,208	$	7,307		$	2,784		$	2,599		$	5,157	$	2,381	$	1,348	$	1,162

____________________


(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
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-Name Accounting Standards Codification
-Topic 210
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-Section S99
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-Subparagraph (SX 210.5-02.22)
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 505
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
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-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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-Name Accounting Standards Codification
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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
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Schedule of Components of Income Tax Expense (Benefit)

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2016

Income Tax Disclosure [Abstract]

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



																								Successor			Predecessor
	For the Year Ended December 31, 2016																							March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO		BGE			Pepco			DPL			ACE			PHI			PHI
Included in operations:
Federal
Current	$	60		$	513		$	(135	)	$	63	$	51		$	(118	)	$	(88	)	$	(26	)	$	(281	)	$	—
Deferred	607			(247		)	379			72		88			136			97			22			283			10
Investment tax credit amortization	(24		)	(20		)	(2		)	—		(1		)	—			—			—			(1		)	—
State
Current	39			45			(4		)	9		5			7			1			—			(11		)	—
Deferred	79			(1		)	63			5		31			16			12			—			13			7
Total	$	761		$	290		$	301		$	149	$	174		$	41		$	22		$	(4	)	$	3		$	17



	For the Year Ended December 31, 2015
																									Predecessor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Included in operations:
Federal
Current	$	407		$	546		$	(80	)	$	64		$	25		$	(54	)	$	(27	)	$	(2	)	$	12
Deferred	566			16			310			69			126			126			73			27			103
Investment tax credit amortization	(22		)	(19		)	(2		)	—			(1		)	—			—			—			(1		)
State
Current	(86		)	(90		)	7			(10		)	—			6			2			3			17
Deferred	208			49			45			20			39			24			1			5			32
Total	$	1,073		$	502		$	280		$	143		$	189		$	102		$	49		$	33		$	163

	For the Year Ended December 31, 2014
																									Predecessor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Included in operations:
Federal
Current	$	121		$	360		$	(171	)	$	28		$	24		$	(79	)	$	(45	)	$	(6	)	$	(153	)
Deferred	576			(35		)	395			87			90			150			98			31			261
Investment tax credit amortization	(20		)	(16		)	(2		)	—			(1		)	—			(1		)	(1		)	(1		)
State
Current	42			35			7			(2		)	—			(2		)	—			(1		)	(10		)
Deferred	(53		)	(137		)	39			1			27			24			13			7			41
Total	$	666		$	207		$	268		$	114		$	140		$	93		$	65		$	30		$	138

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



Net interest receivable (payable) as of	Exelon			Generation		ComEd			PECO		BGE			Pepco		DPL		ACE
December 31, 2016	$	(507	)	$	46	$	(384	)	$	8	$	(1	)	$	1	$	—	$	1
December 31, 2015	(288		)	80		(210		)	3		(1		)	20		3		24



Net penalties receivable (payable) as of	Exelon			Generation		ComEd			PECO		BGE		Pepco		DPL		ACE
December 31, 2016	$	(106	)	$	—	$	(86	)	$	—	$	—	$	—	$	—	$	—
December 31, 2015	—			—		—			—		—		—		—		—



	Successor		Predecessor
PHI	December 31, 2016		December 31, 2015
Net interest receivable (payable)	$	2	$	(34	)
Net penalties receivable (payable)	—		—

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:



																	Successor		Predecessor
	For the Year Ended December 31, 2016																March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL ^(a)		ACE ^(a)		PHI ^(a)		PHI
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit ^(b)	3.3		3.3		5.6		1.3		5.0		15.7		52.7		6.2		5.8		11.9
Qualified nuclear decommissioning trust fund loss	3.4		7.8		—		—		—		—		—		—		—		—
Domestic production activities deduction	—		—		—		—		—		—		—		—		—		—
Health care reform legislation	—		—		—		—		—		—		—		—		—		—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2	)	(2.3	)	(0.3	)	(0.1	)	(0.1	)	(0.2	)	(3.7	)	0.8		1.4		(0.9	)
Plant basis differences	(4.8	)	—		(0.6	)	(9.6	)	(2.7	)	(22.8	)	(25.5	)	10.3		39.0		(13.5	)
Production tax credits and other credits	(3.6	)	(8.2	)	—		—		—		—		—		—		—		—
Noncontrolling interests	(0.2	)	(0.3	)	—		—		—		—		—		—		—		—
Statute of limitations expiration	(0.4	)	(1.7	)	—		—		—		—		—		—		—		—
Penalties	1.9		—		4.5		—		—		—		—		—		(0.7	)	—
Merger Expenses	5.5		1.1		—		—		—		23.5		112.9		(44.9	)	(89.0	)	11.1
Other ^(c)	(0.6	)	(1.5	)	0.1		(1.2	)	—		(1.8	)	(2.2	)	1.3		3.3		3.6
Effective income tax rate	38.3	%	33.2	%	44.3	%	25.4	%	37.2	%	49.4	%	169.2	%	8.7	%	(5.2	)%	47.2	%



	For the Year Ended December 31, 2015
																	Predecessor
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.7		1.0		4.9		1.0		5.3		6.7		1.7		5.7		6.6
Qualified nuclear decommissioning trust fund income	(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	)	(0.1	)	(0.4	)	(0.6	)	(0.2	)
Plant basis differences	(1.5	)	—		(0.1	)	(8.7	)	(0.7	)	(5.8	)	(2.3	)	(1.3	)	(4.3	)
Production tax credits and other credits	(1.9	)	(3.4	)	—		—		—		—		—		—		—
Noncontrolling interests	0.3		0.5		—		—		—		—		—		—		—
Statute of limitations expiration	(1.4	)	(2.4	)	—		—		—		—		—		—		—
Other ^(d)	—		—		0.2		0.2		—		(0.5	)	5.2		6.4		(3.2	)
Effective income tax rate	32.2	%	27.1	%	39.7	%	27.4	%	39.6	%	35.3	%	39.2	%	45.2	%	33.9	%

	For the Year Ended December 31, 2014
																	Predecessor
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
U.S. Federal statutory rate	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%	35.0	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	1.3		(1.9	)	4.5		(0.1	)	5.0		5.4		4.8		5.8		5.3
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	)	(0.1	)	(0.3	)	(0.6	)	(0.3	)
Plant basis differences	(1.9	)	—		(0.1	)	(10.4	)	0.2		(4.9	)	(2.4	)	(0.5	)	(4.5	)
Production tax credits and other credits	(2.4	)	(4.8	)	—		—		—		—		—		—		—
Noncontrolling interests	(1.8	)	(3.7	)	—		—		—		—		—		—		—
Statute of limitations expiration	(2.6	)	(5.3	)	—		—		—		—		—		—		—
Other	(0.2	)	(1.1	)	0.3		0.1		(0.2	)	(0.2	)	1.4		(0.2	)	0.8
Effective income tax rate	26.8	%	16.9	%	39.6	%	24.5	%	39.9	%	35.2	%	38.5	%	39.5	%	36.3	%

_____________________

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


(c)	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.

(d) Includes impacts of the PHI Global Settlement for Pepco, DPL, ACE, and PHI

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, 2016 and 2015 are presented below:



	As of December 31, 2016
																									Successor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Plant basis differences	$	(17,966	)	$	(4,192	)	$	(5,034	)	$	(3,095	)	$	(1,977	)	$	(1,678	)	$	(973	)	$	(869	)	$	(3,586	)
Accrual based contracts	434			(115		)	—			—			—			—			—			—			548
Derivatives and other financial instruments	(179		)	(162		)	(3		)	—			—			—			—			—			(1		)
Deferred pension and postretirement obligation	2,287			(316		)	(453		)	(18		)	(43		)	(122		)	(74		)	(21		)	(111		)
Nuclear decommissioning activities	(509		)	(509		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	325			44			(13		)	(1		)	(3		)	(7		)	(4		)	(2		)	293
Regulatory assets and liabilities	(3,319		)	—			(226		)	10			(240		)	(194		)	(75		)	(69		)	(1,205		)
Tax loss carryforward	189			61			29			—			22			27			39			14			77
Tax credit carryforward	446			493			—			—			—			—			—			—			—
Investment in CENG	(650		)	(650		)	—			—			—			—			—			—			—
Other, net	1,485			403			351			99			27			66			34			34			225
Deferred income tax liabilities (net)	$	(17,457	)	$	(4,943	)	$	(5,349	)	$	(3,005	)	$	(2,214	)	$	(1,908	)	$	(1,053	)	$	(913	)	$	(3,760	)
Unamortized investment tax credits	(658		)	(626		)	(15		)	(1		)	(5		)	(2		)	(3		)	(4		)	(9		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(18,115	)	$	(5,569	)	$	(5,364	)	$	(3,006	)	$	(2,219	)	$	(1,910	)	$	(1,056	)	$	(917	)	$	(3,769	)



	As of December 31, 2015
																									Predecessor
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Plant basis differences	$	(13,393	)	$	(4,269	)	$	(4,424	)	$	(2,901	)	$	(1,821	)	$	(1,599	)	$	(915	)	$	(791	)	$	(3,342	)
Accrual based contracts	(136		)	(136		)	—			—			—			—			—			—			—
Derivatives and other financial instruments	(203		)	(181		)	(4		)	—			—			—			—			—			(1		)
Deferred pension and postretirement obligation	1,801			(371		)	(505		)	(9		)	(47		)	(95		)	(82		)	(20		)	(92		)
Nuclear decommissioning activities	(592		)	(592		)	—			—			—			—			—			—			—
Deferred debt refinancing costs	133			48			(15		)	(1		)	(4		)	(8		)	(4		)	(3		)	(15		)
Regulatory assets and liabilities	(1,706		)	—			(219		)	16			(264		)	(202		)	(91		)	(93		)	(414		)
Tax loss carryforward	103			56			—			—			33			141			122			8			378
Tax credit carryforward	327			374			—			—			—			—			—			—			6
Investment in CENG	(595		)	(595		)	—			—			—			—			—			—			—
Other, net	1,112			425			270			105			27			42			29			18			103
Deferred income tax liabilities (net)	$	(13,149	)	$	(5,241	)	$	(4,897	)	$	(2,790	)	$	(2,076	)	$	(1,721	)	$	(941	)	$	(881	)	$	(3,377	)
Unamortized investment tax credits	(622		)	(598		)	(17		)	(2		)	(5		)	(2		)	(4		)	(4		)	(15		)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$	(13,771	)	$	(5,839	)	$	(4,914	)	$	(2,792	)	$	(2,081	)	$	(1,723	)	$	(945	)	$	(885	)	$	(3,392	)

Summary of Loss Carryforwards

The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2016.



																							Successor
	Exelon			Generation			ComEd		PECO		BGE			Pepco			DPL			ACE			PHI
Federal
Federal net operating loss	$	282	^(a)	$	11		$	82	$	—	$	—		$	44		$	38		$	18		$	121
Deferred taxes on Federal net operating loss	99			4			29		—		—			15			13			6			42
Federal general business credits carryforwards	511		^(b)	509			1		—		1			—			—			—			—
State
State net operating losses and credit carryforwards	3,501		^(c)	1,245		^(c)	—		—		425		^(d)	360		^(e)	639		^(f)	272		^(g)	1,522		^(h)
Deferred taxes on state tax attributes (net)	186			65			—		—		23			20			36			16			86
Valuation allowance on state tax attributes	20			9			—		—		1			—			—			—			10

_____________________


(a)	Exelon's federal net operating loss will begin expiring in 2032.


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


(c)	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2017.


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


(e)	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2028.


(f)	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.


(g)	ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2032.


(h)	PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.

Reconciliation of Unrecognized Tax Benefits Excluding Amounts Pertaining to Examined Tax Returns Foll Forward

following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2016, 2015 and 2014:



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



																					Predecessor
	Exelon			Generation			ComEd			PECO			BGE		Pepco		DPL		ACE		PHI
Unrecognized tax benefits at January 1, 2015	$	1,829		$	1,357		$	149		$	44		$	—	$	—	$	—	$	—	$	702
Increases based on tax positions related to 2015	108			—			—			—			106		—		—		—		—
Change to positions that only affect timing	(705		)	(659		)	(7		)	(44		)	—		—		—		—		(688		)
Increases based on tax positions prior to 2015	79			65			—			—			14		8		3		—		11
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		)	—			—			—		—		—		—		(3		)
Unrecognized tax benefits at December 31, 2015	$	1,078		$	534		$	142		$	—		$	120	$	8	$	3	$	—	$	22



																							Predecessor
	Exelon			Generation			ComEd			PECO		BGE		Pepco			DPL			ACE			PHI
Unrecognized tax benefits at January 1, 2014	$	2,175		$	1,415		$	324		$	44	$	—	$	45		$	3		$	3		$	743
Increases based on tax positions related to 2014	15			15			—			—		—		—			—			—			—
Change to positions that only affect timing	(255		)	33			(175		)	—		—		(45		)	(3		)	(3		)	(41		)
Increases based on tax positions prior to 2014	18			18			—			—		—		—			—			—			—
Decreases based on tax positions prior to 2014	(1		)	(2		)	—			—		—		—			—			—			—
Decreases 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	$	—	$	—		$	—		$	—		$	702

Interest Income and Interest Expense Disclosure [Table Text Block]

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



Net interest expense (income) for the years ended	Exelon			Generation			ComEd		PECO		BGE		Pepco			DPL		ACE
December 31, 2016	$	165		$	(13	)	$	117	$	—	$	—	$	6		$	—	$	(1	)
December 31, 2015	(13		)	(31		)	7		—		—		(4		)	—		—
December 31, 2014	(36		)	(50		)	6		—		1		(1		)	—		(1		)



Net penalty expense (income) for the years ended	Exelon		Generation		ComEd			PECO		BGE		Pepco		DPL		ACE
December 31, 2016	$	106	$	—	$	86	—	$	—	$	—	$	—	$	—	$	—
December 31, 2015	—		—		—			—		—		—		—		—
December 31, 2014	—		—		—			—		—		—		—		—



	Successor			Predecessor
PHI	March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016		December 31, 2015			December 31, 2014
Net interest expense (income)	$	(2	)	$	—	$	(34	)	$	—
Net penalty expense (income)	—			—		—			—

Summary of Open Tax Years by Jurisdiction

ription 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, 2001-2015
PHI Holdings and subsidiaries consolidated Federal income tax returns	2013-2015
Exelon and subsidiaries Illinois unitary income tax returns	2010-2015
Constellation combined New York corporate income tax returns	2010-March 2012
Exelon combined New York corporate income tax returns	2011-2015
Various separate company (excluding PECO) Pennsylvania corporate net income tax returns	2011-2015
PECO Pennsylvania separate company returns	2010-2015
DPL Delaware separate company returns	Same as Federal
ACE New Jersey separate company returns	2012-2015
Various separate company Maryland corporate net income tax returns	Same as Federal
Washington D.C. corporate income tax returns	2013-2015

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2016

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, 2015 to December 31, 2016:



	Exelon and Generation
Nuclear decommissioning ARO at January 1, 2015	$	6,961
Accretion expense	387
Net increase for changes in and timing of estimated future cash flows	901
Costs incurred related to decommissioning plants	(3		)
Nuclear decommissioning ARO at December 31, 2015^(a)	8,246
Accretion expense	436
Net increase for changes in and timing of estimated future cash flows	61
Costs incurred related to decommissioning plants	(9		)
Nuclear decommissioning ARO at December 31, 2016 ^(a)	$	8,734

_________________________


(a)	Includes $10 million and $7 million as the current portion of the ARO at December 31, 2016 and 2015, 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 2016, 2015 and 2014:



	Exelon and Generation
	For the Years Ended December 31,
	2016		2015			2014
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units ^(a)	$	216	$	(282	)	$	180
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement Units ^(b)(c)	194		(197		)	134

_______________________


(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 $(1) million, $7 million and $29 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2016, 2015 and 2014, 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, 2016 and 2015:



	Exelon and Generation
	2016		2015
Carrying value of Zion Station pledged assets	$	113	$	206
Payable to Zion Solutions ^(a)	104		189
Current portion of payable to Zion Solutions ^(b)	90		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs ^(c)	878		786

___________________


(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, 2015 to December 31, 2016:



																Successor
	Exelon			Generation			ComEd			PECO			BGE			PHI^(f)		Pepco		DPL		ACE
Non-nuclear AROs at January 1, 2015	$	346		$	194		$	104		$	30		$	18		$	—	$	—	$	—	$	—
Net (decrease) increase 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^(d)	(2		)	(2		)	—			—			—			—		—		—		—
Payments	(5		)	(3		)	(2		)	—			—			—		—		—		—
Non-nuclear AROs at December 31, 2015^(e)	355			197			113			27			18			—		—		—		—
Merger with PHI ^(g)	8			1			—			—			—			—		—		—		—
Net increase (decrease) due to changes in, and timing of, estimated future cash flows^(a)	34			8			4			1			7			14		2		9		3
Development projects^(b)	11			11			—			—			—			—		—		—		—
Accretion expense^(c)	18			10			7			1			—			—		—		—		—
Sale of generating assets^(d)	(22		)	(22		)	—			—			—			—		—		—		—
Payments	(11		)	(6		)	(3		)	(1		)	(1		)	—		—		—		—
Non-nuclear AROs at December 31, 2016^(e)	$	393		$	199		$	121		$	28		$	24		$	14	$	2	$	9	$	3



	Predecessor
	PHI^(f)
Non-nuclear AROs at January 1, 2015	$	7
Accretion expense^(c)	1
Non-nuclear AROs at December 31, 2015	$	8

Non-nuclear AROs at March 23, 2016	$	8

________________________

(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)	Reflects a reduction to the ARO resulting primarily from the sales of the New Boston generating site and Upstream business in 2016 and Schuylkill generating station in 2015. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.


(e)	Excludes $1 million, $2 million and $3 million as the current portion of the ARO at December 31, 2016 for Generation, ComEd and BGE, respectively. Excludes $5 million, $2 million and $1 million as the current portion of the ARO at December 31, 2015 for Generation, ComEd and BGE, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.


(f)	For PHI, the successor period includes activity for the period of March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year ended December 31, 2015 and the period January 1, 2016 through March 23, 2016.


(g)	Following the completion of the PHI merger on March 23, 2016, PHI's AROs related to its unregulated business interests were transferred to Exelon and Generation.

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule Of Pension And Other Postretirement Participation

The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2016.

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Qualified Pension Plans:

Exelon Corporation Retirement Program^(a)

Exelon Corporation Cash Balance Pension Plan^(a)

Exelon Corporation Pension Plan for Bargaining

Unit Employees^(a)

Exelon New England Union Employees Pension

Plan^(a)

Exelon Employee Pension Plan for Clinton, TMI

and Oyster Creek^(a)

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

Pension Plan of Constellation Energy Nuclear

Group, LLC^(c)

Nine Mile Point Pension Plan^(c)

Constellation Mystic Power, LLC Union Employees

Pension Plan Including Plan A and Plan B^(b)

Pepco Holdings LLC Retirement Plan^(d)

Non-Qualified Pension Plans:

Exelon Corporation Supplemental Pension Benefit

Plan and 2000 Excess Benefit Plan^(a)

Exelon Corporation Supplemental Management

Retirement Plan^(a)

Constellation Energy Group, Inc. Senior Executive

Supplemental Plan^(b)

Constellation Energy Group, Inc. Supplemental

Pension Plan^(b)

Constellation Energy Group, Inc. Benefits

Restoration Plan^(b)

Constellation Energy Nuclear Plan, LLC Executive

Retirement Plan^(c)

Constellation Energy Nuclear Plan, LLC Benefits

Restoration Plan^(c)

Baltimore Gas & Electric Company Executive

Benefit Plan^(b)

Baltimore Gas & Electric Company Manager

Benefit Plan^(b)

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

Conectiv Supplemental Executive Retirement Plan^(d)

Pepco Holdings LLC Combined Executive Retirement Plan ^(d)

Atlantic City Electric Director Retirement Plan ^(d)

Operating Company^(e)

Name of Plan:

Generation

ComEd

PECO

BGE

BSC

PHI

Pepco

DPL

ACE

Other Postretirement Benefit Plans



							Predecessor
			Exelon				PHI
			Percentage of Plan Assets at December 31,
Asset Category	Target Allocation		2016		2015		2015
Equity securities	43	%	47	%	43	%	63	%
Fixed income securities	28	%	29		27		34
Alternative investments^(a)	29	%	24		30		3
Total			100	%	100	%	100	%

___________________


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

Defined Benefit Plan Fair Value Of Plan Assets

Fair Value Measurements

Exelon



At December 31, 2016(a)(d)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	325	$	—	$	—	$	—	$	325
Equities^(b)	3,144		—		2		2,535		5,681
Fixed income:
U.S. Treasury and agencies	1,008		192		—		—		1,200
State and municipal debt	—		64		—		—		64
Corporate debt	—		3,641		206		—		3,847
Other^(b)	—		340		—		748		1,088
Fixed income subtotal	1,008		4,237		206		748		6,199
Private equity	—		—		—		991		991
Hedge funds	—		—		—		1,962		1,962
Real estate	—		—		—		828		828
Private credit	—		—		—		833		833
Pension plan assets subtotal	$	4,477	$	4,237	$	208	$	7,897	$	16,819



At December 31, 2016(a)(d)	Level 1		Level 2		Level 3			Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	24	$	—	$	—		$	—	$	24
Equities	547		2		—			644		1,193
Fixed income:
U.S. Treasury and agencies	9		59		—			—		68
State and municipal debt	—		134		—			—		134
Corporate debt	—		43		—			—		43
Other	256		60		—			131		447
Fixed income subtotal	265		296		—		—	131		692
Hedge funds	—		—		—			445		445
Real estate	—		—		—			117		117
Private credit	—		—		—			107		107
Other postretirement benefit plan assets subtotal	$	836	$	298	$	—		$	1,444	$	2,578
Total pension and other postretirement benefit plan assets^(c)	$	5,313	$	4,535	$	208		$	9,341	$	19,397



At December 31, 2015(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	210	$	—	$	—	$	—	$	210
Equities^(b)	3,571		—		2		1,462		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)	—		146		—		452		598
Fixed income subtotal	1,001		3,187		165		452		4,805
Private equity	—		—		—		924		924
Hedge funds	—		—		—		1,924		1,924
Real estate	—		—		—		725		725
Private credit	—		—		—		699		699
Pension plan assets subtotal	$	4,782	$	3,187	$	167	$	6,186	$	14,322



At December 31, 2015(a)	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	15	$	—	$	—	$	—	$	15
Equities	510		2		—		480		992
Fixed income:
U.S. Treasury and agencies	11		53		—		—		64
State and municipal debt	—		131		—		—		131
Corporate debt	—		44		—		—		44
Other	155		59		—		146		360
Fixed income subtotal	166		287		—		146		599
Hedge funds	—		—		—		451		451
Real estate	—		—		—		131		131
Private credit	—		—		—		103		103
Other postretirement benefit plan assets subtotal	$	691	$	289	$	—	$	1,311	$	2,291
Total pension and other postretirement benefit plan assets^(c)	$	5,473	$	3,476	$	167	$	7,497	$	16,613



	Predecessor
	December 31, 2015(a)
PHI	Level 1		Level 2		Level 3		Not subject to leveling		Total
Pension plan assets
Cash equivalents	$	50	$	—	$	—	$	—	$	50
Equities	335		—		—		224		559
Fixed income:
U.S. Treasury and agencies	114		15		—		—		129
State and municipal debt	—		18		—		—		18
Corporate debt securities	—		625		—		—		625
Other	—		40		—		504		544
Fixed income subtotal	114		698		—		504		1,316
Private equity	—		—		—		38		38
Real estate	—		—		—		46		46
Pension plan assets subtotal	$	499	$	698	$	—	$	812	$	2,009



	Predecessor
	December 31, 2015(a)
PHI	Level 1		Level 2		Level 3		Not subject to leveling		Total
Other postretirement benefit plan assets
Cash equivalents	$	8	$	—	$	—	$	—	$	8
Equities	197		—		—		22		219
Fixed income - other	121		—		—		—		121
Other postretirement benefit plan assets subtotal	$	326	$	—	$	—	$	22	$	348
Total pension and other postretirement benefit plan assets^(e)	$	825	$	698	$	—	$	834	$	2,357

____________________


(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 liabilities of $28 million and net assets of $27 million at December 31, 2016 and 2015, 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.


(d)	Effective March 23, 2016, Exelon became sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets.


(e)	Excludes net assets of $9 million at December 31, 2015, 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 purchased.

Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation

rchases.


(d)	Effective March 23, 2016, Exelon became sponsor of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets.


(e)	Excludes net assets of $9 million at December 31, 2015, 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 purchased.

Exelon



	Fixed income			Equities		Total
Pension Assets
Balance as of January 1, 2016	$	165		$	2	$	167
Actual return on plan assets:
Relating to assets still held at the reporting date	(2		)	—		(2		)
Purchases, sales and settlements:
Purchases	69			—		69
Sales	(14		)	—		(14		)
Settlements^(a)	(12		)	—		(12		)
Balance as of December 31, 2016	$	206		$	2	$	208



	Fixed income			Equities		Total
Pension Assets
Balance as of January 1, 2015	$	120		$	2	$	122
Actual return on plan assets:
Relating to assets still held at the reporting date	(8		)	—		(8		)
Purchases, sales and settlements:
Purchases	61			—		61
Settlements^(a)	(8		)	—		(8		)
Balance as of December 31, 2015	$	165		$	2	$	167

________________________


(a)	Represents cash settlements only.

Schedule Of Defined Contributions

n limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2016, 2015 and 2014:



For the Year Ended December 31,	Exelon^(a)		Generation^(a)		ComEd		PECO		BGE		BSC^(b)		Pepco^(c)		DPL^(c)		ACE		PHISCO^(c)
2016	$	164	$	79	$	34	$	10	$	12	$	19	$	3	$	2	$	2	$	6
2015	148		80		32		11		14		11		3		2		2		6
2014	103		51		26		8		8		10		3		2		1		6



	Successor		Predecessor
PHI	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015		For the Year Ended December 31, 2014
Saving Plan Matching Contributions	$	10	$	3	$	14	$	13

_________________________


(a)	Includes $13 million, $9 million and $5 million related to CENG for the years ended December 31, 2016, 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.


(c)	Pepco's, DPL's and PHISCO's matching contributions include $1 million, $1 million and $1 million, respectively, of costs incurred prior to the closing of Exelon's merger with PHI on March 23, 2016, which is not included in Exelon's matching contributions at December 31, 2016.

Severance (Tables)

12 Months Ended

Dec. 31, 2016

Restructuring and Related Activities [Abstract]

Schedule of Restructuring and Related Costs



	For the Year Ended December 31,
Acquisition, Integration and Financing Costs^(a)	2016			2015
Exelon^(b)	$	143		$	87
Generation	37			24
ComEd^(c)	(6		)	9
PECO	5			4
BGE^(c)	(1		)	5
Pepco^(c)	28			3
DPL^(c)	20			2
ACE	19			1



	Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015
PHI^(c)	$	69	$	29	$	19

______________


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


(b)	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.


(c)	For the year ended December 31, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million, $4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco^(b)		DPL^(c)		ACE
Severance benefits^(a)	$	57	$	9	$	2	$	1	$	1	$	44	$	21	$	13	$	10

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the year ended December 31, 2016.


(b)	Pepco established a regulatory asset of $11 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.


(c)	DPL established a regulatory asset of $4 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.




	Exelon		Generation^(a)		ComEd^(a)		PECO^(a)		BGE^(a)
Year ended December 31,
2016	$	19	$	13	$	3	$	1	$	1
2015	18		15		2		—		1



	Successor		Predecessor
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016		For the Year Ended December 31, 2015
PHI^(a)
Severance Benefits	$	1	$	—	$	—

_______


(a)	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.

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



															Successor
Severance Liability	Exelon			Generation			ComEd			PECO		BGE			PHI^(b)			Pepco			DPL			ACE
Balance at December 31, 2014	$	50		$	34		$	2		$	—	$	2		$	—		$	1		$	—		$	—
Severance charges	16			10			2			—		—			—			—			—			—
Payments	(31		)	(21		)	(1		)	—		(1		)	—			(1		)	—			—
Balance at December 31, 2015	$	35		$	23		$	3		$	—	$	1		$	—		$	—		$	—		$	—
Severance charges^(a)	99			22			2			—		—			56			1			1			—
Payments	(46		)	(9		)	(2		)	—		(1		)	(27		)	(1		)	(1		)	—
Balance at December 31, 2016	$	88		$	36		$	3		$	—	$	—		$	29		$	—		$	—		$	—



	Predecessor
Severance Liability	PHI^(b)
Balance at December 31, 2014	$	3
Severance charges	—
Payments	(3		)
Balance at December 31, 2015	$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.


(b)	For PHI, the successor period includes activity for the period from March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year ended December 31, 2015 and the period January 1, 2016 through March 23, 2016. There was no activity in the 2016 PHI predecessor period.



	Exelon		Generation		ComEd		PECO		BGE
Severance benefits^(a)	$	23	$	18	$	3	$	1	$	1

_______


(a)	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2016.

Mezzanine Equity Contingently Redeemable Noncontrolling Interest (Table)

12 Months Ended

Dec. 31, 2016

Noncontrolling Interest Disclosure [Abstract]

Noncontrolling Interest Disclosure [Text Block]

19. Mezzanine Equity (Exelon, Generation and PHI)

Contingently Redeemable Noncontrolling Interests (Exelon and 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 circumstances the equity contributed by the noncontrolling interests holder could be contingently redeemable. These circumstances are outside of the control of Generation and the noncontrolling interests holder resulting in a portion of the noncontrolling interests being considered contingently redeemable and thus presented in mezzanine equity on the consolidated balance sheet.

The following table summarizes the changes in the contingently redeemable noncontrolling interests for the years ended December 31, 2016 and 2015:



	Contingently Redeemable NCI

Balance at December 31, 2014	$	—
Cash received from noncontrolling interests	32
Release of contingency	(4		)
Balance at December 31, 2015	$	28
Cash received from noncontrolling interests	129
Release of contingency	(157		)
Balance at December 31, 2016	$	—

Preferred Stock (PHI)

In connection with the PHI Merger Agreement, Exelon purchased 18,000 originally issued shares of PHI preferred stock for a purchase price of $180 million. PHI excluded the preferred stock from equity at December 31, 2015 since the preferred stock contained conditions for redemption that were not solely within the control of PHI. Management determined that the preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the preferred stock in the event of such a termination were separately accounted for as derivatives. As of December 31, 2015, the fair value of the derivative related to the preferred stock was estimated to be $18 million based on PHI’s updated assessment and was included in current assets with a corresponding increase in preferred stock on the Consolidated Balance Sheet. Immediately prior to the merger date, PHI updated its assessment of the fair value of the derivative and reduced the fair value to zero, recording the $18 million decrease in fair value as a reduction of Other, within PHI's predecessor period, January 1, 2016 to March 23, 2016, Statements of Operations and Comprehensive Income.

On March 23, 2016, the preferred stock was cancelled and the $180 million cash consideration previously received by PHI to issue the preferred stock was treated as additional merger purchase price consideration.

Redeemable Noncontrolling Interest [Table Text Block]

The following table summarizes the changes in the contingently redeemable noncontrolling interests for the years ended December 31, 2016 and 2015:



	Contingently Redeemable NCI

Balance at December 31, 2014	$	—
Cash received from noncontrolling interests	32
Release of contingency	(4		)
Balance at December 31, 2015	$	28
Cash received from noncontrolling interests	129
Release of contingency	(157		)
Balance at December 31, 2016	$	—

Shareholder Equity Shareholder Equity (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015:



				December 31,
				2016	2015
	Par Value		Shares Authorized	Shares Outstanding
Common Stock
Exelon	no par value		2,000,000,000	924,035,059	919,924,742
ComEd	$	12.50	250,000,000	127,017,157	127,016,973
PECO	no par value		500,000,000	170,478,507	170,478,507
BGE	no par value		175,000,000	1,000	1,000
PHI Predecessor	$	0.01	400,000,000	n/a	254,289,261
Pepco	$	0.01	200,000,000	100	100
DPL	$	2.25	1,000	1,000	1,000
ACE	$	3.00	25,000,000	8,546,017	8,546,017

Schedule of Auction Market Preferred Securities by Stock Series [Table Text Block]



			December 31,
	Redemption Price ^(a)		2016	2015	2016		2015
	Redemption Price ^(a)		Shares Outstanding		Dollar Amount
Series (without mandatory redemption)
7.125%, 1993 Series	$	100.00	—	400,000	$	—	$	40
6.97%, 1993 Series	100.00		—	500,000	—		50
6.70%, 1993 Series	100.00		—	400,000	—		40
6.99%, 1995 Series	100.00		—	600,000	—		60
Total preference stock			—	1,900,000	$	—	$	190

______________________


(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

Stock-Based Compensation Plans (All Registrants) (Tables)

12 Months Ended

Dec. 31, 2016

Common Stock [Abstract]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]



Exelon	Year Ended December 31,
Components of Stock-Based Compensation Expense	2016(a)			2015			2014
Performance share awards	$	93		$	41		$	59
Restricted stock units	75			71			61
Stock options	—			1			2
Other stock-based awards	7			6			5
Total stock-based compensation expense included in operating and maintenance expense	175			119			127
Income tax benefit	(68		)	(46		)	(47		)
Total after-tax stock-based compensation expense	$	107		$	73		$	80

____________________


(a)	2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.

PHI



	Predecessor
	January 1 to March 23,			Years Ended December 31,
Components of Stock-Based Compensation Expense	2016			2015			2014
Time-based restricted stock units	$	2		$	7		$	5
Performance-based restricted stock units	1			5			8
Time-based restricted stock awards	—			1			5
Total stock-based compensation expense included in operating and maintenance expense	3			13			18
Income tax benefit	(1		)	(5		)	(7		)
Total after-tax stock-based compensation expense	$	2		$	8		$	11

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award [Table Text Block]



	Years Ended December 31,
Subsidiaries	2016		2015		2014
Exelon	$	175	$	119	$	127
Generation	78		64		52
ComEd	8		6		7
PECO	3		3		3
BGE	1		3		5
BSC ^(a)	81		43		60
PHI ^(a)(b)	7		13		18



	Successor		Predecessor
	March 24 to December 31,		January 1 to March 23,		Years Ended December 31,
	2016		2016		2015		2014
PHI	$	4	$	3	$	13	$	18

____________________


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


(b)	Pepco's, DPL's and ACE's stock-based compensation expense for the year ended December 31, 2016 and for the period January 1, 2016 through March 23, 2016 was not material. PHI's stock-based compensation expense for the year ended December 31, 2016 includes $3 million of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.

Stock Based Compensation Tax Benefit

The following tables present information regarding Exelon’s and PHI's tax benefits for the years ended December 31, 2016, 2015 and 2014 and PHI's predecessor period January 1, 2016 to March 23, 2016:



Exelon	Years Ended December 31,
	2016		2015		2014
Realized tax benefit when exercised/distributed:
Restricted stock units	$	27	$	30	$	17
Performance share awards	18		18		11

PHI



	Predecessor
	January 1 to March 23,		Years Ended December 31,
	2016		2015		2014
Realized tax benefit when exercised/distributed:
Time-based restricted stock units	$	—	$	2	$	3
Performance-based restricted stock units	—		5		4
Time-based restricted stock awards	—		—		1

Schedule of Assumptions Used

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, 2016:



	Shares		Weighted Average Exercise Price (per share)		Weighted Average Remaining Contractual Life (years)	Aggregate Intrinsic Value
Balance of shares outstanding at December 31, 2015	15,572,757		$	46.68
Options exercised	(840,672	)	22.12
Options forfeited	—		—
Options expired	(2,200,494	)	58.60
Balance of shares outstanding at December 31, 2016	12,531,591		$	46.23	3.50	$	13
Exercisable at December 31, 2016 (a)	12,531,591		$	46.23	3.50	$	13

____________________


(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, 2016, 2015 and 2014:



	Years Ended December 31,
	2016		2015		2014
Intrinsic value^(a)	$	11	$	—	$	3
Cash received for exercise price	19		—		7

______________________


(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, 2016:



	Shares		Weighted Average Exercise Price (per share)
Nonvested at December 31, 2015 (a)	82,250		$	39.81
Vested	(82,250	)	39.81
Nonvested at December 31, 2016 (a)	—		$	—

_____________________


(a)	Excludes 279,000 of stock options issued to retirement-eligible employees as of December 31, 2015 as they are fully vested.

Schedule of Nonvested Restricted Stock Units Activity

Exelon



	Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015 (a)	3,563,254		$	32.92
Granted	3,042,184		28.14
Vested	(1,797,536	)	32.44
Forfeited	(85,940	)	30.08
Undistributed vested awards^(b)	(897,546	)	28.35
Nonvested at December 31, 2016 (a)(c)	3,824,416		$	30.49

PHI



	Time-based Shares	Weighted Average Grant Date Fair Value (per share)		Performance-based Shares			Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015	628,514	$	24.71	$	408,638		$	18.56
Granted	152,928	26.01		305,856			25.41
Vested	—	—		(4,950		)	26.08
Forfeited	—	—		(1,238		)	26.08
Nonvested at March 23, 2016	781,442	$	24.96	$	708,306		$	21.45

______________________


(a)	Excludes 1,319,372 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.


(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2016.

Schedule of Nonvested Performance-based Units Activity

Exelon



	Shares (c)		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015 (a)	2,557,159		$	31.88
Granted	2,319,407		28.85
Change in performance	627,303		30.04
Vested	(949,315	)	31.31
Forfeited	(70,876	)	30.90
Undistributed vested awards ^(b)	(1,367,417	)	28.33
Nonvested at December 31, 2016 (a)	3,116,261		$	30.77

PHI



	Time-based Shares	Weighted Average Grant Date Fair Value (per share)		Performance-based Shares		Weighted Average Grant Date Fair Value (per share)
Nonvested at December 31, 2015	54,165	$	26.80	24,717		$	26.10
Vested	—	—		(24,717	)	26.10
Nonvested at March 23, 2016	54,165	$	26.80	—		$	—

________________


(a)	Excludes 2,443,409 and 1,817,883 of performance share awards issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.


(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2016.

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,
	2016		2015^(c)
Current liabilities^(a)	$	49	$	28
Deferred credits and other liabilities ^(b)	52		32
Common stock	40		35
Total	$	141	$	95

__________________________


(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.


(c)	Excludes $8 million of common stock for PHI at December 31, 2015.

Earnings Per Share and Equity (Tables)

12 Months Ended

Dec. 31, 2016

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:



	Years Ended December 31,
	2016		2015		2014
Net income attributable to common shareholders	$	1,134	$	2,269	$	1,623
Weighted average common shares outstanding—basic	924		890		860
Assumed exercise and/or distributions of stock-based awards	3		3		4
Weighted average common shares outstanding—diluted	927		893		864

Changes in Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016 and 2015:



For the Year Ended December 31, 2016	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Gains and (Losses) on Foreign Currency Items			AOCI of Equity Investments			Total
Exelon^(a)
Beginning balance	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)
OCI before reclassifications	(6		)	1		(182		)	5			(4		)	(186		)
Amounts reclassified from AOCI^(b)	8			—		137			5			—			150
Net current-period OCI	2			1		(45		)	10			(4		)	(36		)
Ending balance	$	(17	)	$	4	$	(2,610	)	$	(30	)	$	(7	)	$	(2,660	)
Generation^(a)
Beginning balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	(6		)	1		—			5			(4		)	(4		)
Amounts reclassified from AOCI^(b)	8			—		—			5			—			13
Net current-period OCI	2			1		—			10			(4		)	9
Ending balance	$	(19	)	$	2	$	—		$	(30	)	$	(7	)	$	(54	)
PECO^(a)
Beginning balance	$	—		$	1	$	—		$	—		$	—		$	1
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		—			—			—			—
Net current-period OCI	—			—		—			—			—			—
Ending balance	$	—		$	1	$	—		$	—		$	—		$	1
PHI Predecessor^(a)
Beginning balance January 1, 2016	$	(8	)	$	—	$	(28	)	$	—		$	—		$	(36	)
OCI before reclassifications	—			—		—			—			—			—
Amounts reclassified from AOCI^(b)	—			—		1			—			—			1
Net current-period OCI	—			—		1			—			—			1
Ending balance March 23, 2016^(c)	$	(8	)	$	—	$	(27	)	$	—		$	—		$	(35	)



For the Year Ended December 31, 2015	Gains and (Losses) on Cash Flow Hedges			Unrealized Gains on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan items			Gains and (Losses) on 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
PHI Predecessor^(a)
Beginning balance	$	(9	)	$	—	$	(37	)	$	—		$	—		$	(46	)
OCI before reclassifications	—			—		5			—			—			5
Amounts reclassified from AOCI^(b)	1			—		4			—			—			5
Net current-period OCI	1			—		9			—			—			10
Ending balance	$	(8	)	$	—	$	(28	)	$	—		$	—		$	(36	)

_______________________


(a)	All amounts are net of tax and noncontrolling interests. 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, Generation and PHI during the years ended December 31, 2016 and 2015:

For the Year Ended December 31, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statements of Operations and Comprehensive Income
							Predecessor
							January 1, 2016 to March 23, 2016
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(13	)	$	(13	)	$	—		Interest expense
Total before tax	(13		)	(13		)	—
Tax benefit	5			5			—
Net of tax	$	(8	)	$	(8	)	$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	78		$	—		$	—
Actuarial losses^(b)	(302		)	—			(1		)
Total before tax	(224		)	—			(1		)
Tax benefit	87			—			—
Net of tax	$	(137	)	$	—		$	(1	)

Gains and (losses) of FX
Gains	$	(5	)	$	(5	)	$	—
Other	—			—			—
Total before tax	(5		)	(5		)	—
Tax benefit	—			—			—
Net of tax	$	(5	)	$	(5	)	$	—

Total Reclassifications	$	(150	)	$	(13	)	$	(1	)	Comprehensive income

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
							Predecessor
	Exelon			Generation			PHI
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		)	(1		)	Interest expense
Total before tax	(35		)	(9		)	(1		)
Tax benefit	14			4			—
Net of tax	$	(21	)	$	(5	)	$	(1	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	74		$	—		$	—
Actuarial losses^(b)	(361		)	—			(6		)
Total before tax	(287		)	—			(6		)
Tax benefit	112			—			2
Net of tax	$	(175	)	$	—		$	(4	)

Total Reclassifications	$	(196	)	$	(5	)	$	(5	)	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, 2016 and 2015:



	For the Years Ended December 31,
	2016			2015			2014
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	30		$	30		$	19
Actuarial loss reclassified to periodic cost	(118		)	(140		)	(93		)
Pension and non-pension postretirement benefit plan valuation adjustment	115			62			317
Change in unrealized (gain) loss on cash flow hedges	—			(6		)	96
Change in unrealized (gain) loss on equity investments	3			1			73
Total	$	30		$	(53	)	$	412

Generation
Change in unrealized loss on cash flow hedges	$	(2	)	$	2		$	84
Change in unrealized (gain) loss on equity investments	3			1			73
Total	$	1		$	3		$	157



	Predecessor
	January 1 to March 23,		For the Years Ended December 31,
PHI	2016		2015		2014
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	—	$	6	$	5

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2016

Schedule of Government Settlement Agreements [Table Text Block]

As of December 31, 2016, and 2015, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:



	December 31, 2016			December 31, 2015
DOE receivable - current ^(a)	$	109		$	76
DOE receivable - noncurrent ^(b)	15			14
Amounts owed to co-owners ^(a)(c)	(13		)	(5		)

_____________________________


(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.

Operating Leases Of Lessee Disclosure

Exelon’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1,614	$	1,355	$	246	$	—	$	13	$	—	$	—
Surety bonds^(b)	1,035		978		33		2		16		6		—
Financing trust guarantees ^(c)	628		—		—		—		—		—		628
Guaranteed lease residual values^(d)	20		—		—		—		—		—		20
Total commercial commitments	$	3,297	$	2,333	$	279	$	2	$	29	$	6	$	648

___________________________


(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)

Other Commitments

As of December 31, 2016, Generation’s estimated commitment relating to its equity purchase agreements, including in-kind services contributions, is anticipated to be as follows:



	Total
2017	$	34
2018	5
Total	$	39



	Exelon ^(a)		Generation^(a)		ComEd ^(b)		PECO ^(b)		BGE ^(b)(c)(d)		PHI		Pepco		DPL ^(b)		ACE
2017	$	183	$	70	$	11	$	3	$	32	$	50	$	7	$	13	$	8
2018	179		75		6		3		34		49		6		17		8
2019	123		30		6		4		34		36		5		7		7
2020	140		48		3		4		34		38		4		10		6
2021	133		47		3		4		32		34		3		9		5
Remaining years	968		644		—		—		33		211		7		54		20
Total minimum future lease payments	$	1,726	$	914	$	29	$	18	$	199	$	418	$	32	$	110	$	54

______________________


(a)	Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.

(b)


(c)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.


(d)	The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the fourth quarter of 2016. BGE's total commitments under the lease agreement are $21 million $25 million, $26 million , $27 million, $28 million, and $14 million related to years 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.

Operating Leases Rent Expense

The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2016, 2015 and 2014:




For the Year Ended December 31,	Exelon		Generation ^(a)		ComEd		PECO		BGE		Pepco		DPL		ACE
2016	$	777	$	667	$	15	$	7	$	22	$	8	$	15	$	13
2015	922		851		12		9		32		7		14		13
2014	865		806		15		14		12		8		14		12



	Successor		Predecessor
	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016	For the Year Ended December 31, 2015	For the Year Ended December 31, 2014
PHI
Rental expense under operating leases	$	49	12	60	59

________________________

(a)

Accrued environmental liabilities



December 31, 2016	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation ^(a)
Exelon	$	429	$	325
Generation	72		—
ComEd	292		291
PECO	33		31
BGE ^(a)	2		2
PHI	30		1
Pepco	27		—
DPL	2		1
ACE	1		—



December 31, 2015	Total environmental investigation and remediation reserve		Portion of total related to MGP investigation and remediation
Exelon	$	369	$	301
Generation	63		—
ComEd	266		264
PECO	37		35
BGE	3		2
PHI (Predecessor)	33		1
Pepco	24		—
DPL	3		1
ACE	1		—

Generation’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1,546	$	1,287	$	246	$	—	$	13	$	—	$	—
Surety bonds	945		918		27		—		—		—		—
Total commercial commitments	$	2,491	$	2,205	$	273	$	—	$	13	$	—	$	—

________________________


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

ComEd’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	14	$	14	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	11		9		2				—		—		—
Financing trust guarantees	200		—		—		—		—		—		200
Total commercial commitments	$	225	$	23	$	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.

PECO’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	23	$	23	$	—	$	—	$	—	$	—	$	—
Surety bonds^(b)	9		9		—		—		—		—		—
Financing trust guarantees	178		—		—		—		—		—		178
Total commercial commitments	$	210	$	32	$	—	$	—	$	—	$	—	$	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.

BGE’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	2	$	2	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	11		10		1		—		—		—		—
Financing trust guarantees	250		—		—		—		—		—		250
Total commercial commitments	$	263	$	12	$	1	$	—	$	—	$	—	$	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.

PHI commercial commitments (Successor) as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	16		14		2		—		—		—		—
Guaranteed lease residual values^(c)	20		—		—		—		—		—		20
Total commercial commitments	$	37	$	15	$	2	$	—	$	—	$	—	$	20

________________________


(a)	Letters of credit (non-debt)—PHI 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)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $50 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Pepco commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Surety bonds ^(a)	9		9		—		—		—		—		—
Guaranteed lease residual values^(b)	6		—		—		—		—		—		6
Total commercial commitments	$	15	$	9	$	—	$	—	$	—	$	—	$	6

________________________

DPL commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Surety bonds ^(a)	4		3		1		—		—		—		—
Guaranteed lease residual values^(b)	7		—		—		—		—		—		7
Total commercial commitments	$	11	$	3	$	1	$	—	$	—	$	—	$	7

________________________

Supplemental Financial Information [Abstract]

ACE commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:



			Expiration within
	Total		2017		2018		2019		2020		2021		2022 and beyond
Letters of credit (non-debt) ^(a)	$	1	$	1	$	—	$	—	$	—	$	—	$	—
Surety bonds ^(b)	3		2		1		—		—		—		—
Guaranteed lease residual values^(c)	5		—		—		—		—		—		5
Total commercial commitments	$	9	$	3	$	1	$	—	$	—	$	—	$	5

________________________


(a)	Letters of credit (non-debt)—ACE 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)

Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $13 million. The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.

Supplemental Financial Information (Tables)

12 Months Ended

Dec. 31, 2016

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, 2016, 2015 and 2014.



																		Successor		Predecessor
																		March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon		Generation		ComEd			PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Taxes other than income
Utility^(a)	$	753	$	122	$	242		$	136	$	85	$	312	$	18	$	—	$	253	$	78
Property	483		246		27			13		123		53		31		3		73		18
Payroll	226		117		28			15		17		8		5		3		23		8
Other	114		21		(4		)	—		4		4		1		1		5		1
Total taxes other than income	$	1,576	$	506	$	293		$	164	$	229	$	377	$	55	$	7	$	354	$	105



											Predecessor
For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	474	$	105	$	236	$	133	$	85	$	326	$	308	$	18	$	—
Property	407		250		27		11		119		94		57		28		3
Payroll	201		118		28		14		16		27		6		4		2
Other	118		16		5		2		4		8		5		1		2
Total taxes other than income	$	1,200	$	489	$	296	$	160	$	224	$	455	$	376	$	51	$	7



											Predecessor
For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Taxes other than income
Utility^(a)	$	456	$	89	$	238	$	128	$	86	$	324	$	307	$	17	$	—
Property	396		240		25		15		114		85		51		24		3
Payroll	200		118		28		14		18		23		6		4		2
Other	102		18		2		2		3		5		5		1		(1		)
Total taxes other than income	$	1,154	$	465	$	293	$	159	$	221	$	437	$	369	$	46	$	4

_____________________

(a)

Components of non-operating income and expenses



																						Successor			Predecessor
																						March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon			Generation			ComEd			PECO			BGE			Pepco		DPL		ACE		PHI			PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	237		$	237		$	—		$	—		$	—		$	—	$	—	$	—	$	—		$	—
Non-regulatory agreement units	126			126			—			—			—			—		—		—		—			—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	216			216			—			—			—			—		—		—		—			—
Non-regulatory agreement units	194			194			—			—			—			—		—		—		—			—
Net unrealized losses on pledged assets
Zion Station decommissioning	(1		)	(1		)	—			—			—			—		—		—		—			—
Regulatory offset to decommissioning trust fund-related activities^(b)	(372		)	(372		)	—			—			—			—		—		—		—			—
Total decommissioning-related activities	400			400			—			—			—			—		—		—		—			—
Investment income (loss)	17			8			—			(1		)	2		^(f)	1		—		1		1			—
Long-term lease income	4			—			—			—			—			—		—		—		—			—
Interest income related to uncertain income tax positions	13			—			—			—			—			1		—		—		(1		)	—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—			—		—		—		—			—
AFUDC—Equity	64			—			14			8			19			19		5		6		23			7
Loss on debt extinguishment	(3		)	(2		)	—			—			—			—		—		—		—			—
Other	24			(5		)	7			1			—			15		8		2		21			(11		)
Other, net	$	413		$	401		$	(65	)	$	8		$	21		$	36	$	13	$	9	$	44		$	(4	)



															Predecessor
For the year ended December 31, 2015	Exelon			Generation			ComEd		PECO			BGE			PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	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		^(f)	—		—		—		—
Long-term lease income	15			—			—		—			—			—		—		—		—
Interest income related to uncertain income tax positions	1			1			—		—			—			34		5		—		—
AFUDC—Equity	24			—			5		5			14			14		12		1		1
Terminated interest rate swaps^(d)	(26		)	—			—		—			—			—		—		—		—
PHI merger related debt exchange^(e)	(22		)	—			—		—			—			—		—		—		—
Other	17			(1		)	16		2			—			40		11		9		2
Other, net	$	(46	)	$	(60	)	$	21	$	5		$	18		$	88	$	28	$	10	$	3



																Predecessor
For the year ended December 31, 2014	Exelon			Generation			ComEd		PECO			BGE				PHI		Pepco		DPL		ACE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	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 (loss)	1			1			—		(1		)	7			^(f)	1		—		—		—
Long-term lease income	24			—			—		—			—				—		—		—		—
Interest income related to uncertain income tax positions	40			54			—		—			—				—		1		—		1
AFUDC—Equity	21			—			3		6			12				13		10		2		1
Other	9			(9		)	14		2			(1		)		30		19		8		1
Other, net	$	455		$	406		$	17	$	7		$	18			$	44	$	30	$	10	$	3

_________________________


(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)	See Note 15—Income Taxes for discussion of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.

(d)


(e)	See Note 14—Debt and Credit Agreements and Note 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.


(f)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.

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, 2016, 2015 and 2014.



																	Successor		Predecessor
																	March 24, 2016 to December 31, 2016		January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	3,477	$	1,835	$	708	$	244	$	299	$	175	$	110	$	82	$	325	$	94
Regulatory assets	407		—		67		26		124		120		47		83		190		58
Amortization of intangible assets, net	52		44		—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	35		35		—		—		—		—		—		—		—		—
Nuclear fuel^(b)	1,159		1,159		—		—		—		—		—		—		—		—
ARO accretion^(c)	446		446		—		—		—		—		—		—		—		—
Total depreciation, amortization and accretion	$	5,576	$	3,519	$	775	$	270	$	423	$	295	$	157	$	165	$	515	$	152



																	Predecessor
For the year ended December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	2,227	$	1,007	$	635	$	240	$	289	$	164	$	103	$	76	$	392
Regulatory assets	170		—		72		20		77		92		45		99		232
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 and accretion	$	3,987	$	2,589	$	707	$	260	$	366	$	256	$	148	$	175	$	624



																	Predecessor
For the year ended December 31, 2014	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI
Depreciation, amortization and accretion
Property, plant and equipment	$	2,080	$	922	$	588	$	227	$	288	$	155	$	94	$	72	$	363
Regulatory assets	191		—		99		9		83		57		28		83		163
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 and accretion	$	3,868	$	2,519	$	687	$	236	$	371	$	212	$	122	$	155	$	526

________________________


(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



																									Successor			Predecessor
																									March 24, 2016 to December 31, 2016			January 1, 2016 to March 23, 2016
For the year ended December 31, 2016	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI			PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	1,340		$	339		$	298		$	104		$	92		$	118		$	47		$	62		$	209		$	43
Income taxes (net of refunds)	(441		)	435			(444		)	64			31			216			115			200			258			11
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	619		$	218		$	166		$	33		$	67		$	31		$	18		$	15		$	86		$	23
Loss from equity method investments	24			25			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	155			19			41			30			1			29			23			32			65			16
Provision for excess and obsolete inventory	12			6			4			—			—			3			1			1			1			1
Stock-based compensation costs	111			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(384		)	(384		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(11		)	(11		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	9			—			4			1			—			2			1			1			3			1
Amortization of rate stabilization deferral	76			—			—			—			81			(12		)	2			—			(5		)	5
Amortization of debt fair value adjustment	(11		)	(11		)	—			—			—			—			—			—			—			—
Merger-related commitments ^(c)(d)	558			53			—			—			—			125			82			110			317			—
Severance costs	99			22			—			—			—			—			—			—			56			—
Asset retirement costs	2			—			—			—			—			—			1			2			2			—
Amortization of debt costs	35			17			4			3			1			—			—			—			1			—
Discrete impacts from EIMA^(e)	8			—			8			—			—			—			—			—			—			—
Lower of cost or market inventory adjustment	37			36			—			1			—			—			—			—			—			—
Baltimore City Conduit Lease Settlement	(28		)	—			—			—			(28		)	—			—			—			—			—
Cash Working Capital Order	(13		)	—			—			—			(13		)	—			—			—			—			—
Other	35			25			(12		)	(3		)	(21		)	5			(14		)	(6		)	(12		)	(3		)
Total other non-cash operating activities	$	1,333		$	15		$	215		$	65		$	88		$	183		$	114		$	155		$	514		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(128	)	$	50		$	(91	)	$	(11	)	$	(86	)	$	27		$	(12	)	$	11		$	21		$	11
Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash	—			119			—			—			—			—			—			—			—			—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash ^(c)(f)	—			—			—			—			—			—			—			—			127			—
Fair value of pension obligation transferred in connection with the PHI Merger ^(c)(f)	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—



Change in PPE related to ARO update	191		191		—	—	—	—	—	—	—	—
Non-cash financing of capital projects	95		95		—	—	—	—	—	—	—	—
Indemnification of like-kind exchange position ^(h)	—		—		158	—	—	—	—	—	—	—
Sale of Upstream assets^(c)	37		37		—	—	—	—	—	—	—	—
Pending FitzPatrick Acquisition⁽ⁱ⁾	(54	)	(54	)	—	—	—	—	—	—	—	—

____________________________


(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)	See Note 4 - Mergers, Acquisitions, and Dispositions for more information.


(d)	Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within Provision for uncollectible accounts.


(e)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate. See Note 3 — Regulatory Matters for more information.


(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


(g)	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.


(h)	See Note 15 — Income Taxes for discussion of the like-kind exchange tax position.


(i)	Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 4 - Mergers, Acquisitions, and Dispositions for more information.



																								Predecessor
For the year ended December 31, 2015	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE		PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	930		$	348		$	308		$	94		$	120		$	116		$	47		$	63	$	268
Income taxes (net of refunds)	342			476			(265		)	64			73			(6		)	(5		)	—		(13		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	637		$	269		$	206		$	39		$	65		$	30		$	15		$	15	$	97
Loss from equity method investments	7			8			—			—			—			—			—			—		—
Provision for uncollectible accounts	120			22			53			30			15			21			20			20		61
Stock-based compensation costs	97			—			—			—			—			—			—			—		13
Other decommissioning-related activity^(a)	(82		)	(82		)	—			—			—			—			—			—		—
Energy-related options^(b)	21			21			—			—			—			—			—			—		—
Amortization of regulatory asset related to debt costs	7			—			5			2			—			2			1			1		5
Amortization of rate stabilization deferral	73			—			—			—			73			1			(3		)	—		(2		)
Amortization of debt fair value adjustment	(17		)	(17		)	—			—			—			—			—			—		—
Discrete impacts from EIMA^(c)	144			—			144			—			—			—			—			—		—
Amortization of debt costs	58			15			4			2			2			—			—			—		2
Provision for excess and obsolete inventory	10			9			1			—			—			—			—			—		1
Lower of cost or market inventory adjustment	23			23			—			—			—			—			—			—		—
Other	11			—			3			(3		)	(18		)	—			—			1		(10		)
Total other non-cash operating activities	$	1,109		$	268		$	416		$	70		$	137		$	54		$	33		$	37	$	167
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	96		$	82		$	34		$	(13	)	$	(9	)	$	(1	)	$	3		$	3	$	6
Nuclear fuel procurement^(d)	57			57			—			—			—			—			—			—		—
Change in PPE related to ARO update	885			885			—			—			—			—			—			—		—
Indemnification of like-kind exchange position^(e)	—			—			7			—			—			—			—			—		—
Non-cash financing of capital projects	77			77			—			—			—			—			—			—		—
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. 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.



																										Predecessor
For the year ended December 31, 2014	Exelon			Generation				ComEd			PECO			BGE			Pepco			DPL			ACE			PHI
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	940		$	322			$	292		$	94		$	111		$	111		$	45		$	61		$	257
Income taxes (net of refunds)	314			227				(6		)	85			(21		)	(58		)	(43		)	(3		)	(2		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	560		$	249			$	162		$	36		$	64		$	22		$	7		$	13		$	58
Loss from equity method investments	22			20				—			—			—			—			—			—			—
Provision for uncollectible accounts	156			14				26			52			64			17			14			13			49
Provision for excess and obsolete inventory	5			5				—			—			—			—			—			—			—
Stock-based compensation costs	91			—				—			—			—			—			—			—			18
Other decommissioning-related activity^(a)	(132		)	(132		)		—			—			—			—			—			—			—
Energy-related options^(b)	122			122				—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	11			—				8			3			—			3			2			—			5
Amortization of rate stabilization deferral	65			—				—			—			65			3			(1		)	—			2
Amortization of debt fair value adjustment	(23		)	(23		)		—			—			—			—			—			—			—
Merger-related commitments	44			44				—			—			—			—			—			—			—
Discrete impacts from EIMA^(c)	53			—				53			—			—			—			—			—			—
Amortization of debt costs	53			12				4			2			2			—			—			—			1
Lower of cost or market inventory adjustment	29			29				—			—			—			—			—			—			—
Other	(2		)	6				2			(1		)	(15		)	(8		)	—			—			(6		)
Total other non-cash operating activities	$	1,054		$	346			$	255		$	92		$	180		$	37		$	22		$	26		$	127
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			10			8			9			28
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. 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 21 — 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.

Accrued Liabilities Current

The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2016 and 2015.



											Successor
December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Investments
Equity method investments:
Financing trusts^(a)	$	22	$	—	$	6	$	8	$	8	$	—	$	—	$	—	$	—
Bloom	216		216		—		—		—		—		—		—		—
Net Power	57		57		—		—		—		—		—		—		—
Other equity method investments	16		15		—		—		—		—		—		—		—
Total equity method investments	311		288		6		8		8		—		—		—		—
Other investments:
Employee benefit trusts and investments (c)	232		44		—		17		4		133		102		—		—
Other cost method investments	52		52		—		—		—		—		—		—		—
Other available for sale investments	34		34		—		—		—		—		—		—		—
Total investments	$	629	$	418	$	6	$	25	$	12	$	133	$	102	$	—	$	—



											Predecessor
December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
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		80		68		—		—
Other cost method investments	55		55		—		—		—		—		—		—		—
Other available for sale investments	29		29		—		—		—		—		—		—		—
Total investments	$	639	$	210	$	6	$	28	$	12	$	80	$	68	$	—	$	—

_________________________


(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, 2016 and 2015.



											Successor
December 31, 2016	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	1,199	$	557	$	199	$	67	$	64	$	112	$	30	$	17	$	11
Taxes accrued	723		239		330		4		78		65		48		4		9
Interest accrued	1,234		82		609		30		31		49		21		8		12
Severance accrued	44		15		2		—		—		19		—		—		—
Other accrued expenses	260		96		110		3		2		27		14		7		6
Total accrued expenses	$	3,460	$	989	$	1,250	$	104	$	175	$	272	$	113	$	36	$	38

											Predecessor
December 31, 2015	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Accrued expenses
Compensation-related accruals^(a)	$	1,014	$	547	$	183	$	66	$	57	$	88	$	26	$	14	$	8
Taxes accrued	293		186		63		4		23		77		56		3		23
Interest accrued	915		77		443		35		27		54		23		8		13
Severance accrued	21		11		3		—		1		—		—		—		—
Other accrued expenses	133		114		14		4		2		47		14		6		26
Total accrued expenses	$	2,376	$	935	$	706	$	109	$	110	$	266	$	119	$	31	$	70

_______________________


(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

Segment Information (Tables)

12 Months Ended

Dec. 31, 2016

Segment Reporting [Abstract]

Reconciliation of revenues from segments to consolidated

Generation total revenues net of purchased power and fuel expense:



	2016							2015							2014
	RNF from external customers^(b)		Intersegment RNF			Total RNF		RNF from external customers^(b)		Intersegment RNF			Total RNF		RNF from external customers^(b)(d)			Intersegment RNF^(d)			Total RNF
Mid-Atlantic ^(a)	$	3,282	$	35		$	3,317	$	3,556	$	15		$	3,571	$	3,544		$	(113	)	$	3,431
Midwest	2,969		2			2,971		2,912		(20		)	2,892		2,607			(8		)	2,599
New England	467		(29		)	438		519		(58		)	461		450			(99		)	351
New York ^(a)	761		(19		)	742		584		50			634		439			44			483
ERCOT	412		(131		)	281		425		(132		)	293		573			(256		)	317
Other Power Regions	483		(147		)	336		440		(190		)	250		517			(190		)	327
Total Revenues net of purchased power and fuel expense for Reportable Segments	$	8,374	$	(289	)	$	8,085	$	8,436	$	(335	)	$	8,101	$	8,130		$	(622	)	$	7,508
Other ^(c)	547		289			836		678		335			1,013		(662		)	622			(40		)
Total Generation Revenues net of purchased power and fuel expense	$	8,921	$	—		$	8,921	$	9,114	$	—		$	9,114	$	7,468		$	—		$	7,468

____________________________


(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 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 the Utility Registrants.

(c)

(d)

Analysis and reconciliation of reportable segment revenues for Generation



	2016							2015							2014
	Revenues from external customers^(b)		Intersegment revenues			Total revenues		Revenues from external customers^(b)		Intersegment revenues			Total revenues		Revenues from external customers^(b)(d)		Intersegment revenues^(d)			Total revenues
Mid-Atlantic ^(a)	$	6,212	$	(33	)	$	6,179	$	5,974	$	(74	)	$	5,900	$	5,414	$	(155	)	$	5,259
Midwest	4,402		10			4,412		4,712		(2		)	4,710		4,488		(13		)	4,475
New England	1,778		(9		)	1,769		2,217		(5		)	2,212		1,468		(46		)	1,422
New York ^(a)	1,198		(42		)	1,156		996		(11		)	985		846		(3		)	843
ERCOT	831		6			837		863		(6		)	857		938		(3		)	935
Other Power Regions	969		(62		)	907		1,182		(80		)	1,102		1,379		(70		)	1,309
Total Revenues for Reportable Segments	$	15,390	$	(130	)	$	15,260	$	15,944	$	(178	)	$	15,766	$	14,533	$	(290	)	$	14,243
Other ^(c)	2,361		130			2,491		3,191		178			3,369		2,860		290			3,150
Total Generation Consolidated Operating Revenues	$	17,751	$	—		$	17,751	$	19,135	$	—		$	19,135	$	17,393	$	—		$	17,393

_______________________


(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 the Utility Registrants.

(c)

(d)

Analysis and reconciliation of reportable segment information



									Successor
	Generation ^(a)		ComEd		PECO		BGE		PHI ^(e)		Other ^(b)		Intersegment Eliminations			Exelon
Operating revenues^(c):
2016
Competitive businesses electric revenues	$	15,390	$	—	$	—	$	—	$	—	$	—	$	(1,430	)	$	13,960
Competitive businesses natural gas revenues	2,146		—		—		—		—		—		—			2,146
Competitive businesses other revenues	215		—		—		—		—		—		(4		)	211



Rate-regulated electric revenues	—			5,254		2,531		2,609		3,506		—		(31		)	13,869
Rate-regulated natural gas revenues	—			—		463		624		92		—		(13		)	1,166
Shared service and other revenues	—			—		—		—		45		1,648		(1,686		)	7
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
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
Intersegment revenues^(d):
2016	$	1,428		$	15	$	8	$	21	$	45	$	1,647	$	(3,159	)	$	5
2015	745			4		2		14		—		1,367		(2,127		)	5
2014	762			4		2		25		—		1,280		(2,067		)	6
Depreciation and amortization:
2016	$	1,879		$	775	$	270	$	423	$	515	$	74	$	—		$	3,936
2015	1,054			707		260		366		—		63		—			2,450
2014	967			687		236		371		—		53		—			2,314
Operating expenses ^(c):
2016	$	16,856		$	4,056	$	2,292	$	2,683	$	3,549	$	1,928	$	(3,164	)	$	28,200
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
Equity in earnings (losses) of unconsolidated affiliates:
2016	$	(25	)	$	—	$	—	$	—	$	—	$	1	$	—		$	(24	)
2015	(8		)	—		—		—		—		1		—			(7		)
2014	(20		)	—		—		—		—		—		—			(20		)
Interest expense, net:
2016	$	364		$	461	$	123	$	103	$	195	$	290	$	—		$	1,536
2015	365			332		114		99		—		123		—			1,033
2014	356			321		113		106		—		169		—			1,065
Income (loss) before income taxes:



2016	$	873	$	679	$	587	$	468	$	(58	)	$	(555	)	$	(5	)	$	1,989
2015	1,850		706		521		477		—			(219		)	(5		)	3,330
2014	1,226		676		466		351		—			(227		)	(6		)	2,486
Income taxes:
2016	$	290	$	301	$	149	$	174	$	3		$	(156	)	$	—		$	761
2015	502		280		143		189		—			(41		)	—			1,073
2014	207		268		114		140		—			(63		)	—			666
Net income (loss):
2016	$	558	$	378	$	438	$	294	$	(61	)	$	(398	)	$	(5	)	$	1,204
2015	1,340		426		378		288		—			(177		)	(5		)	2,250
2014	1,019		408		352		211		—			(164		)	(6		)	1,820
Capital expenditures:
2016	$	3,078	$	2,734	$	686	$	934	$	1,008		$	113		$	—		$	8,553
2015	3,841		2,398		601		719		—			65			—			7,624
2014	3,012		1,689		661		620		—			95			—			6,077
Total assets:
2016	$	46,974	$	28,335	$	10,831	$	8,704	$	21,025		$	10,369		$	(11,334	)	$	114,904
2015	46,529		26,532		10,367		8,295		—			15,389			(11,728		)	95,384

__________________________

(a)


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

(c)

(d)


(e)	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the years ended December 31, 2015 and December 31, 2014.

Successor and Predecessor PHI:



	Pepco		DPL		ACE		Other^(b)		Intersegment Eliminations			PHI
Operating revenues^(a):
March 24, 2016 to December 31, 2016 - Successor
Rate-regulated electric revenues	$	1,675	$	850	$	989	$	5	$	(13	)	$	3,506
Rate-regulated natural gas revenues	—		92		—		—		—			92
Shared service and other revenues	—		—		—		45		—			45
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues	$	511	$	279	$	268	$	42	$	(4	)	$	1,096
Rate-regulated natural gas revenues	—		56		—		1		—			57
Shared service and other revenues	—		—		—		—		—			—
December 31, 2015 - Predecessor
Rate-regulated electric revenues	$	2,129	$	1,138	$	1,295	$	210	$	(2	)	$	4,770



Rate-regulated natural gas revenues	—		164			—			1			—			165
Shared service and other revenues	—		—			—			—			—			—
December 31, 2014 - Predecessor
Rate-regulated electric revenues	$	2,055	$	1,088		$	1,210		$	264		$	(3	)	$	4,614
Rate-regulated natural gas revenues	—		194			—			—			—			194
Shared service and other revenues	—		—			—			—			—			—
Intersegment revenues:
March 24, 2016 to December 31, 2016 - Successor	$	4	$	5		$	2		$	47		$	(13	)	$	45
January 1, 2016 to March 23, 2016 - Predecessor	1		2			1			—			(4		)	—
December 31, 2015 - Predecessor	5		6			4			—			(15		)	—
December 31, 2014 - Predecessor	5		7			4			—			(16		)	—
Depreciation and amortization:
March 24, 2016 to December 31, 2016 - Successor	$	224	$	120		$	128		$	43		$	—		$	515
January 1, 2016 to March 23, 2016 - Predecessor	71		37			37			11			(4		)	152
December 31, 2015 - Predecessor	256		148			175			45			—			624
December 31, 2014 - Predecessor	212		122			155			38			(1		)	526
Operating expenses:
March 24, 2016 to December 31, 2016 - Successor	$	1,577	$	952		$	1,000		$	33		$	(13	)	$	3,549
January 1, 2016 to March 23, 2016 - Predecessor	443		284			251			73			(3		)	1,048
December 31, 2015 - Predecessor	1,790		1,137			1,161			220			—			4,308
December 31, 2014 - Predecessor	1,706		1,075			1,073			350			(1		)	4,203
Interest expense, net:
March 24, 2016 to December 31, 2016 - Successor	$	98	$	38		$	47		$	12		$	—		$	195
January 1, 2016 to March 23, 2016 - Predecessor	29		12			15			11			(2		)	65
December 31, 2015 - Predecessor	124		50			64			43			(1		)	280
December 31, 2014 - Predecessor	115		48			64			42			—			269
Income (loss) before income taxes:
March 24, 2016 to December 31, 2016 - Successor	$	36	$	(30	)	$	(51	)	$	(84	)	$	71		$	(58	)
January 1, 2016 to March 23, 2016 - Predecessor	47		43			5			59			(118		)	36
December 31, 2015 - Predecessor	289		125			73			23			(29		)	481
December 31, 2014 - Predecessor	264		169			76			306			(435		)	380
Income taxes:
March 24, 2016 to December 31, 2016 - Successor	$	26	$	5		$	(5	)	$	(23	)	$	—		$	3
January 1, 2016 to March 23, 2016 - Predecessor	15		17			1			(16		)	—			17
December 31, 2015 - Predecessor	102		49			33			(48		)	27			163
December 31, 2014 - Predecessor	93		65			30			(228		)	178			138
Net income (loss):
March 24, 2016 to December 31, 2016 - Successor	$	10	$	(35	)	$	(47	)	$	(34	)	$	45		$	(61	)
January 1, 2016 to March 23, 2016 - Predecessor	32		26			5			(44		)	—			19
December 31, 2015 - Predecessor	187		76			40			25			(1		)	327
December 31, 2014 - Predecessor	171		104			46			(78		)	(1		)	242
Capital Expenditures:
March 24, 2016 to December 31, 2016 - Successor	$	489	$	277		$	218		$	24		$	—		$	1,008
January 1, 2016 to March 23, 2016 - Predecessor	97		72			93			11			—			273
December 31, 2015 - Predecessor	544		352			300			34			—			1,230
December 31, 2014 - Predecessor	567		352			225			79			—			1,223
Total assets:
December 31, 2016 - Successor	$	7,335	$	4,153		$	3,457		$	10,804		$	(4,724	)	$	21,025
December 31, 2015 - Predecessor	6,908		3,969			3,387			7,162			(5,238		)	16,188

_________


(a)	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 25 — Supplemental Financial Information for total utility taxes for the year ended December 31, 2016 and 2015


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2016

PHI

The financial statements of PHI include related party transactions as presented in the tables below:



	Successor
	March 24, 2016 to December 31, 2016
	March 24, 2016 to December 31, 2016
Operating revenues from affiliates:
BSC	$	44
Generation	1
Total operating revenues from affiliates	$	45
Purchased power from affiliate
Generation	$	486
Operating and maintenance from affiliates:
BSC	$	86
PCI	3
Total operating and maintenance from affiliates	$	89

Cash dividends paid to parent	$	273
Contribution from member	$	1,251

ACE

The financial statements of ACE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
PHISCO	$	2	$	2	$	1
Other	1		2		3
Total operating revenues from affiliates	$	3	$	4	$	4
Purchased power from affiliate
Generation ^(a)	$	37	$	—	$	—
Operating and maintenance:
PHISCO ^(b)	$	155	$	143	$	124
Operating and maintenance from affiliates:
BSC ^(b)	$	15	$	—	$	—
Other	3		3		3
Total operating and maintenance from affiliates	$	18	$	3	$	3
Cash dividends paid to parent	$	63	$	12	$	26
Contribution from parent	$	139	$	95	$	—

The financial statements of ComEd include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates
Generation	$	7	$	4	$	4
BSC	6		—		—
PECO	1		—		—
BGE	1		—		—
Total operating revenues from affiliates	$	15	$	4	$	4
Purchased power from affiliate
Generation ^(a)	$	47	$	18	$	176
Operating and maintenance from affiliates
BSC ^(b)	$	225	$	195	$	166
PECO	1		—		—
BGE	1		—		—
Total operating and maintenance from affiliates	227		195		166
Interest expense to affiliates, net:
ComEd Financing III	$	13	$	13	$	13
Capitalized costs
BSC ^(b)	$	112	$	103	$	77
Cash dividends paid to parent	$	369	$	299	$	307
Contribution from parent	$	315	$	202	$	273



	December 31,
	2016		2015
Payables to affiliates (current):
Generation ^(a)	$	9	$	—
BSC ^(b)	2		—
DPL	2		—
PHISCO ^(b)	16		15
Other	—		1
Total payables to affiliates (current)	$	29	$	16

______________________


(a)	ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. See Note 3—Regulatory Matters for additional information.


(b)	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.



	December 31,
	2016		2015
Receivables from affiliates (current):
Pepco	$	1	$	—
ACE	2		—
Total receivable from affiliates (current)	$	3	$	—
Payables to affiliates (current):
Generation ^(a)	$	16	$	—
BSC ^(b)	3		—
PHISCO ^(b)	19		19
Other	—		1
Total payables to affiliates (current)	$	38	$	20

______________________

The financial statements of PECO include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
Generation ^(a)	$	3	$	2	$	2
BSC	3		—		—
ComEd	1		—		—
BGE	1		—		—
Total operating revenues from affiliates	$	8	$	2	$	2
Purchased power from affiliate
Generation^(b)	$	287	$	220	$	194
Operating and maintenance from affiliates:
BSC ^(c)	$	142	$	107	$	96
Generation	2		3		3
ComEd	1		—		—
BGE	1		—		$	—
Total operating and maintenance from affiliates	$	146	$	110	$	99
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)	$	57	$	40	$	39
Cash dividends paid to parent	$	277	$	279	$	320
Contribution from parent	$	18	$	16	$	24



	December 31,
	2016		2015
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,
	2016		2015
Prepaid voluntary employee beneficiary association trust ^(c)	$	5	$	11
Receivable from affiliates (current):
Voluntary employee beneficiary association trust	$	2	$	2
Generation	9		9
Exelon Corporate ^(e)	345		188
Total receivable from affiliates (current)	$	356	$	199
Receivable from affiliates (noncurrent):
Generation ^(d)	$	2,169	$	2,172
Other	1		—
Total receivable from affiliates (noncurrent)	$	2,170	$	2,172
Payables to affiliates (current):
Generation ^(a)	$	14	$	15
BSC ^(b)	42		39
ComEd Financing III	4		4
PECO	2		2
Exelon Corporate	3		2
Total payables to affiliates (current)	$	65	$	62
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.

The financial statements of Pepco include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
Generation ^(a)	$	1	$	—	$	—
PHISCO	4		5		5
Total operating revenues from affiliates	$	5	$	5	$	5
Purchased power from affiliate
Generation ^(b)	$	295	$	—	$	—
Operating and maintenance:
PHISCO ^(c)	$	263	$	240	$	220
PES ^(d)	39		26		30
Total operating and maintenance	$	302	$	266	$	250
Operating and maintenance from affiliates:
BSC ^(c)	$	31	$	—	$	—
PHISCO ^(c)	4		4		4
Total operating and maintenance from affiliates	$	35	$	4	$	4
Cash dividends paid to parent	$	136	$	146	$	86
Contribution from parent	$	187	$	112	$	80



	December 31,
	2016		2015
Receivables from affiliates (current):
ComEd ^(a)	$	14	$	15
PECO ^(b)	33		36
BGE ^(c)	26		31
Pepco ^(d)	44		—
DPL ^(e)	16		—
ACE ^(f)	9		—
PHISCO ^(j)	5		—
PCI	8		—
Other	1		1
Total receivables from affiliates (current)	$	156	$	83
Intercompany money pool (current):
Exelon Corporate	$	—	$	1,252
PCI	55		—
Total intercompany money pool (current)	$	55	$	1,252
Payables to affiliates (current):
Exelon Corporate ^(m)	$	22	$	16
BSC ^(j)	99		78
ComEd	9		9
Other	7		1
Total payables to affiliates (current)	$	137	$	104
Long-term debt due to affiliates (noncurrent):
Exelon Corporate ^(o)	$	922	$	933
Payables to affiliates (noncurrent):
BSC ^(g)	$	1	$	—
ComEd ⁽ⁿ⁾	2,169		2,172
PECO ⁽ⁿ⁾	438		405
Total payables to affiliates (noncurrent)	$	2,608	$	2,577

_______________________


(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 a ten-year agreement with PECO to sell solar AECs. 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)	Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. See Note 3—Regulatory Matters for additional information.


(e)	Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.


(f)	Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. See Note 3—Regulatory Matters for additional information.

(g)

(h)


(i)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.


(j)	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

(k)


(l)	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.


(m)	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.


(n)	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.

(o)



	December 31,
	2016		2015
Payables to affiliates (current):
Generation ^(b)	$	26	$	31
BSC ^(c)	22		17
Exelon Corporate	1		1
PECO	2		—
BGE Capital Trust II	3		3
Other	1		—
Total payables to affiliates (current)	$	55	$	52
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.

The financial statements of Exelon include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016			2015			2014
Operating revenues from affiliates:
PECO ^(a)	$	1		$	1		$	1
CENG ^(b)	—			—			17
BGE ^(a)	4			4			5
Other	5			4			—
Total operating revenues from affiliates	$	10		$	9		$	23
Purchase power and fuel from affiliates:
CENG^(c)	$	—		$	—		$	282
Keystone Fuels, LLC ^(d)	—			—			138
Conemaugh Fuels, LLC ^(d)	—			—			99
Safe Harbor Water Power Corp ^(d)	—			—			12
Total purchase power and fuel from affiliates	$	—		$	—		$	531
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	)
Qualifying facilities and domestic power projects	(25		)	(8		)	(1		)
Other	1			1			—
Total losses in equity method investments	$	(24	)	$	(7	)	$	(20	)




	December 31,
	2016
	Successor
Payables to affiliates (current):
Generation	$	74
BSC	10
Exelon Corporate	6
PHI Corporate	4
Total payables to affiliates (current)	$	94

The financial statements of DPL include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
PHISCO	$	5	$	5	$	6
Other	2		1		1
Total operating revenues from affiliates	$	7	$	6	$	7
Purchased power from affiliate
Generation ^(a)	$	154	$	—	$	—
Operating and maintenance:
PHISCO ^(b)	$	194	$	179	$	163
PES ^(c)	8		3		—
Total operating and maintenance	$	202	$	182	$	163
Operating and maintenance from affiliates:
BSC ^(b)	$	18	$	—	$	—
Other	1		1		1
Total operating and maintenance from affiliates	$	19	$	1	$	1
Cash dividends paid to parent	$	54	$	92	$	100
Contribution from parent	$	152	$	75	$	130

The financial statements of Generation include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016			2015			2014
Operating revenues from affiliates:
ComEd ^(a)	$	47		$	18		$	176
PECO ^(b)	290			224			198
BGE ^(c)	608			502			387
Pepco ^(d)	295			—			—
DPL ^(e)	154			—			—
ACE^(f)	37			—			—
CENG ^(g)	—			—			17
BSC	2			1			1
Other	6			4			—
Total operating revenues from affiliates	$	1,439		$	749		$	779
Purchase power and fuel from affiliates:
ComEd	$	—		$	—		$	1
BGE	12			14			25
CENG ^(h)	—			—			282
Keystone Fuels, LLC ^(l)	—			—			138
Conemaugh Fuels, LLC ^(l)	—			—			99
Safe Harbor Water Power Corporation^(l)	—			—			12
Total purchase power and fuel from affiliates	$	12		$	14		$	557
Operating and maintenance from affiliates:
ComEd ⁽ⁱ⁾	$	7		$	4		$	3
PECO ⁽ⁱ⁾	3			2			2
BGE ⁽ⁱ⁾	1			—			—
PHI	1			—			—
Pepco	1			—			—
BSC ^(j)	650			614			618
Total operating and maintenance from affiliates	$	663		$	620		$	623
Interest expense to affiliates, net:
Exelon Corporate ^(m)	$	39		$	43		$	53
Earnings (losses) in equity method investments
CENG^(k)	$	—		$	—		$	(19	)
Qualifying facilities and domestic power projects	(25		)	(8		)	(1		)
Total losses in equity method investments	$	(25	)	$	(8	)	$	(20	)
Capitalized costs
BSC ^(j)	$	98		$	76		$	91
Cash distribution paid to member	$	922		$	2,474		$	645
Contribution from member	$	142		$	47		$	53

The financial statements of BGE include related party transactions as presented in the tables below:



	For the Years Ended December 31,
	2016		2015		2014
Operating revenues from affiliates:
Generation ^(a)	$	13	$	14	$	25
BSC	6		—		—
ComEd	1		—		—
PECO	1		—		—
Total operating revenues from affiliates	$	21	$	14	$	25
Purchased power from affiliate
Generation ^(b)	$	604	$	498	$	382
Operating and maintenance from affiliates:
BSC ^(c)	$	130	$	118	$	103
ComEd	1		—		—
PECO	1		—		—
Total operating and maintenance from affiliates	$	132	$	118	$	103
Interest expense to affiliates, net:
BGE Capital Trust II	$	16	$	16	$	16
Capitalized costs
BSC ^(c)	$	36	$	28	$	19
Cash dividends paid to parent	$	179	$	158	$	—
Contribution from parent	$	61	$	7	$	—



	December 31,
	2016		2015
Prepaid voluntary employee beneficiary association trust ^(d)	$	1	$	2
Receivable from affiliate (current):
ComEd	$	2	$	2
BGE	2		—
Total receivable from affiliates (current)	$	4	$	2
Receivable from affiliate (noncurrent):
Generation ^(e)	$	438	$	405
Payables to affiliates (current):
Generation^(b)	$	33	$	36
BSC^(c)	28		17
Exelon Corporate	1		1
PECO Trust III	1		1
Total payables to affiliates (current)	$	63	$	55
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,
	2016		2015
Payables to affiliates (current):
Generation ^(b)	$	44	$	—
BSC ^(c)	4		—
DPL	1		—
PHISCO ^(c)	25		25
PES ^(e)	—		4
Other	—		1
Total payables to affiliates (current)	$	74	$	30

______________________

Quarterly Data (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2016

Quarterly Financial Data [Abstract]

Quarterly Financial Information

The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income					Net (Loss) Income Attributable to Common Shareholders
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	291	$	334	$	(121	)	$	29	$	(100	)	$	9
June 30	270		285		19			25		3			6
September 30	421		386		83			51		47			22
December 31	275		291		26			29		8			3

The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income					Net (Loss) Income Attributable to Common Shareholders
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	551	$	545	$	(105	)	$	63	$	(108	)	$	26
June 30	509		504		97			83		49			42
September 30	635		592		132			115		79			60
December 31	491		488		51			123		23			59

The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:



	Successor			Predecessor		Successor				Predecessor		Successor				Predecessor
	Operating Revenues					Operating (Loss) Income						Net (Loss) Income Attributable to Membership Interest
	2016			2015		2016				2015		2016				2015
Quarter ended:
March 31	$	105	^(a)	$	1,354	$	(411	)	^(a)	$	142	$	(309	)	^(a)	$	53
June 30	1,066			1,119		136				139		52				53
September 30	1,394			1,336		279				184		166				91
December 31	1,078			1,126		90				208		30				130

The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income Attributable to Common Shareholders
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	841	$	985	$	196	$	223	$	124	$	139
June 30	664		661		152		124		100		70
September 30	788		740		204		154		122		90
December 31	701		645		150		128		92		79

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 Attributable to Membership Interest
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	4,739	$	5,840	$	415		$	719	$	310		$	443
June 30	3,589		4,232		(13		)	703		(8		)	398
September 30	5,035		4,768		342			622		236			377
December 31	4,388		4,294		94			230		(41		)	154

The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating (Loss) Income					Net (Loss) Income Attributable to Common Shareholders
	2016		2015		2016			2015		2016			2015
Quarter ended:
March 31	$	362	$	421	$	(72	)	$	63	$	(72	)	$	32
June 30	281		271		30			24		12			8
September 30	331		314		72			32		44			15
December 31	303		296		20			46		7			21

ACE



	Operating Revenues				Operating Income				Net Income Attributable to Common Shareholders
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	7,573	$	8,830	$	483	$	1,366	$	173	$	693
June 30	6,910		6,514		647		1,134		267		638
September 30	9,002		7,401		1,267		1,200		490		629
December 31	7,875		6,702		714		707		204		309

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
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	929	$	1,036	$	187	$	204	$	98	$	106
June 30	680		628		59		99		31		44
September 30	812		725		115		110		54		51
December 31	812		746		190		144		103		74

The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:



	Operating Revenues				Operating Income				Net Income
	2016		2015		2016		2015		2016		2015
Quarter ended:
March 31	$	1,249	$	1,185	$	274	$	230	$	115	$	90
June 30	1,286		1,148		324		243		145		99
September 30	1,497		1,376		389		327		37		149
December 31	1,223		1,196		217		217		80		87

Average Basic And Diluted Shares And Net Income Per Basic And Diluted Share



	Average Basic Shares Outstanding (in millions)		Net Income per Basic Share
	2016	2015	2016		2015
Quarter ended:
March 31	923	862	$	0.19	$	0.80
June 30	924	863	0.29		0.74
September 30	925	913	0.53		0.69
December 31	925	921	0.22		0.34
	Average Diluted Shares Outstanding (in millions)		Net Income per Diluted Share
	2016	2015	2016		2015
Quarter ended:
March 31	925	867	$	0.19	$	0.80
June 30	926	866	0.29		0.74
September 30	927	915	0.53		0.69
December 31	928	924	0.22		0.33

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:



	2016								2015
	Fourth Quarter		Third Quarter		Second Quarter		First Quarter		Fourth Quarter		Third Quarter		Second Quarter		First Quarter
High price	$	36.36	$	37.70	$	36.37	$	35.95	$	31.37	$	34.44	$	34.98	$	38.25
Low price	29.82		32.86		33.18		26.26		25.09		28.41		31.28		31.71
Close	35.49		33.29		36.36		35.86		27.77		29.70		31.42		33.61
Dividends	0.318		0.318		0.318		0.310		0.310		0.310		0.310		0.310

Significant Accounting Policies - Narrative (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	100.00%
Third Party interest in ComEd (less than $1 million)	$ 1,775,000,000	$ 1,308,000,000
Minimum expectation of tax position to be realized	50.00%
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%
Exelon Generation Co L L C [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Cost of spent nuclear fuel disposal per kWh of net nuclear generation	$ (0.001)
Development Costs, Period Cost	1,700,000,000	1,300,000,000
Utilities Operating Expense, Other	$ 13,000,000
Potomac Electric Power Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income		4,000,000	$ 1,000,000
Delmarva Power and Light Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income		1,000,000
Atlantic City Electric Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets				$ 12,000,000
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results		2,000,000	$ 1,000,000
Pepco Holdings LLC [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income		$ 34,000,000
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%

Significant Accounting Policies - Summary of Capitalized Software Costs (Details) - USD ($)

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

^[1]

$ 808,000,000

$ 633,000,000

^[1]

255,000,000

208,000,000

$ 186,000,000

New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income

34,000,000

^[1]

173,000,000

180,000,000

^[1]

72,000,000

73,000,000

59,000,000

213,000,000

172,000,000

62,000,000

47,000,000

45,000,000

91,000,000

86,000,000

33,000,000

28,000,000

164,000,000

178,000,000

44,000,000

46,000,000

43,000,000

New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income

4,000,000

1,000,000

1,000,000

(2,000,000)

2,000,000

New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Net Income

1,000,000

1,000,000

1,000,000

153,000,000

$ 153,000,000

$ 29,000,000

172,000,000

$ 8,000,000

$ 36,000,000

$ 30,000,000

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246RUU4RjBGOTk5MkM0QUIyMzlBMTQ5RjkyNUQxRkRBNjIM}

Significant Accounting Policies - Summary of Total Interest Incurred, Capitalized and Credits to AFUDC (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

^[1],[2]

$ 1,678

$ 1,170

$ 1,144

^[2]

108

^[2]

^[1],[2]

472

445

419

^[2]

107

^[2]

^[1]

469

336

323

^[1]

127

116

115

^[1]

114

113

118

137

131

121

$ 9

$ 68

289

277

$ 10

$ 23

$ 21

$ 207

$ 35

[1]	Successor PredecessorPHIMarch 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015 For the Year Ended December 31, 2014Total incurred interest(b)$207 $68 $289 $277Credits to AFUDC debt and equity35 10 23 21
[2]	Successor PredecessorPHIMarch 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015 For the Year Ended December 31, 2014Total incurred interest(b)$207 $68 $289 $277Credits to AFUDC debt and equity35 10 23 21

Significant Accounting Policies Balance Sheet Classification of Deferred Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Other noncurrent assets	$ 1,472	$ 1,445
Other noncurrent liabilities	1,827	1,491
Commonwealth Edison Co [Member]
Other noncurrent assets	325	324
Other noncurrent liabilities	529	507
Exelon Generation Co L L C [Member]
Other noncurrent assets	688	627
Other noncurrent liabilities	595	602
PECO Energy Co [Member]
Other noncurrent assets	20	21
Other noncurrent liabilities	85	90
Baltimore Gas and Electric Company [Member]
Other noncurrent assets	9	8
Other noncurrent liabilities	$ 61	$ 61

Variable Interest Entities - Narrative (Details)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Apr. 01, 2014

USD ($)

Mar. 23, 2016

USD ($)

Dec. 31, 2016

USD ($)

project

VIE

Dec. 31, 2016

USD ($)

project

VIE

Dec. 31, 2015

USD ($)

VIE

Dec. 31, 2014

USD ($)

Sep. 30, 2016

USD ($)

Jun. 09, 2015

USD ($)

Jul. 18, 2014

USD ($)

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Note Receivable

$ 27

Number of variable interest entities not consolidated by equity holders | VIE

Number of variable interest entities consolidated | VIE

Investments In Nonconsolidated Variable Interest Entities

$ 248

$ 11

Consolidated Variable Interest Entity [Abstract]

Variable Interest Entity, Reporting Entity Involvement, Maximum Loss Exposure, Amount

Equity Method Investment Variable Interest Entities [Member]

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Investments In Nonconsolidated Variable Interest Entities

248

$ 11

Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]

Consolidated Variable Interest Entity [Abstract]

Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]

$ 165

Consolidated Variable Interest Entity [Abstract]

Distributed Energy Company [Member]

245

Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests

250

$ 85

Equity Method Investment Variable Interest Entities [Member]

Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests

$ 172

Electricite De France LLC [Member] | Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]

Consolidated Variable Interest Entity [Abstract]

Electricite De France LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member]

145

Consolidated Variable Interest Entity [Abstract]

49.99%

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Number of variable interest entities consolidated | VIE

Consolidated Variable Interest Entity [Abstract]

^[1]

$ 0

Consolidated Variable Interest Entity [Abstract]

^[1]

$ 1

Consolidated Variable Interest Entity [Abstract]

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

$ 13

Consolidated Variable Interest Entity [Abstract]

Cash Remitted To VIE

$ 60

$ 55

Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]

Investments In Nonconsolidated Variable Interest Entities

Consolidated Variable Interest Entity [Abstract]

Wind project entities with noncontrolling equity interests | project

$ 21

Noncontrolling equity interest ownership percentage held by third parties

1.00%

Number of projects with significant economic power | project

Ownership interests in project entities

99.00%

Exelon Generation Co L L C [Member] | Other Severance Charges [Member]

^[1]

$ 13

Consolidated Variable Interest Entity [Abstract]

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]

Severance Obligation

$ 0

Consolidated Variable Interest Entity [Abstract]

Due from Affiliates

400

316

$ 316

Exelon Generation Co L L C [Member] | Equity Method Investment Variable Interest Entities [Member]

equity interest percentage sold

69.00%

Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests

$ 78

Consolidated Variable Interest Entity [Abstract]

Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member]

275

$ 275

Consolidated Variable Interest Entity [Abstract]

Business Acquisitions, Megawatts Acquired | MW

242

Exelon Generation Co L L C [Member] | AGE Biomass project [Member]

$ 568

Consolidated Variable Interest Entity [Abstract]

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]

Remeasurement gain from derecognition of equity method investment

$ 7

$ 275

$ 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]

Exelon Generation Co L L C [Member] | CENG [Member]

$ 637

Consolidated Variable Interest Entity [Abstract]

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

50.01%

equity interest percentage sold

71.00%

Consolidated Variable Interest Entity [Abstract]

Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage

100.00%

Ownership Percentage Of Consolidated Variable Interest Entities

100.00%

Consolidated Variable Interest Entity [Abstract]

Baltimore Gas and Electric Company [Member] | RSB Bond Co LLC [Member]

^[1]

$ 1

Consolidated Variable Interest Entity [Abstract]

Remittance of payments received from customers for rate stabilization to BondCo.

$ 86

$ 85

[1]	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.

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

Dec. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 635

$ 6,502

$ 1,878

$ 1,609

4,158

3,187

1,201

912

917

1,365

1,274

1,104

930

752

12,412

15,334

71,555

57,439

11,061

10,342

6,677

2,672

492

758

1,472

1,445

30,937

22,611

^[1]

114,904

95,384

2,430

1,500

3,441

2,883

3,460

2,376

282

205

407

100

981

842

13,457

9,118

31,575

23,645

9,111

8,585

4,248

3,385

830

117

1,827

1,491

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

87,292

68,062

150

164

100

371

219

140

199

181

908

882

5,415

5,160

2,185

2,036

315

7,985

7,386

8,893

8,268

181

111

269

216

119

115

674

472

641

666

1,904

1,999

106

2,682

2,792

3,356

3,264

290

431

780

1,258

158

123

2,433

2,095

558

360

917

1,365

935

880

701

535

6,528

6,342

25,585

25,843

11,061

10,342

476

733

688

627

14,861

14,344

^[2]

46,974

46,529

1,117

1,610

1,583

989

935

263

182

100

313

356

5,683

4,933

7,202

7,936

8,922

8,431

117

595

602

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

^[2]

33,718

33,559

150

164

371

219

140

199

181

870

854

5,415

5,160

2,185

2,036

277

7,947

7,381

8,817

8,235

269

216

116

113

589

386

540

623

1,904

1,999

106

2,581

2,749

3,170

3,135

395

300

102

112

842

845

7,040

6,597

822

853

^[3]

8,704

8,295

378

205

209

175

110

707

1,134

2,281

1,480

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

^[3]

5,856

5,418

122

$ 319

581

319

122

1,474

10,864

1,406

1,407

3,850

^[4]

16,188

456

404

266

2,327

4,823

466

200

^[4]

11,592

170

319

496

283

116

1,838

11,598

4,005

$ 0

7,589

^[4]

21,025

253

458

272

335

2,284

5,645

750

249

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

^[4]

13,009

124

124

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

172

101

101

143

101

$ 2

$ 3

125

156

242

399

546

2,521

2,322

537

519

^[5]

3,457

3,387

132

320

297

1,120

1,153

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

^[5]

2,423

2,387

124

124

$ 126

$ 172

[1]	Exelon’s consolidated assets include $8,893 million and $8,268 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,356 million and $3,264 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	Generation’s consolidated assets include $8,817 million and $8,235 million at December 31, 2016 and 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,170 million and $3,135 million at December 31, 2016 and 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[3]	BGE’s consolidated assets include $26 million and $26 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million and $122 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.
[4]	PHI’s consolidated total assets include $49 million and $30 million at December 31, 2016 and 2015, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $143 million and $172 million at December 31, 2016 and 2015, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities.
[5]	ACE’s consolidated assets include $32 million and $30 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $126 million and $172 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities.

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2016

Dec. 31, 2015

Total assets

$ 1,205

$ 427

502

147

Other ownership interests

248

455

269

113

206

Commercial Agreement Variable Interest Entities [Member]

113

206

Total assets

638

263

215

Other ownership interests

423

241

Equity Method Investment Variable Interest Entities [Member]

Total assets

567

164

287

125

Other ownership interests

248

Investments [Member]

Investments [Member] | Commercial Agreement Variable Interest Entities [Member]

264

Investments [Member] | Equity Method Investment Variable Interest Entities [Member]

Contract Intangible Asset [Member]

264

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]

Asset Held In Trust Noncurrent [Member] | Equity Method Investment Variable Interest Entities [Member]

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

Asset Retirement Obligations, Noncurrent

113

206

^[1]

$ 104

$ 189

[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.

Regulatory Matters - Narrative (Details)
GWh in Millions

1 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

60 Months Ended

65 Months Ended

Dec. 31, 2030

Jan. 02, 2018

GWh

Jul. 29, 2016

USD ($)

Nov. 30, 2015

MWh

Nov. 06, 2015

USD ($)

Sep. 10, 2015

USD ($)

May 27, 2015

USD ($)

May 07, 2015

USD ($)

Mar. 27, 2015

USD ($)

Sep. 15, 2014

USD ($)

Aug. 21, 2014

USD ($)

Mar. 15, 2013

USD ($)

Dec. 05, 2012

Nov. 01, 2012

MWh

Jul. 31, 2012

USD ($)

Apr. 30, 2012

Mar. 31, 2013

USD ($)

Aug. 31, 2010

USD ($)

smart_meter

Mar. 31, 2017

USD ($)

Dec. 31, 2016

USD ($)

smart_meter

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Mar. 23, 2016

USD ($)

Dec. 31, 2014

USD ($)

Sep. 30, 2014

USD ($)

Jun. 30, 2014

USD ($)

Dec. 31, 2008

USD ($)

Jun. 30, 2016

USD ($)

Dec. 31, 2016

USD ($)

smart_meter

Dec. 31, 2017

Dec. 31, 2016

USD ($)

smart_meter

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2013

Dec. 31, 2007

USD ($)

Nov. 30, 2010

USD ($)

Nov. 30, 2005

USD ($)

Jun. 01, 2019

Jun. 01, 2018

Jun. 01, 2017

Jun. 03, 2016

USD ($)

Mar. 31, 2015

USD ($)

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 14,000,000

$ 90,000,000

138

(50)

$ 269

11,388,000,000

6,824,000,000

10,046,000,000

6,065,000,000

602,000,000

369,000,000

^[1],[2]

143,000,000

87,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

4,789,000,000

4,570,000,000

128,000,000

96,000,000

220,000,000

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

513,000,000

$ 137,000,000

513,000,000

72,000,000

55,000,000

Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Over Recovered Energy And Transmission Costs [Member]

185,000,000

92,000,000

Regulatory Matters Additional Narrative Information [Line Items]

134,000,000

$ 134,000,000

131,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Subsequent contribution to technology innovation trust

$ 4,000,000

Utility annual customer assistance

$ 10,000,000

Term of contract

20 years

Low income sector consumption reduction targets Act 129 Phase II

0.10%

Renewable energy resources cumulatively increase

1.50%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 90,000,000

68,000,000

36,000,000

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

(4,000,000)

(18,000,000)

14,000,000

1,167,000,000

1,113,000,000

Rate of return on common equity in federal energy regulatory committee complaint

977,000,000

$ 977,000,000

895,000,000

11.50%

329,000,000

$ 329,000,000

155,000,000

^[2],[3]

(6,000,000)

9,000,000

Customer refundable fees, interest

3,698,000,000

3,614,000,000

1,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

(94,000,000)

(86,000,000)

(22,000,000)

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 91,000,000

$ 34,000,000

$ 78,000,000

Public Utilities, Requested Equity Capital Structure, Percentage

8.47%

8.61%

8.62%

Public Utilities, Requested Return on Equity, Percentage

11.50%

Public Utilities, Interim Rate Increase (Decrease), Amount

$ (8,000,000)

SocialCarbonCost

16.50

NuclearFacilityPurchaseAmount

0.16

LowIncomeEnergyAssistanceContributionAnnual

$ 10,000,000

LowIncomeEnergyAssistanceContributionLength

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

5,000,000

$ 5,000,000

$ 6,000,000

Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member]

141,000,000

52,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Renewable energy Requirements [Member]

60,000,000

53,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Over Recovered Electric Supply Cost [Member]

30,000,000

24,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Commonwealth Edison Co [Member] | Electric Distribution [Member]

30,000,000

$ 30,000,000

30,000,000

29,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

134

$ 160

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

$ 18,000,000

$ (127)

$ 67

$ (232)

Public Utilities, Approved Return on Equity, Percentage

8.59%

9.09%

9.20%

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 7

$ 152

$ (72)

Public Utilities, Requested Equity Capital Structure, Percentage

6.71%

7.05%

7.06%

Public Utilities, Requested Return on Equity, Percentage

8.64%

9.14%

9.25%

Commonwealth Edison Co [Member] | Energy Related Derivative [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Term of contract

20 years

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

Regulatory Matters Additional Narrative Information [Line Items]

EnergyEfficiencyAnnualCumulativeSavings

21.50%

6.60%

RenewableEnergyRetailLoad

100.00%

Commonwealth Edison Co [Member] | Minimum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Renewable energy resources cumulatively increase

11.50%

FutureEnergyEfficiencySpending

$ 250,000,000

EnergyEfficiencyROEAdjustment

20000.00%

Commonwealth Edison Co [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Renewable energy resources cumulatively increase

25.00%

FutureEnergyEfficiencySpending

$ 400,000,000

ResidentialCustomerRateIncrease

25.00%

CommercialAndIndustrialCustomerRateIncrease

1.30%

Commonwealth Edison Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

CumulativeAnnualEnergyEfficiencyGoal | GWh

Regulatory Matters Additional Narrative Information [Line Items]

Low income sector consumption reduction targets Act 129 Phase II

4.50%

Smart meters initial phase deployment | smart_meter

1,600,000.0

Estimated number of smart meters to be installed | smart_meter

1,700,000

Total smart grid smart meter investment grant awarded

$ 200,000,000

Total smart meter spend on investment

578,000,000

Total smart grid spend on investment

155,000,000

Smart grid investment grant awarded

$ 275,000,000

$ 534,000,000

Cumulative consumption reduction targets | MWh

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

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 127,000,000

$ 190,000,000

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

10.95%

1,710,000,000

$ 1,617,000,000

1,681,000,000

1,583,000,000

127,000,000

112,000,000

^[2]

5,000,000

4,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

644,000,000

639,000,000

11,000,000

13,000,000

$ 0

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

PECO Energy Co [Member] | Over Recovered NonBypassable Transmission Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]

10,000,000

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member]

41,000,000

40,000,000

Regulatory Matters Additional Narrative Information [Line Items]

PECO Energy Co [Member] | Minimum [Member]

56,000,000

60,000,000

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%

Regulatory Matters Additional Narrative Information [Line Items]

Increase in electric delivery service revenue resulting from rate case settlement or order.

22,000,000

Increase in gas delivery service revenue resulting from rate case settlement or order.

38,000,000

Estimated number of smart meters to be installed | smart_meter

2,000,000

Projected investment in smart meters

$ 104,000,000

37,000,000

Annual depreciation expense decrease regulated property

$ 20,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

12,000,000

9,000,000

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

$ (68,000,000)

$ (99,000,000)

(3,000,000)

3,000,000

(5,000,000)

Total projected smart meter smart grid spend

712,000,000

781,000,000

$ 480,000,000

Reimbursements received from the DOE

$ 200,000,000

Customer Refund Liability, Noncurrent

504,000,000

514,000,000

$ 30,000,000

50,000,000

38,000,000

Site contingency, recovery from third party of environmental remediation cost

^[2],[3]

(1,000,000)

5,000,000

$ 1,000,000

$ 5,000,000

Deferred costs, noncurrent

160,000,000

$ 160,000,000

222,000,000

$ 16,000,000

$ 8,000,000

Rate cap imposed on public utility subsidiary

15.00%

Deferred purchased power costs

$ 306,000,000

Environmental costs recognized, recovery credited to expense

$ 81,000,000

73,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

(28,000,000)

(10,000,000)

(17,000,000)

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 86,000,000

$ 9,000,000

$ 25,000,000

Public Utilities, Requested Equity Capital Structure, Percentage

8.09%

8.46%

8.53%

Public Utilities, Requested Return on Equity, Percentage

10.50%

11.30%

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

57,000,000

$ 57,000,000

$ 49,000,000

Baltimore Gas and Electric Company [Member] | Abandonment costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

9,000,000

19,000,000

Baltimore Gas and Electric Company [Member] | Under Recovered Decoupling Revenue [Member]

18,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Over Recovered Transmission Costs [Member]

2,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Over-Recovered Natural Gas Costs [Member]

14,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Gas Revenue [Member]

5,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Electric Revenue [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Baltimore Gas and Electric Company [Member] | Under-Recovered Electric Revenue Decoupling [Member]

30,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

116,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (44,000,000)

Public Utilities, Requested Return on Equity, Percentage

9.80%

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

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

78,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ (48,000,000)

Public Utilities, Requested Return on Equity, Percentage

9.70%

Regulatory Matters Additional Narrative Information [Line Items]

Customer Refund Liability, Noncurrent

14,000,000

90,000,000

20,000,000

Unregulated Operating Revenue

^[2]

37,000,000

24,000,000

101,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

50,000,000

82,000,000

$ 61,000,000

Exelon Generation Co L L C [Member] | Conowingo [Member]

Regulatory Matters Additional Narrative Information [Line Items]

License costs

28,000,000

Regulatory Matters Additional Narrative Information [Line Items]

^[2],[3]

28,000,000

3,000,000

$ 444,000,000

Regulatory Matters Additional Narrative Information [Line Items]

2,582,000,000

2,277,000,000

66,000,000

^[3]

$ 29,000,000

19,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

213,000,000

$ 11,000,000

6,000,000

28,000,000

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

4,000,000

Pepco Holdings LLC [Member] | Predecessor [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Predecessor [Member] | Over Recovered Energy And Transmission Costs [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

27,000,000

Regulatory Matters Additional Narrative Information [Line Items]

3,504,000,000

2,851,000,000

79,000,000

^[3]

69,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

237,000,000

21,000,000

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

323,000,000

10,000,000

Pepco Holdings LLC [Member] | Successor [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Pepco Holdings LLC [Member] | Successor [Member] | Over Recovered Energy And Transmission Costs [Member]

3,000,000

Regulatory Matters Additional Narrative Information [Line Items]

18,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Rate of return on common equity

10.60%

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 66,000,000

8,000,000

15,000,000

4,000,000

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

(57,000,000)

10,000,000

1,000,000

(6,000,000)

348,000,000

371,000,000

Public Utilities, Approved Return on Equity, Percentage

289,000,000

299,000,000

0.00%

43,000,000

49,000,000

^[2]

20,000,000

2,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

140,000,000

160,000,000

14,000,000

(12,000,000)

(25,000,000)

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 12,000,000

$ 3,000,000

$ 8,000,000

Public Utilities, Requested Return on Equity, Percentage

10.50%

11.30%

Public Utilities, Interim Rate Increase (Decrease), Amount

86,000,000

$ 86,000,000

$ 2,500,000

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

4,000,000

$ 3,000,000

Delmarva Power and Light Company [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power and Light Company [Member] | Over Recovered Energy And Transmission Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power and Light Company [Member] | Over Recovered Transmission Costs [Member]

5,000,000

19,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power and Light Company [Member] | Over-Recovered Natural Gas Costs [Member]

3,000,000

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power and Light Company [Member] | Over Recovered Electric Supply Cost [Member]

4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Delmarva Power and Light Company [Member] | Electric Distribution [Member]

2,000,000

4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 39,000,000

63,000,000

$ 15,000,000

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

9.70%

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

(30,000,000)

Delmarva Power and Light Company [Member] | Gas Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Increase in gas delivery service revenue resulting from rate case settlement or order.

0.14

Public Utilities, Requested Rate Increase (Decrease), Amount

22,000,000

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

(10,000,000)

Delmarva Power and Light Company [Member] | Minimum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Projected investment in smart grid infrastructure

5,000,000

Delmarva Power and Light Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Projected investment in smart grid infrastructure

$ 9,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

2,000,000

10,000,000

$ (9,000,000)

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

9.55%

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

10,000,000

3,000,000

1,000,000

852,000,000

801,000,000

690,000,000

661,000,000

11,000,000

15,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

31,000,000

44,000,000

23,000,000

(5,000,000)

(7,000,000)

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 27,000,000

$ 1,000,000

$ 10,000,000

Public Utilities, Requested Return on Equity, Percentage

10.50%

11.30%

Power Plant Output | MW

661

Capital ProjectFundedByBonds

$ 375,000,000

CapitalProjectFundedByEntity

500,000,000

CapitalProjectFundedByAgency

$ 125,000,000

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

126,000,000

$ 126,000,000

6,000,000

$ 1,000,000

Potomac Electric Power Company [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Over Recovered Energy And Transmission Costs [Member]

3,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Over Recovered Transmission Costs [Member]

8,000,000

16,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Over Recovered Electric Supply Cost [Member]

5,000,000

14,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Potomac Electric Power Company [Member] | Electric Distribution [Member]

3,000,000

2,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

53,000,000

86,000,000

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

$ (82,000,000)

Public Utilities, Approved Return on Equity, Percentage

10.60%

Potomac Electric Power Company [Member] | Subsequent Event [Member] | Electric Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

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

$ (77,000,000)

Potomac Electric Power Company [Member] | Minimum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Power Plant Output | MW

650

Potomac Electric Power Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Power Plant Output | MW

700

Proposed Capital Expenditure

$ 0.105

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

8,000,000

10,000,000

$ 4,000,000

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

14,000,000

(2,000,000)

(3,000,000)

$ 501,000,000

501,000,000

512,000,000

405,000,000

414,000,000

25,000,000

18,000,000

^[2]

19,000,000

1,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

25,000,000

6,000,000

(12,000,000)

(7,000,000)

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 11,000,000

$ 3,000,000

$ 9,000,000

Public Utilities, Requested Return on Equity, Percentage

10.50%

11.30%

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

111,000,000

$ 111,000,000

$ 0

Atlantic City Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Over Recovered Transmission Costs [Member]

5,000,000

8,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Atlantic City Electric Company [Member] | Over Recovered Electric Supply Cost [Member]

4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

(45,000,000)

Public Utilities, Interim Rate Increase (Decrease), Amount

1,000,000

19,000,000

$ 9,000,000

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

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Interim Rate Increase (Decrease), Amount

$ 29,000,000

Deferred Project Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | Commonwealth Edison Co [Member]

8,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | PECO Energy Co [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | Baltimore Gas and Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | Delmarva Power and Light Company [Member]

8,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Rate of return on common equity

12.95%

Deferred Project Costs [Member] | Potomac Electric Power Company [Member]

8,000,000

$ 41,000,000

8,000,000

13,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Project Costs [Member] | Atlantic City Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under-Recovered Non-Bypassable Transmission Costs [Member] | PECO Energy Co [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Regulatory Matters Additional Narrative Information [Line Items]

1,000,000

Advanced Metering Infrastructure Costs [Member] | Baltimore Gas and Electric Company [Member]

23,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Advanced Metering Infrastructure Costs [Member] | Potomac Electric Power Company [Member] | Electric Distribution [Member]

144,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

3,000,000

Over-Recovered Natural Gas Costs [Member] | Baltimore Gas and Electric Company [Member]

13,000,000

Other Income

10,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Abandonment costs [Member] | Baltimore Gas and Electric Company [Member]

3,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Abandonment costs [Member] | Delmarva Power and Light Company [Member]

3,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Abandonment costs [Member] | Potomac Electric Power Company [Member]

3,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

UnderRecoveredElectricEnergyCosts [Member] | Delmarva Power and Light Company [Member]

28,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

4,000,000

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

TransmissionCost [Member] | Commonwealth Edison Company [Member]

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

15,000,000

31,000,000

Regulatory Matters Additional Narrative Information [Line Items]

TransmissionCost [Member] | Delmarva Power and Light Company [Member]

4,000,000

12,000,000

Regulatory Matters Additional Narrative Information [Line Items]

TransmissionCost [Member] | Potomac Electric Power Company [Member]

1,000,000

7,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

5,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member]

6,000,000

2,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Commonwealth Edison Co [Member]

188,000,000

189,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Net regulatory assets

188,000,000

189,000,000

188,000,000

189,000,000

Under Recovered Distribution Service Costs [Member] | Commonwealth Edison Co [Member] | Electric Distribution [Member]

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | PECO Energy Co [Member]

134,000,000

142,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Baltimore Gas and Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Delmarva Power and Light Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Potomac Electric Power Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Atlantic City Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Commonwealth Edison Co [Member]

621,000,000

279,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | PECO Energy Co [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Baltimore Gas and Electric Company [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

285,000,000

278,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Pepco Holdings LLC [Member] | Successor [Member]

401,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Delmarva Power and Light Company [Member]

335,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Potomac Electric Power Company [Member]

85,000,000

111,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Atlantic City Electric Company [Member]

250,000,000

289,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Non-severance Merger Integration Costs [Member]

$ 0

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

4,000,000

Pension and Other Postretirement Benefits [Member] | Baltimore Gas and Electric Company [Member]

5 years

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member]

12 years

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Commonwealth Edison Co [Member]

305,000,000

$ 305,000,000

286,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | PECO Energy Co [Member]

278,000,000

255,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Baltimore Gas and Electric Company [Member]

26,000,000

30,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Delmarva Power and Light Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Potomac Electric Power Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Environmental Restoration Costs [Member] | Atlantic City Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Electric Energy And Transmission Costs [Member] | Commonwealth Edison Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Regulatory Matters Additional Narrative Information [Line Items]

5,000,000

AMI Expenses [Member]

AMI Expenses [Member] | Commonwealth Edison Co [Member]

701,000,000

399,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | PECO Energy Co [Member]

164,000,000

140,000,000

Regulatory Matters Additional Narrative Information [Line Items]

49,000,000

$ 49,000,000

63,000,000

AMI Expenses [Member] | Baltimore Gas and Electric Company [Member]

10 years

Regulatory Matters Additional Narrative Information [Line Items]

Amount of Impairment to Carrying Amount of Regulatory Assets

52,000,000

$ 52,000,000

230,000,000

196,000,000

AMI Expenses [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

230,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Pepco Holdings LLC [Member] | Successor [Member]

267,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Delmarva Power and Light Company [Member]

258,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Potomac Electric Power Company [Member]

84,000,000

87,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Atlantic City Electric Company [Member]

174,000,000

180,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

25,000,000

$ 25,000,000

6,000,000

Merger Integration Costs [Member] | Commonwealth Edison Co [Member]

5 years

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | PECO Energy Co [Member]

$ 0

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Baltimore Gas and Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

10,000,000

$ 6,000,000

10,000,000

6,000,000

$ 4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Delmarva Power and Light Company [Member]

15,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Potomac Electric Power Company [Member]

4,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Atlantic City Electric Company [Member]

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Commonwealth Edison Co [Member]

89,000,000

84,000,000

Regulatory Matters Additional Narrative Information [Line Items]

23,000,000

43,000,000

Under Recovered Energy And Transmission Costs [Member] | PECO Energy Co [Member]

8,000,000

7,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Baltimore Gas and Electric Company [Member]

1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

38,000,000

40,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Pepco Holdings LLC [Member] | Successor [Member]

33,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Delmarva Power and Light Company [Member]

28,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Potomac Electric Power Company [Member]

5,000,000

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Atlantic City Electric Company [Member]

6,000,000

9,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Legacy AMI [Member] | Baltimore Gas and Electric Company [Member]

17,000,000

13,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Legacy AMI [Member] | Delmarva Power and Light Company [Member]

54,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Recoverable Smart Meter Related Costs [Member] | Baltimore Gas and Electric Company [Member]

14,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Recoverable Smart Meter Related Costs [Member] | Delmarva Power and Light Company [Member]

32,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

41,000,000

Regulatory Matters Additional Narrative Information [Line Items]

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

54,000,000

47,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Income Tax Transmission Related [Member] | Commonwealth Edison Co [Member]

20,000,000

36,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Income Tax Transmission Related [Member] | Baltimore Gas and Electric Company [Member]

22,000,000

15,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Income Tax Transmission Related [Member] | Delmarva Power and Light Company [Member]

38,000,000

16,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Income Tax Transmission Related [Member] | Potomac Electric Power Company [Member]

20,000,000

18,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Deferred Income Tax Transmission Related [Member] | Atlantic City Electric Company [Member]

31,000,000

26,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Accelerated Depreciation Costs of Non AMI Meters [Member] | Commonwealth Edison Co [Member]

19,000,000

15,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Non Utility Deferral [Member] | Atlantic City Electric Company [Member] | Electric Distribution [Member]

162,000,000

$ 162,000,000

$ 137,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Increase (Decrease) in Other Regulatory Assets

10,000,000

Uncollectible deferral Balance [Member] | Atlantic City Electric Company [Member] | Electric Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Increase (Decrease) in Other Regulatory Assets

$ 7,000,000

[1]	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.
[2]	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.
[3]	, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million, $4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.

Regulatory Matters - Estimated Commitments related to PJM Agreements (Details) - USD ($) $ in Millions	Dec. 31, 2016	Jun. 30, 2016	Mar. 31, 2016
Other Commitments [Line Items]
Total	$ 513	$ 137
Pepco Holdings LLC [Member]
Other Commitments [Line Items]
Total			$ 444
Pepco Holdings LLC [Member] \| Successor [Member]
Other Commitments [Line Items]
Total	323
Potomac Electric Power Company [Member]
Other Commitments [Line Items]
Total	126
Delmarva Power and Light Company [Member]
Other Commitments [Line Items]
Total	86
Atlantic City Electric Company [Member]
Other Commitments [Line Items]
Total	111
Construction Expansion Plans [Member] \| Commonwealth Edison Co [Member]
Other Commitments [Line Items]
Total	97
2015	64
2016	28
2017	5
2018	0
2019	0
Construction Expansion Plans [Member] \| PECO Energy Co [Member]
Other Commitments [Line Items]
Total	34
2015	14
2016	10
2017	7
2018	2
2019	1
Construction Expansion Plans [Member] \| Baltimore Gas and Electric Company [Member]
Other Commitments [Line Items]
Total	226
2015	113
2016	55
2017	44
2018	14
2019	0
Construction Expansion Plans [Member] \| Potomac Electric Power Company [Member]
Other Commitments [Line Items]
Total	104
2015	6
2016	39
2017	40
2018	19
2019	0
Construction Expansion Plans [Member] \| Delmarva Power and Light Company [Member]
Other Commitments [Line Items]
Total	63
2015	47
2016	16
2017	0
2018	0
2019	0
Construction Expansion Plans [Member] \| Atlantic City Electric Company [Member]
Other Commitments [Line Items]
Total	93
2015	36
2016	39
2017	18
2018	0
2019	$ 0

Regulatory Matters - Purchase of Receivables Programs (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2016

$ 313

$ 229

(37)

(31)

$ (37)

276

198

276

103

(14)

(16)

(14)

$ 73

Purchase of Receivables, Discount Rate related to Implementation Costs

1.00%

^[1]

(6)

(7)

$ (6)

^[1]

^[2]

(4)

(8)

(4)

100

(13)

(6)

(13)

(7)

(4)

(7)

(2)

(4)

(2)

(4)

$ 18

$ 17

$ 18

[1]	(a)For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff.
[2]	PECO’s natural gas POR program became effective on January 1, 2012 and included 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.

Regulatory Matters Annual Electric Distribution Filings (Details) - USD ($)	3 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 138	$ (50)	$ 269
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 90,000,000	$ 68,000,000	$ 36,000,000
Public Utilities, Requested Equity Capital Structure, Percentage		8.47%	8.61%	8.62%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount		$ 4,000,000	$ 18,000,000	$ (14,000,000)
Public Utilities, Approved Rate Increase (Decrease), Amount		94,000,000	$ 86,000,000	$ 22,000,000
Public Utilities, Requested Return on Equity, Percentage			11.50%	11.50%
Electric Distribution [Member] \| Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount		$ 134	$ 85	$ 160
Public Utilities, Requested Equity Capital Structure, Percentage		6.71%	7.05%	7.06%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount	$ (18,000,000)	$ 127	$ (67)	$ 232
Public Utilities, Approved Equity Capital Structure, Percentage		6.69%	7.02%	7.04%
Public Utilities, Approved Rate Increase (Decrease), Amount		$ (7)	$ (152)	$ 72
Public Utilities, Approved Return on Equity, Percentage		8.59%	9.09%	9.20%
Public Utilities, Requested Return on Equity, Percentage		8.64%	9.14%	9.25%

Regulatory Matters Annual Electric Transmission Filings (Details) - USD ($)				1 Months Ended	3 Months Ended					6 Months Ended	12 Months Ended
	Jul. 29, 2016	Nov. 06, 2015	Sep. 15, 2014	Mar. 31, 2013	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 138	$ (50)	$ 269
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 90,000,000	$ 68,000,000	$ 36,000,000
Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint											11.50%
Public Utilities, Requested Equity Capital Structure, Percentage											8.47%	8.61%	8.62%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount											$ 4,000,000	$ 18,000,000	$ (14,000,000)
Public Utilities, Approved Rate Increase (Decrease), Amount											$ 94,000,000	$ 86,000,000	$ 22,000,000
Public Utilities, Requested Return on Equity, Percentage												11.50%	11.50%
Cap on Equity Component of Rate of Return on Common Equity in Federal Energy Regulatory Committee Complaint											55.00%
Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 12,000,000	$ 0	$ 9,000,000
Public Utilities, Requested Equity Capital Structure, Percentage											8.09%	8.46%	8.53%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 68,000,000					$ 99,000,000			$ 3,000,000	$ (3,000,000)	$ 5,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount											$ 28,000,000	$ 10,000,000	$ 17,000,000
Public Utilities, Requested Return on Equity, Percentage											10.50%	11.30%	11.30%
Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 2,000,000	$ 10,000,000	$ (9,000,000)
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount										9.55%
Public Utilities, Approved Equity Capital Structure, Percentage											7.88%	8.36%	8.60%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount											$ (10,000,000)	$ (3,000,000)	$ (1,000,000)
Public Utilities, Approved Rate Increase (Decrease), Amount											(23,000,000)	5,000,000	7,000,000
Current Year Revenue Adjustment											$ (15,000,000)	$ (2,000,000)	$ 17,000,000
Public Utilities, Requested Return on Equity, Percentage											10.50%	11.30%	11.30%
Delmarva Power and Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount						$ 66,000,000					$ 8,000,000	$ 15,000,000	$ 4,000,000
Public Utilities, Approved Return on Equity, Percentage							0.00%
Public Utilities, Approved Equity Capital Structure, Percentage											7.21%	7.80%	8.05%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount						$ 57,000,000					$ (10,000,000)	$ (1,000,000)	$ 6,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount											(14,000,000)	12,000,000	25,000,000
Current Year Revenue Adjustment											$ (12,000,000)	$ (2,000,000)	$ 15,000,000
Public Utilities, Requested Return on Equity, Percentage											10.50%	11.30%	11.30%
Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 8,000,000	$ 10,000,000	$ 4,000,000
Public Utilities, Approved Equity Capital Structure, Percentage											7.83%	8.51%	8.66%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount											$ (14,000,000)	$ 2,000,000	$ 3,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount											(6,000,000)	12,000,000	7,000,000
Current Year Revenue Adjustment											$ 0	$ 0	$ 0
Public Utilities, Requested Return on Equity, Percentage											10.50%	11.30%	11.30%
Electric Distribution [Member] \| Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 134	$ 85	$ 160
Public Utilities, Approved Return on Equity, Percentage											8.59%	9.09%	9.20%
Public Utilities, Requested Equity Capital Structure, Percentage											6.71%	7.05%	7.06%
Public Utilities, Approved Equity Capital Structure, Percentage											6.69%	7.02%	7.04%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount					$ (18,000,000)						$ 127	$ (67)	$ 232
Public Utilities, Approved Rate Increase (Decrease), Amount											$ (7)	$ (152)	$ 72
Public Utilities, Requested Return on Equity, Percentage											8.64%	9.14%	9.25%
Electric Distribution [Member] \| Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 116,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 44,000,000
Public Utilities, Requested Return on Equity, Percentage		9.80%
Electric Distribution [Member] \| Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount					$ 53,000,000		$ 86,000,000
Public Utilities, Approved Return on Equity, Percentage					10.60%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount					$ 82,000,000
Electric Distribution [Member] \| Delmarva Power and Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount				$ 39,000,000			63,000,000		$ 15,000,000
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount									9.70%
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount							$ 30,000,000
Electric Distribution [Member] \| Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount											$ 45,000,000

Mergers, Acquisitions and Dispositions - Narrative (Details) - USD ($)

3 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

Jun. 16, 2016

Dec. 31, 2014

Dec. 31, 2017

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Jun. 30, 2016

Dec. 31, 2016

Dec. 31, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Sep. 01, 2016

Mar. 24, 2016

Business Combination, Contingent Consideration, Asset

$ 235,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets

$ 6,934,000,000

$ 40,000,000

$ 386,000,000

$ 1,441,000,000

^[1],[2]

143,000,000

87,000,000

Share price

$ 27.25

$ 513,000,000

$ 137,000,000

$ 513,000,000

513,000,000

7,875,000,000

$ 9,002,000,000

6,910,000,000

$ 7,573,000,000

$ 6,702,000,000

$ 7,401,000,000

$ 6,514,000,000

$ 8,830,000,000

31,360,000,000

29,447,000,000

27,429,000,000

1,204,000,000

2,250,000,000

1,820,000,000

558,000,000

44,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent

22,000,000

$ 3,447,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets

248,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

4,005,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

1,515,000,000

Total net assets

7,142,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt

5,636,000,000

Other Intangible Assets [Member]

Finite-lived Intangible Assets Acquired

1,500,000,000

Business Combination, Contingent Consideration, Asset

163,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets

293,000,000

40,000,000

386,000,000

$ 390,000,000

390,000,000

Gain (Loss) on Disposition of Property Plant Equipment

^[2]

37,000,000

24,000,000

69,000,000

10,000,000

32,000,000

Proceeds from Sale of Productive Assets

$ 37,000,000

4,388,000,000

5,035,000,000

3,589,000,000

4,739,000,000

4,294,000,000

4,768,000,000

4,232,000,000

5,840,000,000

17,751,000,000

19,135,000,000

17,393,000,000

558,000,000

1,340,000,000

1,019,000,000

53,000,000

44,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent

(16,000,000)

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

50,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

(110,000,000)

Asset Impairment Charges

23,000,000

^[2],[3]

(1,000,000)

5,000,000

812,000,000

680,000,000

929,000,000

746,000,000

725,000,000

628,000,000

1,036,000,000

3,233,000,000

3,135,000,000

3,165,000,000

294,000,000

288,000,000

211,000,000

Baltimore Gas and Electric Company [Member] | Regulatory Assets [Member]

6,000,000

^[2],[3]

(6,000,000)

9,000,000

5,000,000

158,000,000

7,000,000

158,000,000

7,000,000

5,000,000

1,223,000,000

1,497,000,000

1,286,000,000

1,249,000,000

1,196,000,000

1,376,000,000

1,148,000,000

1,185,000,000

5,254,000,000

4,905,000,000

4,564,000,000

80,000,000

37,000,000

145,000,000

115,000,000

87,000,000

149,000,000

99,000,000

90,000,000

378,000,000

426,000,000

408,000,000

Commonwealth Edison Co [Member] | Regulatory Assets [Member]

8,000,000

^[2]

5,000,000

4,000,000

701,000,000

788,000,000

664,000,000

841,000,000

645,000,000

740,000,000

661,000,000

985,000,000

2,994,000,000

3,032,000,000

3,094,000,000

438,000,000

378,000,000

352,000,000

^[2],[3]

28,000,000

3,000,000

Pepco Holdings LLC [Member] | Regulatory Assets [Member]

444,000,000

16,000,000

Gain (Loss) on Disposition of Property Plant Equipment

33,000,000

37,000,000

$ 8,000,000

9,000,000

126,000,000

491,000,000

635,000,000

509,000,000

551,000,000

488,000,000

592,000,000

504,000,000

545,000,000

2,186,000,000

2,129,000,000

2,055,000,000

42,000,000

187,000,000

171,000,000

125,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

1,700,000,000

Potomac Electric Power Company [Member] | Regulatory Assets [Member]

11,000,000

Gain (Loss) on Disposition of Property Plant Equipment

^[2]

20,000,000

2,000,000

5,000,000

4,000,000

86,000,000

303,000,000

331,000,000

281,000,000

362,000,000

296,000,000

314,000,000

271,000,000

421,000,000

1,277,000,000

1,302,000,000

1,282,000,000

(9,000,000)

76,000,000

104,000,000

82,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

1,100,000,000

Delmarva Power and Light Company [Member] | Regulatory Assets [Member]

4,000,000

^[2]

19,000,000

1,000,000

111,000,000

$ 111,000,000

111,000,000

$ 275,000,000

421,000,000

270,000,000

291,000,000

386,000,000

285,000,000

334,000,000

1,257,000,000

1,295,000,000

1,210,000,000

(42,000,000)

40,000,000

46,000,000

110,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

1,200,000,000

Preferred Stock [Member]

Deferred Compensation, Share-based Payments [Member] | Pepco Holdings LLC [Member]

180,000,000

^[4]

$ 29,000,000

Minimum [Member]

20.00%

Maximum [Member]

50.00%

^[3]

29,000,000

$ 19,000,000

1,153,000,000

$ 1,126,000,000

$ 1,336,000,000

$ 1,119,000,000

$ 1,354,000,000

4,935,000,000

4,808,000,000

19,000,000

327,000,000

242,000,000

$ 0

Business Combination, Contingent Consideration, Asset

$ 400,000,000

^[5]

$ 400,000,000

^[5]

400,000,000

^[5]

$ 235,000,000

^[3]

69,000,000

Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent

323,000,000

35,000,000

1,078,000,000

1,394,000,000

$ 1,066,000,000

$ 105,000,000

^[6]

3,643,000,000

(61,000,000)

Workforce Development [Member]

317,000,000

Workforce Development [Member] | Potomac Electric Power Company [Member]

24,000,000

Workforce Development [Member] | Delmarva Power and Light Company [Member]

Workforce Development [Member] | Atlantic City Electric Company [Member]

Workforce Development [Member] | Successor [Member] | Pepco Holdings LLC [Member]

Charitable Contributions [Member]

Charitable Contributions [Member] | Potomac Electric Power Company [Member]

50,000,000

Charitable Contributions [Member] | Delmarva Power and Light Company [Member]

28,000,000

Charitable Contributions [Member] | Atlantic City Electric Company [Member]

12,000,000

Charitable Contributions [Member] | Successor [Member] | Pepco Holdings LLC [Member]

10,000,000

Energy Efficiency Program [Member]

50,000,000

Energy Efficiency Program [Member] | Potomac Electric Power Company [Member]

111,000,000

Energy Efficiency Program [Member] | Delmarva Power and Light Company [Member]

Energy Efficiency Program [Member] | Atlantic City Electric Company [Member]

Energy Efficiency Program [Member] | Successor [Member] | Pepco Holdings LLC [Member]

Rate Bill Credits [Member]

Rate Bill Credits [Member] | Potomac Electric Power Company [Member]

259,000,000

Rate Bill Credits [Member] | Delmarva Power and Light Company [Member]

91,000,000

Rate Bill Credits [Member] | Atlantic City Electric Company [Member]

67,000,000

Rate Bill Credits [Member] | Successor [Member] | Pepco Holdings LLC [Member]

101,000,000

Commitments [Member] | Potomac Electric Power Company [Member]

259,000,000

Commitments [Member] | Delmarva Power and Light Company [Member]

73,000,000

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

46,000,000

Delivery System Modernization [Member]

49,000,000

Delivery System Modernization [Member] | Potomac Electric Power Company [Member]

22,000,000

Delivery System Modernization [Member] | Delmarva Power and Light Company [Member]

Delivery System Modernization [Member] | Atlantic City Electric Company [Member]

Delivery System Modernization [Member] | Successor [Member] | Pepco Holdings LLC [Member]

Green Sustainability Fund [Member]

Green Sustainability Fund [Member] | Potomac Electric Power Company [Member]

14,000,000

Green Sustainability Fund [Member] | Delmarva Power and Light Company [Member]

Green Sustainability Fund [Member] | Atlantic City Electric Company [Member]

Green Sustainability Fund [Member] | Successor [Member] | Pepco Holdings LLC [Member]

Other1 [Member]

Other1 [Member] | Potomac Electric Power Company [Member]

33,000,000

Other1 [Member] | Delmarva Power and Light Company [Member]

7,000,000

Other1 [Member] | Atlantic City Electric Company [Member]

7,000,000

Other1 [Member] | Successor [Member] | Pepco Holdings LLC [Member]

Delmarva Power and Light Company [Member] | Rate Bill Credits [Member]

14,000,000

9,000,000

3,785,000,000

Pepco Holdings LLC [Member] | Preferred Stock [Member]

(66,000,000)

180,000,000

Pepco Holdings LLC [Member] | Successor [Member] | Pepco Holdings LLC [Member]

^[7]

62,000,000

Pepco Holdings LLC [Member] | Successor [Member] | Deferred Compensation, Share-based Payments [Member] | Pepco Holdings LLC [Member]

33,000,000

Pepco Holdings LLC [Member] | Commitments [Member]

29,000,000

$ 513,000,000

513,000,000

Pepco Holdings [Member]

Intergrys Energy Group Inc [Member]

7,142,000,000

Business Combination, Bargain Purchase, Gain Recognized, Amount

332,000,000

28,000,000

386,000,000

(42,000,000)

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

$ 5,000,000

7,000,000

$ 108,000,000

ConEdision [Member] | Exelon Generation Co L L C [Member]

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets

235,000,000

$ 204,000,000

Payments to Acquire Businesses, Net of Cash Acquired

22,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets

1,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

9,000,000

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities

65,000,000

Total net assets

$ 257,000,000

Fitzpatrick [Member]

Fitzpatrick [Member] | Exelon Generation Co L L C [Member]

$ 110,000,000

Other Payments to Acquire Businesses

$ 127,000,000

Fitzpatrick [Member] | Maximum [Member]

$ 200,000,000

$ 250,000,000

[1]	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.
[2]	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.
[3]	, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million, $4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.
[4]	PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.
[5]	Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed by PHI to Exelon.
[6]	Amounts for March 31, 2016 reflect the PHI Successor activity for the period March 24, 2016 to March 31, 2016.
[7]	he liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 4 — Mergers, Acquisitions, and Dispositions.

Mergers, Acquisitions and Dispositions - Purchase Price Allocation of Merger with Constellation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2014	Sep. 01, 2016	Mar. 24, 2016	Mar. 23, 2016
Business Acquisition [Line Items]
Current assets				$ 1,441
Property, plant and equipment				11,088
Total assets				21,797
Current liabilities				2,752
Unamortized energy contract liabilities				(1,515)
Other liabilities				(187)
Total liabilities				(14,655)
Total net assets				7,142
_BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRetirmentObligations				821
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent				3,447
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets			$ 4,005
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedAssets				5,015
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets				248
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedLiabilities				297
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt				$ 5,636
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Current assets	$ 390
Unamortized energy contracts	115
Current liabilities	(196)
Unamortized energy contract liabilities	110
Other liabilities	(57)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	(16)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	50
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedAssets	184
ConEdision [Member] \| Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Current assets		$ 204
Property, plant and equipment		2
Unamortized energy contracts		6
Total assets		322
Unamortized energy contract liabilities		(65)
Total liabilities		(65)
Total net assets		257
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets		9
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedAssets		100
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets		$ 1
Integrys [Member] \| Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Total net assets	360
Business Combination, Bargain Purchase, Gain Recognized, Amount	28
Business Combination, Consideration Transferred	$ 332

Mergers, Acquisitions and Dispositions - Summary of Pro-forma Impact of the Merger (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Business Acquisition, Pro Forma Revenue

$ 32,342

^[1]

$ 33,823

^[2]

Business Acquisition, Pro Forma Net Income (Loss)

$ 1,562

^[1]

$ 2,618

^[2]

Business Acquisition, Pro Forma Earnings Per Share, Basic

$ 1.69

^[1]

$ 2.85

^[2]

Business Acquisition, Pro Forma Earnings Per Share, Diluted

$ 1.69

^[1]

$ 2.84

^[2]

Consolidation, Eliminations [Member]

$ 558

$ 44

Business Acquisition, Pro Forma Revenue

171

$ 559

680

$ 92

$ 0

$ 317

125

$ 110

$ 0

[1]	The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for year ended December 31, 2016
[2]	The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31, 2015

Mergers, Acquisitions and Dispositions Goodwill Amortization Schedule (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Mar. 24, 2016

Dec. 31, 2015

Dec. 31, 2014

Goodwill, Gross

$ 8,660

$ 4,655

Goodwill, Acquired During Period

6,677

$ 2,672

4,016

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

$ 4,005

Goodwill, Other Increase (Decrease)

^[1]

$ (11)

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

$ 1,200

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246NDZFQjI3NUEyQkZDMDk5MDI0QzM5QTYwQjcyQUEwRDkM}

Mergers, Acquisitions and Dispositions Merger Integration Related Costs Table (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

^[1],[2]

$ 143

$ 87

^[2]

^[2],[3]

(6)

^[2]

^[2],[3]

(1)

^[2],[3]

^[2]

^[2]

$ 1

^[3]

$ 29

Regulatory Assets [Member] | Commonwealth Edison Co [Member]

^[3]

$ 69

Regulatory Assets [Member] | Baltimore Gas and Electric Company [Member]

Regulatory Assets [Member] | Pepco Holdings LLC [Member]

Regulatory Assets [Member] | Potomac Electric Power Company [Member]

Regulatory Assets [Member] | Delmarva Power and Light Company [Member]

Schedule of Equity Method Investments [Line Items]

$ 4

[1]	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.
[2]	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.
[3]	, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million, $4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated recovery. See Note 3 - Regulatory Matters for more information.

Mergers, Acquisitions and Dispositions Merger Transaction Table (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Mar. 23, 2016	Dec. 31, 2013
Business Acquisition, Share Price				$ 27.25
Investments	$ 629	$ 639
Shares, Issued	958,778	954,668	894,568		892,034
Payments to Acquire Businesses, Gross	$ 6,934	$ 40	$ 386
Pepco Holdings LLC [Member] \| Predecessor [Member]
Investments		80
Goodwill, Other Increase (Decrease)		$ (6)
Pepco Holdings LLC [Member] \| Successor [Member]
Investments	133
Pepco Holdings LLC [Member] \| Common Stock [Member]
Payments to Acquire Businesses, Gross	$ 6,933

Investment in Constellation Energy Nuclear Group, LLC - Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Apr. 01, 2014

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Jun. 09, 2015

$ 50

(24)

$ (7)

$ 0

7,875

$ 9,002

$ 6,910

$ 7,573

$ 6,702

$ 7,401

$ 6,514

$ 8,830

31,360

29,447

27,429

(2,660)

(2,624)

(2,660)

(2,624)

Constellation Energy Nuclear Group [Member]

^[1],[2]

143

Schedule of Equity Method Investments [Line Items]

Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]

$ 1,500

Schedule of Equity Method Investments [Line Items]

Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]

245

Schedule of Equity Method Investments [Line Items]

165

Schedule of Equity Method Investments [Line Items]

922

2,474

645

(20)

4,388

$ 5,035

$ 3,589

$ 4,739

4,294

$ 4,768

$ 4,232

5,840

17,751

19,135

17,393

AOCI Tax, Attributable to Parent

(54)

(63)

(54)

(63)

Allocation of federal tax benefit under tax sharing agreement

$ 57

$ 55

1,439

749

779

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

^[2]

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

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]

$ 275

Schedule of Equity Method Investments [Line Items]

548

509

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

$ 316

Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased

5.25%

85.00%

50.00%

Other Intangible Assets, Net

$ 152

Reduction to net income attributable to noncontrolling interest

$ 20

Net Income (Loss) Attributable to Parent

201

(11)

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] | Variable Interest Entity, Primary Beneficiary [Member]

$ 376

$ 488

$ 137

Schedule of Equity Method Investments [Line Items]

Electricite De France LLC [Member] | Constellation Energy Nuclear Group [Member]

49.99%

Schedule of Equity Method Investments [Line Items]

Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased

15.00%

50.00%

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]

Investment Interest Rate

8.50%

Constellation Energy Group LLC [Member] | EDFI [Member]

Schedule of Equity Method Investments [Line Items]

Accounts, Notes, Loans and Financing Receivable [Line Items]

$ 400

[1]	Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.
[2]	The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed above.

Investment in Constellation Energy Nuclear Group, LLC - Schedule of Assets and Liabilities of CENG (Details) - USD ($) $ in Millions	Mar. 23, 2016	Dec. 31, 2014	Apr. 01, 2014
Business Acquisition [Line Items]
Current assets	$ 1,441
Property, plant and equipment	11,088
Total assets	21,797
Current liabilities	2,752
Unamortized energy contract liabilities	1,515
Other liabilities	187
Total liabilities	14,655
Total net assets	$ 7,142
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Current assets		$ 390
Current liabilities		(196)
Unamortized energy contract liabilities		(110)
Other liabilities		$ 57
Exelon Generation Co L L C [Member] \| Constellation Energy Nuclear Group [Member]
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 ($)

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

$ 1,673,000,000

$ 1,203,000,000

^[1]

(334,000,000)

(284,000,000)

11,388,000,000

6,824,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

^[2]

910,000,000

732,000,000

^[1]

(91,000,000)

(77,000,000)

Accounts, Notes, Loans and Financing Receivable [Line Items]

219,000,000

218,000,000

^[1]

(70,000,000)

(75,000,000)

1,167,000,000

1,113,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

140,000,000

105,000,000

Allowance for Doubtful Accounts Receivable, Noncurrent

^[1],[3]

(61,000,000)

(83,000,000)

23,000,000

8,000,000

1,710,000,000

1,617,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

182,000,000

148,000,000

^[1]

(32,000,000)

(49,000,000)

712,000,000

781,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

10,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

222,000,000

^[1],[4]

(80,000,000)

3,504,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

177,000,000

^[1]

(56,000,000)

2,582,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

123,000,000

93,000,000

^[1]

(29,000,000)

^[4]

(17,000,000)

852,000,000

801,000,000

6,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

58,000,000

45,000,000

^[1]

(24,000,000)

^[4]

(17,000,000)

348,000,000

371,000,000

4,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

41,000,000

39,000,000

^[1]

(27,000,000)

^[4]

(17,000,000)

PHI Merger [Member] | Pepco Holdings LLC [Member]

501,000,000

$ 512,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

(30,000,000)

PHI Merger [Member] | Potomac Electric Power Company [Member]

20,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

(14,000,000)

PHI Merger [Member] | Delmarva Power and Light Company [Member]

8,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

(8,000,000)

PHI Merger [Member] | Atlantic City Electric Company [Member]

4,000,000

Accounts, Notes, Loans and Financing Receivable [Line Items]

(8,000,000)

Electric—transmission and distribution

$ 8,000,000

[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]	Excludes the non-current allowance for uncollectible accounts of $23 million and $8 million at December 31, 2016 and 2015, respectively, related to PECO’s current installment plan receivables described below.
[4]	At December 31, 2016, as explained in Note 1—Significant Accounting Policies, PHI, Pepco, DPL and ACE 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 an overall increase of $30 million, $14 million, $8 million, and $8 million in the allowance for uncollectible accounts with $20 million, $8 million, $4 million, and $8 million deferred as a regulatory asset on PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets at December 31, 2016, respectively. This also resulted in a $10 million, $6 million, and $4 million pre-tax charge to provision for uncollectible accounts expense for the year ended December 31, 2016, which is included in Operating and maintenance expense on PHI's, Pepco's, and DPL's Consolidated Statements of Operations and Comprehensive Income, respectively.

Accounts Receivable Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	$ 9	$ 15
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	13	15
Risk Level, Low [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	1	1
Risk Level, Medium [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	3	3
Risk Level, High [Member] \| PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	$ 9	$ 11

Property, Plant and Equipment Annual Depreciation Provisions as Percentage of Average Service Life (Details)

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

2.73%

2.83%

2.93%

Electric—generation

Gas Distribution Equipment

5.94%

^[1]

3.47%

3.50%

2.17%

2.13%

Common—electric and gas

PECO Energy Co [Member] | Electric—transmission and distribution

7.41%

7.79%

7.32%

PECO Energy Co [Member] | Gas Distribution Equipment

2.32%

2.39%

2.55%

PECO Energy Co [Member] | Common—electric and gas

1.82%

1.87%

1.84%

Baltimore Gas and Electric Company [Member] | Electric—transmission and distribution

5.11%

5.16%

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

2.56%

2.62%

2.96%

Baltimore Gas and Electric Company [Member] | Common—electric and gas

2.45%

2.50%

2.47%

Pepco Holdings LLC [Member] | Electric—transmission and distribution

9.45%

10.35%

9.49%

Pepco Holdings LLC [Member] | Gas Distribution Equipment

2.52%

2.48%

2.42%

Pepco Holdings LLC [Member] | Common—electric and gas

2.57%

2.55%

2.48%

Delmarva Power and Light Company [Member] | Electric—transmission and distribution

8.12%

5.19%

4.55%

Delmarva Power and Light Company [Member] | Gas Distribution Equipment

2.49%

2.44%

2.41%

Delmarva Power and Light Company [Member] | Common—electric and gas

2.57%

2.55%

2.48%

4.99%

4.24%

4.08%

[1]	See Note 9—Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton and Quad Cities.

Property, Plant and Equipment - Narrative (Details)

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Electric—generation

Electric—transmission and distribution

5.94%

^[1]

3.47%

3.50%

Exelon Generation Co L L C [Member] | Electric—generation

2.73%

2.83%

2.93%

Commonwealth Edison Co [Member] | Electric—transmission and distribution

5.94%

3.47%

3.50%

Potomac Electric Power Company [Member] | Electric—transmission and distribution

3.03%

3.05%

Atlantic City Electric Company [Member] | Electric—transmission and distribution

2.17%

2.13%

2.10%

Capital Leases Net Investment In Direct Financing Leases [Line Items]

2.45%

2.46%

2.48%

[1]	See Note 9—Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton and Quad Cities.

Impairment of Long-lived Assets - Narrative (Details) - USD ($)
$ in Millions

1 Months Ended

12 Months Ended

May 31, 2014

Feb. 26, 2014

Jun. 30, 2017

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Impairment charges

$ 24

Interest costs incurred

^[1],[2]

1,678

$ 1,170

$ 1,144

Estimated residual value of leased assets

356

639

Proceeds From Lease Termination

$ 335

360

Capital leases net investment in direct financing leases writeoff

$ 336

352

Pre Tax Loss

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Carrying amount of long lived assets to be written down

$ 151

1,000

Assets held for sale

556

Impairment charges

$ 86

$ 119

450

Interest costs incurred

^[1],[2]

472

445

419

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Interest costs incurred

^[1]

$ 114

113

118

Constellation Energy Group LLC [Member]

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Impairment charges

$ 5

$ 124

[1]	Successor PredecessorPHIMarch 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015 For the Year Ended December 31, 2014Total incurred interest(b)$207 $68 $289 $277Credits to AFUDC debt and equity35 10 23 21
[2]	Successor PredecessorPHIMarch 24, 2016 to December 31, 2016 January 1, 2016 to March 23, 2016 For the Year Ended December 31, 2015 For the Year Ended December 31, 2014Total incurred interest(b)$207 $68 $289 $277Credits to AFUDC debt and equity35 10 23 21

Impairment of Long-lived Assets - Components of Net Investment in Long-term Leases (Details) - USD ($)
$ in Millions

1 Months Ended

3 Months Ended

6 Months Ended

12 Months Ended

May 31, 2014

Feb. 26, 2014

Jun. 30, 2017

Dec. 31, 2016

Jun. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Impairment or Disposal of Tangible Assets Disclosure [Abstract]

Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property

$ 356

$ 639

Less: unearned income

287

Net investment in long-term leases

^[1]

358

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Tangible Asset Impairment Charges

Capital Leases, Net Investment in Direct Financing Leases, Unguaranteed Residual Values of Leased Property

356

639

Proceeds From Lease Termination

$ 335

360

Gain (Loss) on Contract Termination

Impairment or Disposal of Tangible Assets Disclosure [Abstract]

Net investment in long-term leases

^[1]

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Tangible Asset Impairment Charges

$ 86

$ 119

450

$ 15

Assets held for sale

$ 65

$ 24

556

Gain (Loss) on Disposition of Property Plant Equipment

$ 69

$ 10

$ 32

Constellation Energy Group LLC [Member]

Capital Leases Net Investment In Direct Financing Leases [Line Items]

Tangible Asset Impairment Charges

$ 5

$ 124

[1]	Represents direct financing lease investments.

Early Nuclear Plant Retirements Early Nuclear Plant Retirements (Details) - USD ($)
$ in Millions

1 Months Ended

12 Months Ended

Jun. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Inventory, Raw Materials and Supplies, Gross

$ 1,274

$ 1,104

71,555

57,439

^[1]

1,159

1,116

$ 1,073

^[2]

446

398

345

3,477

2,227

2,080

Facility Closing [Member]

413

(46)

455

Other Expenses

688

Quad Cities [Member]

Inventory, Raw Materials and Supplies, Gross

Nuclear Fuel, Net of Amortization

Asset Retirement Obligation

(565)

1,015

Nuclear Plant [Member]

Other Expenses

688

$ 146

712

(86)

Inventory, Raw Materials and Supplies, Gross

935

880

25,585

25,843

^[1]

1,159

1,116

1,073

^[2]

446

397

345

1,835

1,007

922

$ 401

$ (60)

$ 406

[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.

Early Nuclear Plant Retirements Early Nuclear Plant Retirements table (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 11,388

$ 6,824

^[1]

446

398

$ 345

3,477

2,227

2,080

^[2]

1,159

1,116

1,073

Quad Cities [Member]

Asset Retirement Obligation

565

Facility Closing [Member]

Other Expenses

688

348

371

^[1]

110

103

^[2]

1,167

1,113

^[1]

708

635

588

Accelerated Depreciation Costs of Non AMI Meters [Member] | Commonwealth Edison Co [Member]

^[2]

$ 0

Deferred Income Tax Transmission Related [Member] | Delmarva Power and Light Company [Member]

162

137

Deferred Income Tax Transmission Related [Member] | Commonwealth Edison Co [Member]

Recoverable Smart Meter Related Costs [Member] | Delmarva Power and Light Company [Member]

$ 15

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

$ 41

[1]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

Jointly Owned Electric Utility Plant - Ownership Interests in Jointly Owned Electric Plants and Transmission Facilities (Details)
$ in Millions

12 Months Ended

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Quad Cities [Member]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

$ 37

Conemaugh [Member]

Substation capacity | V

500

Pennsylvania [Member]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Miles of transmission voltage lines | mi

127

Delaware And New Jersey [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Miles of transmission voltage lines | mi

151.3

Delaware River Crossing [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Miles of transmission voltage lines | mi

2.5

New Freedom Switching [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Electric Transmission [Member] | Pennsylvania [Member]

500

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1],[2]

$ 27

^[1],[2]

Electric Transmission [Member] | Delaware And New Jersey [Member]

^[2]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1],[3]

^[1],[3]

Other Service [Member] | Other Locations [Member]

^[3]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[1],[4]

^[1],[4]

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

^[4]

$ 0

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Quad Cities [Member]

44.24%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

75.00%

^[1]

$ 1,054

1,035

^[1]

515

309

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Peach Bottom [Member]

$ 0

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

50.00%

^[1]

$ 1,384

1,345

^[1]

407

368

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Salem [Member]

$ 16

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

^[5]

42.59%

^[1],[5]

$ 596

566

^[1],[5]

186

167

Exelon Generation Co L L C [Member] | Nuclear Plant [Member] | Nine Mile Point [Member]

^[5]

$ 41

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

82.00%

^[1]

$ 830

756

^[1]

Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Salem [Member]

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Wyman [Member]

$ 3

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

5.89%

^[1]

$ 3

^[1]

PECO Energy Co [Member] | Conemaugh [Member]

$ 0

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] | Delaware River Crossing [Member]

42.55%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

42.55%

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]

Potomac Electric Power Company [Member] | Conemaugh [Member]

7.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Potomac Electric Power Company [Member] | Pennsylvania [Member]

9.72%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Potomac Electric Power Company [Member] | Valley Forge [Member]

27.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power and Light Company [Member] | Conemaugh [Member]

11.90%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power and Light Company [Member] | Pennsylvania [Member]

3.72%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power and Light Company [Member] | Delaware And New Jersey [Member]

9.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power and Light Company [Member] | Delaware River Crossing [Member]

1.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power and Light Company [Member] | Merrill Creek [Member]

7.45%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Delmarva Power and Light Company [Member] | Valley Forge [Member]

4.83%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

7.40%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

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

3.83%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Delaware And New Jersey [Member]

8.00%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Delaware River Crossing [Member]

13.90%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Merrill Creek [Member]

7.45%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | Valley Forge [Member]

11.91%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

Atlantic City Electric Company [Member] | New Freedom Switching [Member]

6.60%

Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]

21.78%

[1]	Excludes asset retirement costs.
[2]	PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%, 10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.
[3]	PECO, DPL and ACE own a 42.55%, 1% and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and Delaware Station. PECO, DPL and ACE also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New Freedom Switching
[4]	Generation, DPL and ACE own a 44.24%, 4.83% and 11.91% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and ACE own a 11.9%, 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center.
[5]	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2016 and 2015.

Intangible Assets - Schedule of Goodwill (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Mar. 24, 2016	Dec. 31, 2014
Goodwill [Roll Forward]
Goodwill, Gross		$ 8,660	$ 8,660	$ 4,655		$ 4,655
Accumulated impairment loss		1,983	1,983	1,983		1,983
Goodwill, beginning balance	$ 2,672		2,672	2,672
Goodwill from business combination			4,016
Impairment losses			0	0
Goodwill, Purchase Accounting Adjustments			(11)
Goodwill, ending balance		6,677	6,677	2,672
Exelon Generation Co L L C [Member]
Goodwill [Roll Forward]
Goodwill, Gross		47	47	47		47
Goodwill, beginning balance	47		47	47
Goodwill from business combination			0
Impairment losses			0	0
Goodwill, ending balance		47	47	47
Commonwealth Edison Co [Member]
Goodwill [Roll Forward]
Goodwill, Gross		4,608	4,608	4,608		4,608
Accumulated impairment loss		1,983	1,983	1,983		1,983
Goodwill, beginning balance	2,625		2,625	2,625
Goodwill from business combination			0
Impairment losses			0	0
Goodwill, ending balance		2,625	2,625	2,625
Delmarva Power and Light Company [Member]
Goodwill [Roll Forward]
Goodwill, Gross		8	8	8		8
Goodwill, beginning balance	8		8	8
Goodwill from business combination			0
Impairment losses			0	0
Goodwill, ending balance		8	8	8
Pepco Holdings LLC [Member] \| Predecessor [Member]
Goodwill [Roll Forward]
Goodwill, Gross	1,418			1,418		1,425
Accumulated impairment loss	12			12		$ 18
Goodwill, beginning balance	1,406	1,406	1,406	1,407
Goodwill from business combination	0		0
Impairment losses	0			(7)
Goodwill, Impairment Loss, Net of Tax				(1)
Goodwill, Other Increase (Decrease)				(6)
Goodwill, ending balance	1,406			$ 1,406
Pepco Holdings LLC [Member] \| Successor [Member]
Goodwill [Roll Forward]
Goodwill, Gross	0	4,005	4,005
Accumulated impairment loss		0	0		$ 0
Goodwill, beginning balance		0
Goodwill from business combination		4,016
Impairment losses		0
Goodwill, Purchase Accounting Adjustments		(11)
Goodwill, ending balance	$ 0	$ 4,005	$ 4,005

Intangible Assets - Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Nov. 30, 2016

Mar. 24, 2016

Dec. 31, 2008

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

$ 6,677

$ 2,672

$ 4,005

Goodwill, Purchase Accounting Adjustments

(11)

179

1,225

2,625

Current alternative or renewable energy credits

Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount

30.00%

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

Current alternative or renewable energy credits

179

317

251

Alternative Or Renewable Energy Credits Noncurrent

Current alternative or renewable energy credits

$ 1,406

1,406

1,407

Goodwill, Purchase Accounting Adjustments

4,005

(11)

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

1,700

Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount

10.00%

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

1,100

Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount

10.00%

50.00%

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets

$ 1,200

Reporting Unit, Percentage of Fair Value in Excess of Carrying Amount

10.00%

Unamortized Energy Contracts [Member]

Unamortized Energy Contracts [Member] | Commonwealth Edison Co [Member]

^[1]

135

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[1]

Unamortized Energy Contracts [Member] | PECO Energy Co [Member]

^[1]

135

Unamortized Energy Contracts [Member] | Pepco Holdings LLC [Member]

^[1]

Unamortized Energy Contracts [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

(1,515)

Unamortized Energy Contracts [Member] | Pepco Holdings LLC [Member] | Successor [Member]

^[1]

$ 0

Unamortized Energy Contracts [Member] | Potomac Electric Power Company [Member]

^[1]

Unamortized Energy Contracts [Member] | Potomac Electric Power Company [Member] | Predecessor [Member]

^[1]

Unamortized Energy Contracts [Member] | Delmarva Power and Light Company [Member]

^[1]

Unamortized Energy Contracts [Member] | Atlantic City Electric Company [Member]

^[1]

Unamortized Energy Contracts [Member] | Atlantic City Electric Company [Member] | Predecessor [Member]

^[1]

Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[1]

$ 0

Constellation Energy Group LLC [Member] | Trade Names [Member]

^[2],[3]

1,499

$ 1,499

Constellation Energy Group LLC [Member] | Trade Names [Member] | Exelon Generation Co L L C [Member]

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 $10 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 $(9) million, $(7) million, $(6) million, $(2) million and $4 million for 2017, 2018, 2019, 2020 and 2021, 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, 2016

USD ($)

$ 1,225

Licensing Agreements [Member]

(1,504)

(279)

244

(101)

$ (11)

^[1],[2]

10 years

^[1]

$ 95

^[1]

(15)

^[1]

^[1]

(10)

^[1]

^[1]

(10)

^[1]

(10)

Customer Relationships [Member]

^[1]

^[3],[4]

$ (1)

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],[5]

21 years 9 months 18 days

^[5]

$ 100

^[5]

(86)

^[5]

^[5]

(3)

^[5]

^[5]

(3)

^[5]

(3)

Commonwealth Edison Co [Member] | Intangible Asset Two Thousand Three Chicago Settlement Agreement [Member]

^[5]

$ 0

^[2],[6]

17 years 10 months 24 days

^[6]

$ 62

^[6]

(47)

^[6]

^[6]

(4)

^[6]

^[6]

(4)

^[6]

(4)

Pepco Holdings LLC [Member] | Unamortized Energy Contracts [Member]

^[6]

$ 0

6 years 9 months 18 days

$ (1,515)

Pepco Holdings LLC [Member] | Utility Contracts [Member]

430

(1,085)

(335)

(189)

119

(115)

(92)

Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member]

(9)

(7)

(6)

$ 4

Wind turbine supply megawatt | MW

735

Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[2],[7],[8]

18 years

^[7],[8]

$ 224

^[7],[8]

(83)

^[7],[8]

141

^[7],[8]

(14)

^[7],[8]

^[7],[8]

(14)

^[7],[8]

(10)

Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member]

^[7],[8]

$ 10

Wind turbine supply megawatt | MW

242

Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[2],[8],[9]

25 years

^[8],[9]

$ 190

^[8],[9]

(28)

^[8],[9]

162

^[8],[9]

(8)

^[8],[9]

^[8],[9]

(8)

^[8],[9]

(8)

Constellation Energy Group LLC [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[8],[9]

$ 8

^[2],[4],[8]

1 year 6 months

^[4],[8]

$ 1,499

^[4],[8]

(1,440)

^[4],[8]

^[4],[8]

(21)

^[4],[8]

(11)

^[4],[8]

(8)

^[4],[8]

(10)

Constellation Energy Group LLC [Member] | Exelon Generation Co L L C [Member] | Customer Relationships [Member]

^[4],[8]

$ 10

^[2],[3],[4]

12 years 4 months 24 days

^[3],[4]

$ 214

^[3],[4]

(94)

^[3],[4]

120

^[3],[4]

(18)

^[3],[4]

^[3],[4]

(17)

^[3],[4]

(17)

Constellation Energy Group LLC [Member] | Exelon Generation Co L L C [Member] | Trade Names [Member]

^[3],[4]

$ 17

^[2],[4]

10 years

^[4]

$ 243

^[4]

(125)

^[4]

118

^[4]

(23)

^[4]

^[4]

(23)

^[4]

(23)

CENG [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[4]

$ 23

^[2],[8],[10]

1 year 8 months 12 days

^[8],[10]

$ (97)

^[8],[10]

^[8],[10]

(38)

^[8],[10]

(15)

^[8],[10]

^[8],[10]

(15)

^[8],[10]

(8)

Integrys [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[8],[10]

$ 4

^[2],[8],[10]

2 years 4 months 24 days

^[8],[11]

$ 5

^[8],[11]

(3)

^[8],[11]

Integrys [Member] | Exelon Generation Co L L C [Member] | Customer Relationships [Member]

^[8],[11]

(1)

^[8],[11]

^[8],[11]

^[8],[11]

^[8],[11]

$ 0

^[2],[3],[11]

10 years

^[3],[11]

$ 50

^[3],[11]

(11)

^[3],[11]

^[3],[11]

(5)

^[3],[11]

^[3],[11]

(5)

^[3],[11]

(5)

PES [Member] | Exelon Generation Co L L C [Member] | Customer Relationships [Member]

^[3],[11]

$ 5

15 years

$ 12

PES [Member] | Exelon Generation Co L L C [Member] | Customer Contracts [Member]

(1)

^[3],[11]

(1)

(1)

(1)

$ 1

^[2],[4]

1 year

^[4]

$ 9

^[4]

(7)

^[4]

ConEdison Solutions [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]

^[4]

(2)

^[4]

^[4]

^[4]

^[4]

$ 0

1 year 6 months

^[8],[11]

$ 100

ConEdison Solutions [Member] | Exelon Generation Co L L C [Member] | Customer Relationships [Member]

(53)

^[8],[11]

(37)

(2)

$ (1)

^[2],[3],[11]

10 years

^[3],[11]

$ 9

^[3],[11]

^[3],[11]

^[3],[11]

(1)

^[3],[11]

^[3],[11]

(1)

^[3],[11]

(1)

^[3],[11]

$ 1

[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]	Excludes $11 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 2017 to 2021.
[4]	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.
[5]	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.
[6]	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.
[7]	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735 MWs of installed, operating wind capacity located in eight states.
[8]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $10 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 $(9) million, $(7) million, $(6) million, $(2) million and $4 million for 2017, 2018, 2019, 2020 and 2021, respectively.
[9]	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 242 MW solar project in northern Los Angeles County, CA from First Solar, Inc.
[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

9 Months Ended

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 87

$ 76

$ 179

179

Unamortized Energy Contracts [Member]

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[1]

135

Unamortized Energy Contracts [Member] | Commonwealth Edison Co [Member]

^[1]

135

Unamortized Energy Contracts [Member] | Pepco Holdings LLC [Member] | Successor [Member]

^[1]

$ 0

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, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward Power Basis	$ 2.65
Forward Gas Basis	0.34
Middle market lending [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	284,000,000
Private Equity Funds [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	65,000,000
Real Estate Funds [Member] \| Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$ 205,000,000

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Cash collateral excluded

$ 61,000,000

$ 201,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

^[1]

333,000,000

248,000,000

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Derivative assets, fair value

435,000,000

^[2],[3]

857,000,000

^[4],[5]

Exelon Generation Co L L C [Member] | Not Designated as Hedging Instrument [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] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

(3,000,000)

^[2],[3]

(7,000,000)

^[4],[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] | Minimum [Member] | Not Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

^[3]

^[5]

Forward gas price assets

1.72

^[3]

1.18

^[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] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

^[3]

^[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] | Not Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

130

^[3]

^[5]

Forward gas price assets

9.2

^[3]

8.95

^[5]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

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

$ 79

^[3]

$ 78

^[5]

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Volatility percentage

8.00%

^[3]

5.00%

^[5]

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

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Volatility percentage

173.00%

^[3]

152.00%

^[5]

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [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] | Fair Value, Inputs, Level 3 [Member]

$ (258,000,000)

$ (247,000,000)

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Marketability Reserve

3.00%

3.50%

Renewable factor

89.00%

87.00%

Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Designated as Hedging Instrument [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] | Not Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

^[6]

8.00%

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Fair Value, Inputs, Level 3 [Member]

^[7]

9.00%

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]

^[7]

10.00%

Marketability Reserve

8.00%

7.00%

Renewable factor

121.00%

128.00%

Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]

^[6]

9.00%

[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 $61 million as of December 31, 2016.
[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 $201 million as of December 31, 2015
[5]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[6]	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.
[7]	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)
$ in Thousands

3 Months Ended

12 Months Ended

Jun. 30, 2016

USD ($)

Jun. 30, 2015

USD ($)

Dec. 31, 2016

USD ($)

GWh

Dec. 31, 2015

USD ($)

GWh

Dec. 31, 2014

USD ($)

GWh

Mar. 31, 2016

USD ($)

Proprietary trading activities volume | GWh

6,179

7,310

10,571

Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound

$ 2,918,000

$ 1,774,000

7,000

Ineffective portion recognized in income

14,000

17,000

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax

$ 3,000

Derivative, Gain (Loss) on Derivative, Net

3,000

392,000

374,000

Derivative, collateral, right to reclaim cash

282,000

205,000

29,000

52,000

Cash collateral held

(9,000)

Letters of credit held

16,000

Interest Rate Fair Value Hedge Asset at Fair Value

16,000

Designated as Hedging Instrument [Member]

Notional amount of preissuance interest rate cash flow hedge derivatives

659,000

Interest Rate Swap [Member]

100,000

800,000

$ 600,000

28,000

54,000

4,000

8,000

Interest Rate Swap [Member] | Cash Flow Hedging [Member]

8,000

Interest Rate Swap [Member] | PHI Merger [Member]

90,000

100,000

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

$ 2,400,000

16,000

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]

800,000

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member]

16,000

25,000

Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member] | Cash Flow Hedging [Member]

495,000

9,000

Derivative [Member]

1,381,000

2,069,000

388,000

366,000

Designated as Hedging Instrument [Member] | PHI Merger [Member]

274,000

197,000

Derivative, Gain (Loss) on Derivative, Net

$ (64,000)

Credit exposure under off system sales

26,000

8,000

Incremental collateral for loss of investment grade credit rating

62,000

153,000

150,000

Derivative, collateral, right to reclaim cash

263,000

182,000

8,000

3,000

Letters of credit posted

284,000

497,000

Cash collateral held

(24,000)

(21,000)

Letters of credit held

28,000

78,000

Cash collateral posted

347,000

1,267,000

Incremental collateral for loss of investment grade credit rating

1,900,000

2,000,000

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

Notional amount of interest rate swaps acquired from merger

24,000

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

2,000

$ 195,000

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

12,000

29,000

4,000

8,000

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Other Solar Projects [Member] | Cash Flow Hedging [Member]

8,000

Notional amount of interest rate swaps acquired from merger

$ 25,000

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

3,000

8,000

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

7,000

8,000

Exelon Generation Co L L C [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]

164,000

Exelon Generation Co L L C [Member] | Foreign Exchange Contract [Member]

1,000

Exelon Generation Co L L C [Member] | Derivative [Member]

85,000

1,381,000

^[1]

2,069,000

^[2]

149,000

^[1]

142,000

^[2]

$ 255,000

^[1]

174,000

^[2]

Term of contract

20 years

$ (239,000)

224,000

19,000

23,000

Credit exposure under off system sales

14,000

1,000

Cash collateral held

(3,000)

Letters of credit held

19,000

Incremental collateral for loss of investment grade credit rating

19,000

Incremental collateral for loss of investment grade credit rating

33,000

31,000

18,000

Pepco Holdings LLC [Member] | Derivative [Member] | Successor [Member]

44,000

Incremental collateral for loss of investment grade credit rating

16,000

10,000

Delmarva Power and Light Company [Member] | Energy Related Derivative [Member]

Brokered Natural Gas Margin Revenue

2,750

Delmarva Power and Light Company [Member] | Derivative [Member]

^[2]

^[2]

$ 0

^[2]

$ 9,000

Minimum [Member]

Expected generation hedged in next twelve months

91.00%

Expected generation hedged in year two

56.00%

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

94.00%

Expected generation hedged in year two

59.00%

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%

Senior Notes [Member] | Exelon Generation Co L L C [Member]

$ 4,200,000

$ 750,000

[1]	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.
[2]	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.

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) - USD ($)
$ in Millions

Dec. 31, 2016

Dec. 31, 2015

Mark-to-market derivative assets (noncurrent assets)

$ 917

$ 1,365

492

758

282

205

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

392

374

Mark-to-market derivative assets (noncurrent assets)

917

1,365

476

733

263

182

Interest Rate Swap [Member]

153

150

Mark-to-market derivative assets (noncurrent assets)

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

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

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

Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

909

1,350

472

719

1,381

2,069

274

197

388

366

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

662

563

719

1,506

Derivative [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

909

^[1]

1,350

^[2]

472

^[1]

719

^[2]

1,381

^[1]

2,069

^[2]

255

^[1]

174

^[2]

149

^[1]

142

^[2]

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

404

^[1]

316

^[2]

977

^[1]

1,753

^[2]

Proprietary Trading [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

108

130

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

127

(3)

Collateral and Netting | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

(2,769)

^[3]

(3,994)

(1,016)

^[3]

(1,163)

(3,785)

^[3]

(5,157)

(2,964)

^[3]

(4,827)

(1,150)

^[3]

(1,564)

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

(4,114)

^[3]

(6,391)

329

^[3]

1,234

Collateral and Netting | Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

(13)

(5)

^[4]

(8)

(1)

^[4]

(21)

(6)

^[4]

(14)

(11)

^[4]

(9)

(4)

^[4]

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

(23)

(15)

^[4]

^[4]

Other Segments [Member] | Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

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

Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

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

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

Mark-to-market derivative assets (noncurrent assets)

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

(10)

(16)

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

Mark-to-market derivative assets (noncurrent assets)

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

Designated as Hedging Instrument [Member] | Other Segments [Member] | Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

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

Not Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

^[5]

^[5]

^[5]

^[5]

^[5]

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

^[5]

^[5]

$ 1

$ 3

[1]	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.
[2]	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.
[3]	Exelon, Generation, PHI and DPL 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.
[4]	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.
[5]	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.

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Jun. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Interest Expense [Member] | Fair Value Hedging [Member]

$ (3)

Interest Expense [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member]

$ 23

$ 14

$ (1)

Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member]

(9)

Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

^[1]

Gain (Loss) on Fair Value Hedges Recognized in Earnings

^[1]

$ 0

(1)

(16)

$ (1)

(17)

Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness, Net

$ 4

[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

Dec. 31, 2016

Dec. 31, 2015

Mark-to-market derivative assets (noncurrent assets)

$ 917

$ 1,365

492

758

(282)

(205)

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

(392)

(374)

(2,660)

(2,624)

Mark-to-market derivative assets (noncurrent assets)

917

1,365

476

733

(263)

(182)

(153)

(150)

(54)

(63)

(19)

(23)

239

(224)

Mark-to-market derivative assets (noncurrent assets)

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

(36)

Proprietary Trading [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

108

130

(54)

(94)

(25)

(33)

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

(79)

(127)

(3)

Collateral and Netting | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

(2,769)

^[1]

(3,994)

(1,016)

^[1]

(1,163)

(3,785)

^[1]

(5,157)

2,964

^[1]

4,827

1,150

^[1]

1,564

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

4,114

^[1]

6,391

329

^[1]

1,234

Collateral and Netting | Delmarva Power and Light Company [Member]

Mark-to-market derivative assets (noncurrent assets)

(2)

^[1]

^[1]

(2)

^[1]

^[1]

^[1]

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

^[1]

(2)

^[1]

Derivative [Member]

Mark-to-market derivative assets (noncurrent assets)

909

1,350

472

719

1,381

2,069

(274)

(197)

(388)

(366)

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

(662)

(563)

719

1,506

Derivative [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

909

^[2]

1,350

^[3]

472

^[2]

719

^[3]

1,381

^[2]

2,069

^[3]

(255)

^[2]

(174)

^[3]

(149)

^[2]

(142)

^[3]

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

(404)

^[2]

(316)

^[3]

977

^[2]

1,753

^[3]

Derivative [Member] | Delmarva Power and Light Company [Member]

Mark-to-market derivative assets (noncurrent assets)

^[3]

^[3]

^[3]

^[3]

^[3]

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

^[3]

^[3]

Derivative [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Mark-to-market derivative assets (noncurrent assets)

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

Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

(8)

(4)

(8)

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

(12)

(16)

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

(8)

(4)

(8)

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

(12)

(16)

Economic Hedges [Member] | Exelon Generation Co L L C [Member]

Mark-to-market derivative assets (noncurrent assets)

3,623

5,236

1,467

1,860

5,090

7,096

(3,165)

(4,907)

(1,274)

(1,673)

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

(4,439)

(6,580)

651

516

Economic Hedges [Member] | Commonwealth Edison Co [Member]

Mark-to-market derivative assets (noncurrent assets)

^[4]

(19)

(23)

^[4]

(239)

(224)

^[4]

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

(258)

(247)

^[4]

(258)

(247)

^[4]

Economic Hedges [Member] | Delmarva Power and Light Company [Member]

Mark-to-market derivative assets (noncurrent assets)

^[4]

^[4]

^[4]

(2)

^[4]

^[4]

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

(2)

^[4]

(2)

^[4]

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

Mark-to-market derivative assets (noncurrent assets)

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

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

Current assets collateral offset

(100)

352

Noncurrent assets collateral offset

(72)

180

Current liabilities collateral offset

(95)

480

Collateral Amount Offset Against Fair Value Of Derivative Current Noncurrent Liability

(222)

Total cash collateral received net of cash collateral posted

329

(1,234)

Designated as Hedging Instrument [Member] | Interest Rate Swap [Member]

Mark-to-market derivative assets (noncurrent assets)

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

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

Mark-to-market derivative assets (noncurrent assets)

(7)

(8)

(3)

(8)

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

(10)

(16)

(10)

(16)

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

Mark-to-market derivative assets (noncurrent assets)

(13)

(2)

(8)

(1)

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

(21)

(3)

$ 7

$ 17

[1]	Exelon, Generation, PHI and DPL 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]	Current and noncurrent assets are shown net of collateral of $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $329 million at December 31, 2016.
[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]	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, 2016

Dec. 31, 2015

Dec. 31, 2014

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

$ (2,660)

$ (2,624)

^[1]

(150)

(196)

^[2],[3]

Other, net [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax

Interest Expense [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Tax

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(54)

(63)

^[1]

(13)

(5)

^[2],[3]

Cash Flow Hedging [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

(17)

(19)

$ (28)

(6)

(12)

Cash Flow Hedging [Member] | Other, net [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Cash Flow Hedging [Member] | Interest Expense [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Cash Flow Hedging [Member] | Operating Revenue [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(2)

Cash Flow Hedging [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

(19)

(21)

$ (18)

(6)

(8)

Cash Flow Hedging [Member] | Exelon Generation Co L L C [Member] | Other, net [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Cash Flow Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Expense [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

$ 8

Cash Flow Hedging [Member] | Exelon Generation Co L L C [Member] | Operating Revenue [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

$ (2)

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

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (24,000,000)	$ 367,000,000	$ (716,000,000)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(41,000,000)	357,000,000	(693,000,000)
Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	1,000,000	(8,000,000)	(26,000,000)
Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		100,000,000	(100,000,000)
Commodity Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	213,000,000	404,000,000	(607,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(244,000,000)	(154,000,000)	8,000,000
Unrealized Gain (Loss) on Commodity Contracts	(31,000,000)	250,000,000	(599,000,000)
Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	23,000,000	8,000,000	(1,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(21,000,000)	(14,000,000)	(29,000,000)
Unrealized Gain (Loss) on Commodity Contracts	2,000,000	(6,000,000)	(30,000,000)
Commodity Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge		0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0
Unrealized Gain (Loss) on Commodity Contracts		0	0
Foreign Exchange Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(2,000,000)	49,000,000	(92,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(8,000,000)	58,000,000	(2,000,000)
Unrealized Gain (Loss) on Derivatives	(10,000,000)	107,000,000	(94,000,000)
Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(1,000,000)	8,000,000	1,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	(10,000,000)	3,000,000
Unrealized Gain (Loss) on Derivatives	(1,000,000)	(2,000,000)	4,000,000
Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge		36,000,000	(100,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		64,000,000	0
Unrealized Gain (Loss) on Derivatives		100,000,000	(100,000,000)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(40,000,000)	249,000,000	(635,000,000)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(41,000,000)	257,000,000	(593,000,000)
Exelon Generation Co L L C [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(500,000,000)	203,000,000	(174,000,000)
Exelon Generation Co L L C [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	459,000,000	54,000,000	(417,000,000)
Exelon Generation Co L L C [Member] \| Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts			(2,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	213,000,000	404,000,000	(607,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(244,000,000)	(154,000,000)	8,000,000
Unrealized Gain (Loss) on Commodity Contracts	(31,000,000)	250,000,000	(599,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	5,000,000	759,000,000	(413,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(495,000,000)	(563,000,000)	231,000,000
Unrealized Gain (Loss) on Commodity Contracts	(490,000,000)	196,000,000	(182,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	208,000,000	(355,000,000)	(194,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	251,000,000	409,000,000	(223,000,000)
Unrealized Gain (Loss) on Commodity Contracts	459,000,000	54,000,000	(417,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge			0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			0
Unrealized Gain (Loss) on Commodity Contracts			0
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(2,000,000)	13,000,000	8,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(8,000,000)	(6,000,000)	(2,000,000)
Unrealized Gain (Loss) on Derivatives	(10,000,000)	7,000,000	6,000,000
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(2,000,000)	13,000,000	10,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(8,000,000)	(6,000,000)	(2,000,000)
Unrealized Gain (Loss) on Derivatives	(10,000,000)	7,000,000	8,000,000
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	0	0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0	0
Unrealized Gain (Loss) on Derivatives	$ 0	$ 0	0
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge			(2,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			0
Unrealized Gain (Loss) on Derivatives			$ (2,000,000)

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	$ (24,000,000)	$ 367,000,000	$ (716,000,000)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(41,000,000)	357,000,000	(693,000,000)
Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	1,000,000	(8,000,000)	(26,000,000)
Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		100,000,000	(100,000,000)
Commodity Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	213,000,000	404,000,000	(607,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(244,000,000)	(154,000,000)	8,000,000
Unrealized Gain (Loss) on Commodity Contracts	(31,000,000)	250,000,000	(599,000,000)
Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	23,000,000	8,000,000	(1,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(21,000,000)	(14,000,000)	(29,000,000)
Unrealized Gain (Loss) on Commodity Contracts	2,000,000	(6,000,000)	(30,000,000)
Commodity Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge		0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0	0
Unrealized Gain (Loss) on Commodity Contracts		0	0
Foreign Exchange Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(2,000,000)	49,000,000	(92,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(8,000,000)	58,000,000	(2,000,000)
Unrealized Gain (Loss) on Derivatives	(10,000,000)	107,000,000	(94,000,000)
Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(1,000,000)	8,000,000	1,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	(10,000,000)	3,000,000
Unrealized Gain (Loss) on Derivatives	(1,000,000)	(2,000,000)	4,000,000
Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge		36,000,000	(100,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		64,000,000	0
Unrealized Gain (Loss) on Derivatives		100,000,000	(100,000,000)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(40,000,000)	249,000,000	(635,000,000)
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(41,000,000)	257,000,000	(593,000,000)
Exelon Generation Co L L C [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(500,000,000)	203,000,000	(174,000,000)
Exelon Generation Co L L C [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	459,000,000	54,000,000	(417,000,000)
Exelon Generation Co L L C [Member] \| Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts			(2,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	213,000,000	404,000,000	(607,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(244,000,000)	(154,000,000)	8,000,000
Unrealized Gain (Loss) on Commodity Contracts	(31,000,000)	250,000,000	(599,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	5,000,000	759,000,000	(413,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(495,000,000)	(563,000,000)	231,000,000
Unrealized Gain (Loss) on Commodity Contracts	(490,000,000)	196,000,000	(182,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	208,000,000	(355,000,000)	(194,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	251,000,000	409,000,000	(223,000,000)
Unrealized Gain (Loss) on Commodity Contracts	459,000,000	54,000,000	(417,000,000)
Exelon Generation Co L L C [Member] \| Commodity Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge			0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			0
Unrealized Gain (Loss) on Commodity Contracts			0
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(2,000,000)	13,000,000	8,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(8,000,000)	(6,000,000)	(2,000,000)
Unrealized Gain (Loss) on Derivatives	(10,000,000)	7,000,000	6,000,000
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	(2,000,000)	13,000,000	10,000,000
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(8,000,000)	(6,000,000)	(2,000,000)
Unrealized Gain (Loss) on Derivatives	(10,000,000)	7,000,000	8,000,000
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	0	0	0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0	0
Unrealized Gain (Loss) on Derivatives	$ 0	$ 0	0
Exelon Generation Co L L C [Member] \| Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge			(2,000,000)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net			0
Unrealized Gain (Loss) on Derivatives			$ (2,000,000)

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member] $ in Millions	Dec. 31, 2016 USD ($)
Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Investment grade	$ 995
Non-investment grade	118
Internally rated — investment grade	352
Internally rated — non-investment grade	72
Total	1,537
Credit Collateral [Member]
Derivative [Line Items]
Investment grade	0
Non-investment grade	16
Internally rated — investment grade	1
Internally rated — non-investment grade	8
Total	25
Net Exposure [Member]
Derivative [Line Items]
Investment grade	995
Non-investment grade	102
Internally rated — investment grade	351
Internally rated — non-investment grade	64
Total	1,512
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	328
Non-investment grade	0
Internally rated — investment grade	0
Internally rated — non-investment grade	0
Total	$ 328

Derivative Financial Instruments - Net Credit Exposure by Type of Counterparty (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Cash collateral held	$ 9
Letters of credit held	16
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash collateral held	24	$ 21
Letters of credit held	28	$ 78
Exelon Generation Co L L C [Member] \| Net Exposure [Member]
Derivative [Line Items]
Financial institutions	116
Investor-owned utilities, marketers, power producers	689
Energy cooperatives and municipalities	636
Other	71
Total	$ 1,512

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

Dec. 31, 2016

Dec. 31, 2015

Derivative Asset, Fair Value, Gross Liability

^[1]

$ (960)

$ (932)

Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements

^[2]

627

684

^[3]

$ (333)

$ (248)

[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, 2016

Sep. 30, 2016

May 26, 2016

Dec. 31, 2015

Dec. 31, 2014

Aug. 10, 2013

Aug. 01, 2011

Commercial Paper [Member]

^[1]

$ 1,510,000,000

^[2],[3]

9,450,000,000

$ 10,375,000,000

$ 688,000,000

$ 1,162,000,000

$ 600,000,000

^[4]

$ 500,000,000

Average Interest Rate on Commercial Paper Borrowings

1.12%

0.88%

0.53%

Exelon Corporate [Member] | Commercial Paper [Member]

^[1]

$ 29,000,000

^[2],[3]

$ 500,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 0

0.70%

Average Interest Rate on Commercial Paper Borrowings

1.14%

Line of Credit Facility, Current Borrowing Capacity

$ 1,170,000,000

50,000,000

Exelon Generation Co L L C [Member] | Commercial Paper [Member]

^[2],[3]

5,300,000,000

5,450,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 620,000,000

$ 0

0.94%

0.49%

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

Exelon Generation Co L L C [Member] | Letter of Credit [Member]

$ 500,000,000

$ 275,000,000

7,000,000

Average Interest Rate on Commercial Paper Borrowings

0.89%

0.50%

Line of Credit Facility, Current Borrowing Capacity

^[1]

2,000,000

34,000,000

Commonwealth Edison Co [Member] | Commercial Paper [Member]

^[2],[3]

$ 1,000,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 0

$ 294,000,000

0.77%

0.53%

Commonwealth Edison Co [Member] | Letter of Credit [Member]

$ 12,000,000

Line of Credit Facility, Current Borrowing Capacity

^[1]

2,000,000

34,000,000

PECO Energy Co [Member] | Commercial Paper [Member]

^[2],[3]

$ 600,000,000

PECO Energy Co [Member] | Letter of Credit [Member]

$ 0

$ 21,000,000

Average Interest Rate on Commercial Paper Borrowings

0.95%

0.87%

0.61%

Line of Credit Facility, Current Borrowing Capacity

^[1]

$ 0

5,000,000

Baltimore Gas and Electric Company [Member] | Commercial Paper [Member]

^[2],[3]

600,000,000

$ 600,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 45,000,000

$ 210,000,000

0.77%

0.48%

Baltimore Gas and Electric Company [Member] | Letter of Credit [Member]

Pepco Energy Services [Member]

$ 2,000,000

Line of Credit Facility, Current Borrowing Capacity

2,000,000

Average Interest Rate on Commercial Paper Borrowings

1.22%

0.78%

Pepco Holdings LLC [Member] | Commercial Paper [Member]

^[2],[3]

$ 875,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 0

$ 484,000,000

1.03%

0.80%

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

Line of Credit Facility, Current Borrowing Capacity

$ 900,000,000

$ 1,500,000,000

$ 900,000,000

Average Interest Rate on Commercial Paper Borrowings

0.90%

0.68%

0.46%

Potomac Electric Power Company [Member] | Commercial Paper [Member]

^[1]

$ 0

^[2],[3]

500,000,000

$ 500,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 23,000,000

$ 64,000,000

0.71%

0.44%

Average Interest Rate on Commercial Paper Borrowings

0.79%

0.42%

Line of Credit Facility, Current Borrowing Capacity

^[1]

$ 0

2,000,000

Delmarva Power and Light Company [Member] | Commercial Paper [Member]

^[2],[3]

500,000,000

$ 500,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 0

$ 105,000,000

0.68%

0.47%

Average Interest Rate on Commercial Paper Borrowings

0.65%

0.52%

Line of Credit Facility, Current Borrowing Capacity

^[1]

$ 1,000,000

2,000,000

Atlantic City Electric Company [Member] | Commercial Paper [Member]

^[2],[3]

350,000,000

$ 350,000,000

Average Interest Rate on Commercial Paper Borrowings

$ 0

$ 5,000,000

0.65%

0.46%

[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
[2]	Excludes $500 million and $275 million in bilateral credit facilities that do not back Generation's commercial paper program at December 31, 2016 and 2015, respectively
[3]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[4]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 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 ($)
$ in Millions

Dec. 31, 2016

Sep. 30, 2016

May 26, 2016

Apr. 01, 2016

Jan. 05, 2016

Dec. 31, 2015

Oct. 23, 2015

Aug. 10, 2013

Aug. 01, 2011

$ 75

^[1]

1,510

7,915

^[2]

7,108

$ 600

^[3]

$ 500

^[1]

571

^[2]

571

1,170

4,130

Credit facility agreements with minority and community banks

3,510

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

Exelon Generation Co L L C [Member] | Letter of Credit [Member]

500

$ 275

Exelon Generation Co L L C [Member] | Line of Credit [Member]

$ 200

$ 150

$ 100

119

^[2]

^[1]

998

Credit facility agreements with minority and community banks

^[2]

998

Commonwealth Edison Co [Member] | Letter of Credit [Member]

^[1]

598

Credit facility agreements with minority and community banks

^[2]

598

PECO Energy Co [Member] | Letter of Credit [Member]

^[1]

600

Credit facility agreements with minority and community banks

^[2]

555

Baltimore Gas and Electric Company [Member] | Letter of Credit [Member]

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

Credit facility agreements with minority and community banks

$ 900

$ 1,500

$ 900

^[1]

300

^[2]

277

^[1]

300

Credit facility agreements with minority and community banks

^[2]

300

^[1]

299

Credit facility agreements with minority and community banks

^[2]

299

$ 2

[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
[2]	Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
[3]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

Debt and Credit Agreements - Summary of Short-term Borrowing Activities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Exelon Corporate [Member]
Short-term Debt [Line Items]
Average borrowings	$ 1,125	$ 499	$ 571
Maximum borrowings outstanding	$ 3,076	$ 739	$ 1,164
Average interest rates, computed on a daily basis	0.88%	0.53%	0.32%
Average interest rates at year end	1.12%	0.88%	0.53%
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Average borrowings	$ 536	$ 1	$ 93
Maximum borrowings outstanding	$ 1,735	$ 50	$ 552
Average interest rates, computed on a daily basis	0.94%	0.49%	0.32%
Average interest rates at year end	1.14%
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Average borrowings	$ 256	$ 461	$ 415
Maximum borrowings outstanding	$ 755	$ 684	$ 597
Average interest rates, computed on a daily basis	0.77%	0.53%	0.33%
Average interest rates at year end		0.89%	0.50%
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 143	$ 37	$ 64
Maximum borrowings outstanding	$ 369	$ 210	$ 180
Average interest rates, computed on a daily basis	0.77%	0.48%	0.29%
Average interest rates at year end	0.95%	0.87%	0.61%
Pepco Holdings LLC [Member]
Short-term Debt [Line Items]
Average borrowings	$ 153	$ 444	$ 153
Maximum borrowings outstanding	$ 559	$ 784	$ 369
Average interest rates, computed on a daily basis	1.03%	0.90%	0.56%
Average interest rates at year end		1.22%	0.78%
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 4	$ 34	$ 37
Maximum borrowings outstanding	$ 73	$ 190	$ 209
Average interest rates, computed on a daily basis	0.71%	0.44%	0.28%
Average interest rates at year end	0.90%	0.68%	0.46%
Delmarva Power and Light Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 33	$ 81	$ 69
Maximum borrowings outstanding	$ 116	$ 179	$ 177
Average interest rates, computed on a daily basis	0.68%	0.47%	0.26%
Average interest rates at year end		0.79%	0.42%
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Average borrowings	$ 0	$ 175	$ 112
Maximum borrowings outstanding	$ 5	$ 253	$ 259
Average interest rates, computed on a daily basis	0.65%	0.46%	0.27%
Average interest rates at year end		0.65%	0.52%

Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details)	12 Months Ended
	Dec. 31, 2016
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	27.50%
Basis Points For Libor Based Borrowings	127.5
Credit agreement threshold	2.50
Exelon Generation Co L L C [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	27.50%
Basis Points For Libor Based Borrowings	127.5
Credit agreement threshold	3.00
Commonwealth Edison Co [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	7.50%
Basis Points For Libor Based Borrowings	107.5
Credit agreement threshold	2.00
PECO Energy Co [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	0.00%
Basis Points For Libor Based Borrowings	90.0
Credit agreement threshold	2.00
Baltimore Gas and Electric Company [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	0.00%
Basis Points For Libor Based Borrowings	100.0
Credit agreement threshold	2.00
Potomac Electric Power Company [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	7.50%
Basis Points For Libor Based Borrowings	107.5
Credit agreement threshold	2.00
Delmarva Power and Light Company [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	7.50%
Basis Points For Libor Based Borrowings	107.5
Credit agreement threshold	2.00
Atlantic City Electric Company [Member]
Line of Credit Facility [Line Items]
Basis Points For Prime Based Borrowings	7.50%
Basis Points For Libor Based Borrowings	107.5
Credit agreement threshold	2.00

Debt and Credit Agreements - Summary of Interest Coverage Ratios (Details)	12 Months Ended
	Dec. 31, 2016
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	7.03
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	11.81
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	6.89
PECO Energy Co [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	8.77
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	10.47
Potomac Electric Power Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	6.24
Delmarva Power and Light Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	8.42
Atlantic City Electric Company [Member]
Debt Instrument [Line Items]
Debt Instrument, Covenant Compliance	5.84

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) - USD ($)

Dec. 31, 2016

Dec. 31, 2015

Jun. 30, 2015

$ 33,311,000,000

$ 25,113,000,000

Long-term debt (including amounts due within one year) (a)

(68,000,000)

(63,000,000)

962,000,000

275,000,000

(2,430,000,000)

(1,500,000,000)

31,575,000,000

23,645,000,000

641,000,000

648,000,000

^[1]

(200,000,000)

(180,000,000)

206,000,000

ComEd Financing Three Affiliate [Member] | Maximum [Member]

$ 205,000,000

205,000,000

6.35%

PECO Trust Three Affiliate [Member]

6.35%

$ 81,000,000

81,000,000

PECO Trust Three Affiliate [Member] | Maximum [Member]

$ 81,000,000

81,000,000

7.38%

PECO Trust Four Affiliate [Member]

7.38%

$ 103,000,000

103,000,000

PECO Trust Four Affiliate [Member] | Maximum [Member]

$ 103,000,000

103,000,000

5.75%

BGE Trust Member [Member]

5.75%

BGE Trust Member [Member] | Maximum [Member]

$ 258,000,000

258,000,000

6.20%

6.20%

Unsecured Debt [Member]

Unsecured Debt [Member] | Minimum [Member]

$ 2,300,000,000

1,750,000,000

2.40%

Unsecured Debt [Member] | Maximum [Member]

2.40%

6.35%

Rate Stabilization Bonds [Member]

6.35%

Rate Stabilization Bonds [Member] | Minimum [Member]

$ 41,000,000

120,000,000

5.82%

Rate Stabilization Bonds [Member] | Maximum [Member]

5.82%

5.82%

5.82%

Secured Debt [Member]

Secured Debt [Member] | Minimum [Member]

^[2]

$ 14,123,000,000

9,019,000,000

^[2]

1.70%

Secured Debt [Member] | Maximum [Member]

^[2]

1.70%

^[2]

7.90%

^[2]

7.90%

Senior Notes [Member] | Minimum [Member]

$ 11,868,000,000

9,803,000,000

1.55%

Senior Notes [Member] | Maximum [Member]

1.55%

7.60%

Pollution Control Notes [Member]

7.60%

Pollution Control Notes [Member] | Maximum [Member]

$ 435,000,000

435,000,000

2.70%

Notes Payable to Banks [Member]

2.70%

Notes Payable to Banks [Member] | Minimum [Member]

$ 105,000,000

127,000,000

3.15%

Notes Payable to Banks [Member] | Maximum [Member]

3.15%

3.35%

Notes Payable, Other Payables [Member]

3.35%

^[3],[4]

$ 576,000,000

314,000,000

Notes Payable, Other Payables [Member] | Minimum [Member]

^[1]

$ (7,000,000)

(7,000,000)

^[3]

1.43%

Notes Payable, Other Payables [Member] | Maximum [Member]

^[3]

1.43%

^[3]

7.83%

Junior Subordinated Debt [Member]

^[3]

7.83%

Junior Subordinated Debt [Member] | Maximum [Member]

$ 1,150,000,000

1,150,000,000

$ 1,150,000,000.00

6.50%

contract Payments Junior Subordinate Debt [Member]

6.50%

contract Payments Junior Subordinate Debt [Member] | Maximum [Member]

$ 19,000,000

64,000,000

2.50%

Software License Arrangement [Member]

2.50%

Software License Arrangement [Member] | Maximum [Member]

$ 103,000,000

111,000,000

3.95%

Tax-exempt Money Market Funds [Member]

3.95%

Tax-exempt Money Market Funds [Member] | Maximum [Member]

$ 112,000,000

5.40%

Medium-term Notes [Member]

5.40%

Medium-term Notes [Member] | Minimum [Member]

$ 40,000,000

6.81%

Medium-term Notes [Member] | Maximum [Member]

6.81%

7.72%

Transition Bonds [Member]

7.72%

Transition Bonds [Member] | Minimum [Member]

$ 124,000,000

5.05%

Transition Bonds [Member] | Maximum [Member]

5.05%

5.55%

Non Recourse Fixed Rate [Member]

5.55%

Non Recourse Variable Rate [Member]

$ 1,400,000,000

1,162,000,000

Capital Lease Obligations [Member]

915,000,000

1,058,000,000

Capital lease obligations, noncurrent

69,000,000

29,000,000

17,000,000

18,000,000

20,000,000

5,000,000

1,000,000

8,000,000

9,208,000,000

8,919,000,000

Long-term debt (including amounts due within one year) (a)

(17,000,000)

115,000,000

127,000,000

(1,117,000,000)

(90,000,000)

7,202,000,000

7,936,000,000

922,000,000

933,000,000

8,124,000,000

8,869,000,000

Capital lease obligations, noncurrent

(65,000,000)

(70,000,000)

22,000,000

21,000,000

Due in 2016

5,000,000

Due in 2017

6,000,000

Due in 2018

5,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member]

Exelon Generation Co L L C [Member] | Senior Notes [Member] | Minimum [Member]

$ 5,971,000,000

5,971,000,000

2.00%

Exelon Generation Co L L C [Member] | Senior Notes [Member] | Maximum [Member]

2.00%

7.60%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member]

7.60%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member] | Minimum [Member]

$ 435,000,000

435,000,000

2.50%

Exelon Generation Co L L C [Member] | Pollution Control Notes [Member] | Maximum [Member]

2.50%

2.70%

Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member]

2.70%

Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member] | Minimum [Member]

$ 105,000,000

127,000,000

3.20%

Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member] | Maximum [Member]

3.20%

3.40%

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member]

3.40%

^[5],[6]

$ 382,000,000

166,000,000

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

$ 198,000,000

1.40%

Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

1.40%

7.80%

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member]

7.80%

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member] | Minimum [Member]

$ 1,400,000,000

1,162,000,000

2.30%

Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member] | Maximum [Member]

2.30%

6.00%

Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member]

6.00%

Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member] | Minimum [Member]

$ 915,000,000

1,058,000,000

3.20%

Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member] | Maximum [Member]

3.20%

5.00%

5.00%

$ 2,381,000,000

2,385,000,000

(2,000,000)

(3,000,000)

2,333,000,000

2,340,000,000

(16,000,000)

(11,000,000)

2,333,000,000

2,340,000,000

Potomac Electric Power Company [Member] | Secured Debt [Member]

^[7]

(30,000,000)

(31,000,000)

Potomac Electric Power Company [Member] | Secured Debt [Member] | Minimum [Member]

$ 2,335,000,000

2,335,000,000

3.05%

Potomac Electric Power Company [Member] | Secured Debt [Member] | Maximum [Member]

3.05%

7.90%

Potomac Electric Power Company [Member] | Notes Payable, Other Payables [Member]

7.90%

Potomac Electric Power Company [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

$ 46,000,000

50,000,000

6.20%

Potomac Electric Power Company [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

6.20%

8.88%

8.88%

$ 7,101,000,000

6,567,000,000

(22,000,000)

(20,000,000)

(425,000,000)

(665,000,000)

6,608,000,000

5,844,000,000

205,000,000

206,000,000

6,608,000,000

5,844,000,000

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

^[8]

(46,000,000)

(38,000,000)

206,000,000

205,000,000

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member] | Maximum [Member]

^[8]

$ (1,000,000)

(1,000,000)

6.35%

Commonwealth Edison Co [Member] | Secured Debt [Member]

6.35%

Commonwealth Edison Co [Member] | Secured Debt [Member] | Minimum [Member]

^[9]

$ 6,954,000,000

6,419,000,000

^[9]

2.15%

Commonwealth Edison Co [Member] | Secured Debt [Member] | Maximum [Member]

^[9]

2.15%

^[9]

6.45%

Commonwealth Edison Co [Member] | Notes Payable, Other Payables [Member]

^[9]

6.45%

Commonwealth Edison Co [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

^[10]

$ 147,000,000

148,000,000

^[10]

6.95%

Commonwealth Edison Co [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

^[10]

6.95%

^[10]

7.49%

Commonwealth Edison Co [Member] | Capital Lease Obligations [Member]

^[10]

7.49%

Capital lease obligations, noncurrent

$ 8,000,000

Due in 2020

1,000,000

2,600,000,000

(5,000,000)

2,580,000,000

2,280,000,000

184,000,000

(300,000,000)

2,580,000,000

2,280,000,000

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

^[7]

(15,000,000)

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member] | Maximum [Member]

$ 81,000,000

81,000,000

7.38%

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

7.38%

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member] | Maximum [Member]

$ 103,000,000

103,000,000

5.75%

PECO Energy Co [Member] | Secured Debt [Member]

5.75%

PECO Energy Co [Member] | Secured Debt [Member] | Minimum [Member]

^[11]

$ 2,600,000,000

2,600,000,000

^[11]

1.70%

PECO Energy Co [Member] | Secured Debt [Member] | Maximum [Member]

^[11]

1.70%

^[11]

5.95%

^[11]

5.95%

$ 2,341,000,000

1,870,000,000

(4,000,000)

(3,000,000)

2,281,000,000

1,480,000,000

252,000,000

258,000,000

(41,000,000)

(378,000,000)

2,281,000,000

1,480,000,000

Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member]

^[12]

(15,000,000)

(9,000,000)

252,000,000

258,000,000

Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member] | Maximum [Member]

^[12]

$ (6,000,000)

(6,000,000)

6.20%

Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds [Member]

6.20%

Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds [Member] | Minimum [Member]

$ 41,000,000

120,000,000

5.82%

Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds [Member] | Maximum [Member]

5.82%

5.82%

Baltimore Gas and Electric Company [Member] | Senior Notes [Member]

5.82%

Baltimore Gas and Electric Company [Member] | Senior Notes [Member] | Minimum [Member]

$ 2,300,000,000

1,750,000,000

2.40%

Baltimore Gas and Electric Company [Member] | Senior Notes [Member] | Maximum [Member]

2.40%

6.35%

6.35%

$ 5,157,000,000

5,331,000,000

Long-term debt (including amounts due within one year) (a)

1,000,000

(2,000,000)

742,000,000

(253,000,000)

(456,000,000)

5,645,000,000

4,823,000,000

Pepco Holdings LLC [Member] | Unsecured Debt [Member]

^[7]

(2,000,000)

(50,000,000)

Pepco Holdings LLC [Member] | Unsecured Debt [Member] | Minimum [Member]

$ 266,000,000

456,000,000

6.13%

Pepco Holdings LLC [Member] | Unsecured Debt [Member] | Maximum [Member]

6.13%

7.45%

Pepco Holdings LLC [Member] | Secured Debt [Member]

7.45%

Pepco Holdings LLC [Member] | Secured Debt [Member] | Minimum [Member]

$ 4,569,000,000

4,495,000,000

3.05%

Pepco Holdings LLC [Member] | Secured Debt [Member] | Maximum [Member]

3.05%

7.90%

Pepco Holdings LLC [Member] | Notes Payable, Other Payables [Member]

7.90%

Pepco Holdings LLC [Member] | Notes Payable, Other Payables [Member] | Minimum [Member]

$ 46,000,000

57,000,000

6.20%

Pepco Holdings LLC [Member] | Notes Payable, Other Payables [Member] | Maximum [Member]

6.20%

8.88%

Pepco Holdings LLC [Member] | Tax-exempt Money Market Funds [Member]

8.88%

Pepco Holdings LLC [Member] | Tax-exempt Money Market Funds [Member] | Maximum [Member]

$ 112,000,000

112,000,000

5.40%

Pepco Holdings LLC [Member] | Medium-term Notes [Member]

5.40%

Pepco Holdings LLC [Member] | Medium-term Notes [Member] | Minimum [Member]

$ 40,000,000

40,000,000

6.81%

Pepco Holdings LLC [Member] | Medium-term Notes [Member] | Maximum [Member]

6.81%

7.72%

Pepco Holdings LLC [Member] | Transition Bonds [Member]

7.72%

Pepco Holdings LLC [Member] | Transition Bonds [Member] | Minimum [Member]

^[13]

$ 124,000,000

171,000,000

5.05%

Pepco Holdings LLC [Member] | Transition Bonds [Member] | Maximum [Member]

5.05%

5.55%

5.55%

$ 1,348,000,000

1,273,000,000

2,000,000

(105,000,000)

1,221,000,000

1,061,000,000

(119,000,000)

(204,000,000)

1,221,000,000

1,061,000,000

Delmarva Power and Light Company [Member] | Secured Debt [Member]

^[7]

(10,000,000)

Delmarva Power and Light Company [Member] | Secured Debt [Member] | Minimum [Member]

$ 1,196,000,000

1,121,000,000

3.50%

Delmarva Power and Light Company [Member] | Secured Debt [Member] | Maximum [Member]

3.50%

4.15%

Delmarva Power and Light Company [Member] | Tax-exempt Money Market Funds [Member]

4.15%

Delmarva Power and Light Company [Member] | Tax-exempt Money Market Funds [Member] | Maximum [Member]

$ 112,000,000

112,000,000

5.40%

Delmarva Power and Light Company [Member] | Medium-term Notes [Member]

5.40%

Delmarva Power and Light Company [Member] | Medium-term Notes [Member] | Minimum [Member]

$ 40,000,000

40,000,000

6.81%

Delmarva Power and Light Company [Member] | Medium-term Notes [Member] | Maximum [Member]

6.81%

7.72%

7.72%

$ 1,162,000,000

1,210,000,000

(1,000,000)

1,120,000,000

1,153,000,000

(35,000,000)

(48,000,000)

1,120,000,000

1,153,000,000

Atlantic City Electric Company [Member] | Secured Debt [Member]

^[7]

(6,000,000)

(8,000,000)

Atlantic City Electric Company [Member] | Secured Debt [Member] | Minimum [Member]

$ 1,038,000,000

1,039,000,000

3.38%

Atlantic City Electric Company [Member] | Secured Debt [Member] | Maximum [Member]

3.38%

7.75%

Atlantic City Electric Company [Member] | Transition Bonds [Member]

7.75%

Atlantic City Electric Company [Member] | Transition Bonds [Member] | Minimum [Member]

^[14]

$ 124,000,000

$ 171,000,000

5.05%

Atlantic City Electric Company [Member] | Transition Bonds [Member] | Maximum [Member]

5.05%

5.55%

5.55%

[1]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[2]	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of their respective mortgage indentures.
[3]	Includes capital lease obligations of $69 million and $29 million at December 31, 2016 and 2015, respectively. Lease payments of $17 million, $18 million, $20 million, $5 million, $1 million, and $8 million will be made in 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.
[4]	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, 2016, $198 million was outstanding.
[5]	Includes Generation’s capital lease obligations of $22 million and $21 million at December 31, 2016 and 2015, respectively. Generation will make lease payments of $5 million, $5 million, $6 million and $5 million and $1 million in 2017, 2018, 2019, 2020 and 2021 respectively. The capital lease matures in 2020.
[6]	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, 2016, $198 million was outstanding.
[7]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[8]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
[9]	Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.
[10]	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2016 and 2015, respectively. Lease payments of less than $1 million will be made from 2017 through expiration at 2053.
[11]	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture
[12]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.
[13]	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.
[14]	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) - USD ($)
$ in Millions

Dec. 31, 2016

Dec. 31, 2015

$ 2,430

1,742

1,060

3,331

2,400

^[1]

22,996

33,959

648

$ 648

BGE Trust Member [Member]

33,311

25,113

258

PECO Financing Trusts [Member]

206

184

1,117

104

606

1,912

888

4,581

9,208

9,208

8,919

425

840

300

500

350

^[2]

4,892

7,307

206

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

7,101

6,567

206

500

300

^[3]

1,984

2,784

2,600

300

^[4]

2,258

2,599

258

Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member]

2,341

1,870

258

253

298

154

262

4,171

5,157

5,157

5,331

124

2,226

2,381

2,381

2,385

119

1,213

1,348

1,348

1,273

281

260

549

1,162

Medium-term Notes [Member]

1,162

1,210

Medium-term Notes [Member] | Pepco Holdings LLC [Member]

Medium-term Notes [Member] | Delmarva Power and Light Company [Member]

Unsecured Debt [Member]

Unsecured Debt [Member] | Pepco Holdings LLC [Member]

2,300

1,750

266

456

Senior Notes [Member] | Exelon Generation Co L L C [Member]

11,868

9,803

Senior Notes [Member] | Baltimore Gas and Electric Company [Member]

5,971

Transition Bonds [Member]

2,300

1,750

Transition Bonds [Member] | Pepco Holdings LLC [Member]

124

Transition Bonds [Member] | Atlantic City Electric Company [Member]

^[5]

124

171

Rate Stabilization Bonds [Member]

^[6]

124

171

Rate Stabilization Bonds [Member] | Baltimore Gas and Electric Company [Member]

120

Pollution Control Notes [Member]

120

Pollution Control Notes [Member] | Exelon Generation Co L L C [Member]

435

Notes Payable to Banks [Member]

435

Notes Payable to Banks [Member] | Exelon Generation Co L L C [Member]

105

127

Notes Payable, Other Payables [Member]

105

127

Notes Payable, Other Payables [Member] | Exelon Generation Co L L C [Member]

^[7],[8]

576

314

Notes Payable, Other Payables [Member] | Commonwealth Edison Co [Member]

^[9],[10]

382

166

Notes Payable, Other Payables [Member] | Pepco Holdings LLC [Member]

^[11]

147

148

Notes Payable, Other Payables [Member] | Potomac Electric Power Company [Member]

Non Recourse Fixed Rate [Member]

Non Recourse Fixed Rate [Member] | Exelon Generation Co L L C [Member]

1,400

1,162

Non Recourse Variable Rate [Member]

1,400

1,162

Non Recourse Variable Rate [Member] | Exelon Generation Co L L C [Member]

915

1,058

$ 915

$ 1,058

[1]	Includes $648 million due to ComEd, PECO and BGE financing trusts.
[2]	Includes $206 million due to ComEd financing trust.
[3]	Includes $184 million due to PECO financing trusts.
[4]	Includes $258 million due to BGE financing trust.
[5]	Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.
[6]	Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.
[7]	Includes capital lease obligations of $69 million and $29 million at December 31, 2016 and 2015, respectively. Lease payments of $17 million, $18 million, $20 million, $5 million, $1 million, and $8 million will be made in 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.
[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, 2016, $198 million was outstanding.
[9]	Includes Generation’s capital lease obligations of $22 million and $21 million at December 31, 2016 and 2015, respectively. Generation will make lease payments of $5 million, $5 million, $6 million and $5 million and $1 million in 2017, 2018, 2019, 2020 and 2021 respectively. The capital lease matures in 2020.
[10]	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, 2016, $198 million was outstanding.
[11]	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2016 and 2015, respectively. Lease payments of less than $1 million will be made from 2017 through expiration at 2053.

Debt and Credit Agreements - Narrative (Details)
$ / shares in Units, shares in Millions

1 Months Ended

12 Months Ended

Feb. 29, 2016

USD ($)

Dec. 02, 2015

USD ($)

Sep. 30, 2013

Jun. 30, 2014

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Dec. 31, 2014

USD ($)

Jun. 30, 2016

USD ($)

May 26, 2016

USD ($)

Apr. 01, 2016

USD ($)

Mar. 31, 2016

USD ($)

Jan. 13, 2016

USD ($)

Jan. 05, 2016

USD ($)

Oct. 23, 2015

USD ($)

Sep. 30, 2015

USD ($)

Jul. 30, 2015

Jun. 30, 2015

USD ($)

$ / shares

Sep. 30, 2014

USD ($)

Sep. 18, 2014

USD ($)

May 31, 2014

USD ($)

Feb. 06, 2014

USD ($)

Aug. 10, 2013

USD ($)

Dec. 31, 2012

USD ($)

Jun. 30, 2012

USD ($)

Oct. 31, 2011

USD ($)

Aug. 01, 2011

USD ($)

Jul. 31, 2011

USD ($)

$ 2,430,000,000

$ 1,500,000,000

Gain (Loss) on Sale of Debt Investments

1,936,000,000

2,687,000,000

$ 1,545,000,000

Escrow Deposit

6,000,000

$ 37,000,000

2.50

^[1]

$ 1,510,000,000

27.50%

127.5

Bridge loan

$ 3,200,000,000.0

$ 7,200,000,000.0

$ 33,311,000,000

25,113,000,000

Collateral amount of debt

33,959,000,000

Redemption of debt

45,000,000

44,000,000

2,800,000,000

Line of Credit Facility, Increase (Decrease), Other, Net

$ 45,000,000

Secured Demand Note Deficiency

$ 23,000,000

Debt Instrument, Fee Amount

75,000,000

$ 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

659,000,000

Upstream Gas Property [Member]

15,000,000

11,868,000,000

9,803,000,000

Junior Subordinated Debt [Member]

$ 4,200,000,000

Redemption of debt

868,000,000

Equity units issued | shares

$ 1,150,000,000

1,150,000,000

$ 1,150,000,000.00

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]

9000.00%

Maximum [Member] | Senior Notes [Member]

165.0

Maximum [Member] | Junior Subordinated Debt [Member]

7.60%

Minimum [Member] | Senior Notes [Member]

6.50%

1.55%

Line of credit facility, maximum borrowing capacity

^[2]

$ 9,500,000,000

Line of credit facility, maximum borrowing capacity

$ 600,000,000

^[2]

$ 500,000,000

Line of Credit Facility, Maximum Amount Outstanding During Period

$ 250,000,000

500

$ 46,000,000

2,263,000,000

23,000,000

^[1]

29,000,000

7,608,000,000

5,853,000,000

7,608,000,000

$ 1,900,000,000

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

$ 1,150,000,000

1,150,000,000

Exelon Corporate [Member] | Maximum [Member] | Senior Notes [Member]

6.50%

Exelon Corporate [Member] | Minimum [Member] | Senior Notes [Member]

^[3]

7.60%

Exelon Corporate [Member] | Revolving Credit Facility [Member]

^[3]

1.60%

Line of credit facility, maximum borrowing capacity

^[4],[5]

$ 600,000,000

1,117,000,000

90,000,000

$ 202,000,000

89,000,000

586,000,000

3.00

$ 1,170,000,000

27.50%

127.5

$ 9,208,000,000

8,919,000,000

9,208,000,000

Line of Credit Facility, Description

$ 0

100

Exelon Generation Co L L C [Member] | ExGen Texas Power [Member] | Interest Rate Swap [Member]

Non-recourse debt, interest rate swap

2.34%

$ 505,000,000

Exelon Generation Co L L C [Member] | ExgenRenewablesI425June62021[Member] | Interest Rate Swap [Member]

Non-recourse debt, interest rate swap

2.03%

$ 240,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member]

$ 5,971,000,000

5,971,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExGen Texas Power [Member]

750,000,000

4.75%

$ 675,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExgenRenewablesI425June62021[Member]

660,000,000

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]

234,000,000

Non-recourse debt, commitment

106,000,000

$ 646,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Denver International Airport [Member]

552,000,000

$ 7,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Holyoke [Member]

6,000,000

$ 11,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Upstream Gas Property [Member]

9,000,000

Non-recourse debt, commitment

$ 85,000,000

Non-recourse debt, commitment increase available

$ 500,000,000

22,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | SolGen [Member]

68,000,000

$ 150,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Renewable Power Generation [Member]

148,000,000

$ 150,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Continetal Wind [Member]

141,000,000

Line of credit facility, maximum borrowing capacity

$ 131,000,000

108,000,000

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] | Maximum [Member] | Senior Notes [Member]

$ 543,000,000

Exelon Generation Co L L C [Member] | Minimum [Member] | Senior Notes [Member]

7.60%

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

2.00%

Line of credit facility, maximum borrowing capacity

$ 5,300,000,000

Exelon Generation Co L L C [Member] | Line of Credit [Member]

Line of credit facility, maximum borrowing capacity

^[2]

500,000,000

^[1]

306,000,000

Exelon Generation Co L L C [Member] | Line of Credit [Member]

75,000,000

Line of credit facility, maximum borrowing capacity

$ 200,000,000

$ 150,000,000

$ 100,000,000

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

500,000,000

275,000,000

425,000,000

665,000,000

$ 665,000,000

260,000,000

617,000,000

2.00

^[1]

$ 2,000,000

7.50%

107.5

$ 7,101,000,000

6,567,000,000

7,307,000,000

Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

^[2],[4],[5]

1,000,000,000

$ 300,000,000

250,000,000

2.00

^[1]

$ 2,000,000

0.00%

90.0

$ 2,600,000,000

2,600,000,000

2,784,000,000

PECO Energy Co [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

^[2],[4],[5]

600,000,000

$ 379,000,000

75,000,000

70,000,000

2.00

^[1]

$ 0

0.00%

100.0

$ 2,341,000,000

1,870,000,000

2,599,000,000

Baltimore Gas and Electric Company [Member] | Senior Notes [Member]

Baltimore Gas and Electric Company [Member] | Maximum [Member] | Senior Notes [Member]

$ 2,300,000,000

1,750,000,000

Baltimore Gas and Electric Company [Member] | Minimum [Member] | Senior Notes [Member]

6.35%

Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]

2.40%

Line of credit facility, maximum borrowing capacity

^[2]

$ 600,000,000

5,157,000,000

5,331,000,000

Short-term Bank Loans and Notes Payable

5,157,000,000

Repayments of Bank Debt

300,000,000

$ 500,000,000

Short-term Debt, Percentage Bearing Variable Interest Rate

1.00%

950000.00%

Pepco Holdings LLC [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

$ 900,000,000

$ 1,500,000,000

Line of Credit Facility, Capacity Available for Specific Purpose Other than for Trade Purchases

$ 500,000,000

Line of Credit Facility, Maximum Amount Outstanding During Period

$ 750,000,000

1.25

$ 11,000,000

22,000,000

184,000,000

2.00

^[1]

$ 0

7.50%

107.5

$ 2,381,000,000

2,385,000,000

2,381,000,000

Potomac Electric Power Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

^[2]

300,000,000

105,000,000

$ 100,000,000

100,000,000

2.00

^[1]

$ 0

7.50%

107.5

$ 1,348,000,000

1,273,000,000

1,348,000,000

Delmarva Power and Light Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

^[2]

300,000,000

$ 48,000,000

58,000,000

$ 66,000,000

2.00

^[1]

$ 1,000,000

7.50%

107.5

$ 1,162,000,000

$ 1,210,000,000

1,162,000,000

Atlantic City Electric Company [Member] | Revolving Credit Facility [Member]

Line of credit facility, maximum borrowing capacity

^[2]

$ 300,000,000

[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
[2]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246QjFDN0Q4OTA0OTQyMUZCQTgxMDE5RjkyNUQyN0VERjAM}
[4]	Excludes $500 million and $275 million in bilateral credit facilities that do not back Generation's commercial paper program at December 31, 2016 and 2015, respectively
[5]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Income taxes			$ 761	$ 1,073	$ 666
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Income taxes			290	502	207
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Income taxes			301	280	268
PECO Energy Co [Member]
Income Taxes [Line Items]
Income taxes			149	143	114
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Income taxes			174	189	140
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Income taxes			41	102	93
Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Income taxes			22	49	65
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Income taxes			(4)	33	30
Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Income taxes		$ 3
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Income taxes	$ 17			163	138
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Current			60	407	121
Deferred			607	566	576
Investment Tax Credit			(24)	(22)	(20)
Internal Revenue Service (IRS) [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current			513	546	360
Deferred			(247)	16	(35)
Investment Tax Credit			(20)	(19)	(16)
Internal Revenue Service (IRS) [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current			(135)	(80)	(171)
Deferred			379	310	395
Investment Tax Credit			(2)	(2)	(2)
Internal Revenue Service (IRS) [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current			63	64	28
Deferred			72	69	87
Investment Tax Credit			0	0	0
Internal Revenue Service (IRS) [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current			51	25	24
Deferred			88	126	90
Investment Tax Credit			(1)	(1)	(1)
Internal Revenue Service (IRS) [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Current			(118)	(54)	(79)
Deferred			136	126	150
Investment Tax Credit			0	0	0
Internal Revenue Service (IRS) [Member] \| Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Current			(88)	(27)	(45)
Deferred			97	73	98
Investment Tax Credit			0	0	(1)
Internal Revenue Service (IRS) [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Current			(26)	(2)	(6)
Deferred			22	27	31
Investment Tax Credit			0	0	(1)
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Current		(281)
Deferred		283
Investment Tax Credit		(1)
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Current	0			12	(153)
Deferred	10			103	261
Investment Tax Credit	0			(1)	(1)
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Current			39	(86)	42
Deferred			79	208	(53)
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current			45	(90)	35
Deferred			(1)	49	(137)
State and Local Jurisdiction [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current			(4)	7	7
Deferred			63	45	39
State and Local Jurisdiction [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Current			9	(10)	(2)
Deferred			5	20	1
State and Local Jurisdiction [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current			5	0	0
Deferred			31	39	27
State and Local Jurisdiction [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Current			7	6	(2)
Deferred			16	24	24
State and Local Jurisdiction [Member] \| Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Current			1	2	0
Deferred			12	1	13
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Current			0	3	(1)
Deferred			$ 0	5	7
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Current		(11)
Deferred		$ 13
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Current	0			17	(10)
Deferred	$ 7			$ 32	$ 41

Income Taxes - Reconciliation to Effective Tax Rate (Details)

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

State income taxes, net of Federal income tax benefit (b)

35.00%

3.30%

^[1]

3.70%

1.30%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

3.40%

(0.40%)

2.40%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

(0.70%)

(2.00%)

0.00%

0.10%

Amortization of investment tax credit, including deferred taxes on basis difference

(1.20%)

(0.90%)

(1.10%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(4.80%)

(1.50%)

(1.90%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(3.60%)

(1.90%)

(2.40%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.20%)

(0.30%)

(1.80%)

(0.40%)

(1.40%)

(2.60%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

1.90%

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

5.50%

(0.60%)

0.00%

(0.20%)

38.30%

32.20%

26.80%

State income taxes, net of Federal income tax benefit (b)

35.00%

3.30%

1.00%

(1.90%)

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

7.80%

(0.80%)

4.80%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

(1.30%)

(4.10%)

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(2.30%)

(1.50%)

(2.00%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(8.20%)

(3.40%)

(4.80%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.30%)

(0.50%)

(3.70%)

(1.70%)

(2.40%)

(5.30%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

1.10%

(1.50%)

0.00%

(1.10%)

33.20%

27.10%

16.90%

State income taxes, net of Federal income tax benefit (b)

35.00%

5.60%

4.90%

4.50%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

0.00%

0.20%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.30%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(0.60%)

(0.10%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

4.50%

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

0.00%

0.10%

0.20%

0.30%

44.30%

39.70%

39.60%

State income taxes, net of Federal income tax benefit (b)

35.00%

1.30%

1.00%

(0.10%)

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(9.60%)

(8.70%)

(10.40%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

0.00%

(1.20%)

^[2]

0.20%

0.10%

25.40%

27.40%

24.50%

State income taxes, net of Federal income tax benefit (b)

35.00%

5.00%

5.30%

5.00%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

0.00%

0.10%

0.20%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.10%)

(0.30%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(2.70%)

(0.70%)

0.20%

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

0.00%

0.00%

(0.20%)

37.20%

39.60%

39.90%

State income taxes, net of Federal income tax benefit (b)

35.00%

15.70%

^[1]

6.70%

5.40%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.20%)

(0.10%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(22.80%)

(5.80%)

(4.90%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

23.50%

(1.80%)

(0.50%)

^[3]

(0.20%)

49.40%

35.30%

35.20%

State income taxes, net of Federal income tax benefit (b)

35.00%

^[4]

35.00%

52.70%

^[1],[4]

1.70%

4.80%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

^[4]

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

^[4]

(0.00%)

0.00%

^[4]

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(3.70%)

^[4]

(0.40%)

(0.30%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(25.50%)

^[4]

(2.30%)

(2.40%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

^[4]

(0.00%)

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

^[4]

112.90%

(2.20%)

^[4]

5.20%

^[3]

1.40%

169.20%

^[4]

39.20%

38.50%

State income taxes, net of Federal income tax benefit (b)

35.00%

^[4]

35.00%

6.20%

^[4]

5.70%

5.80%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

^[4]

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

^[4]

(0.00%)

0.00%

^[4]

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

0.80%

^[4]

(0.60%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

10.30%

^[4]

(1.30%)

(0.50%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

^[4]

(0.00%)

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

^[4]

(44.90%)

1.30%

^[4]

6.40%

^[3]

(0.20%)

8.70%

^[4]

45.20%

39.50%

State income taxes, net of Federal income tax benefit (b)

^[4]

35.00%

^[1],[4]

5.80%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

^[4]

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

^[4]

(0.00%)

^[4]

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

^[4]

1.40%

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

^[4]

39.00%

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

^[4]

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

^[4]

(0.70%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

^[4]

(89.00%)

^[4]

3.30%

^[4]

(5.20%)

State income taxes, net of Federal income tax benefit (b)

35.00%

^[4]

35.00%

11.90%

^[1],[4]

6.60%

5.30%

Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent

0.00%

^[4]

0.00%

Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent

(0.00%)

^[4]

(0.00%)

0.00%

^[4]

0.00%

Amortization of investment tax credit, including deferred taxes on basis difference

(0.90%)

^[4]

(0.20%)

(0.30%)

Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent

(13.50%)

^[4]

(4.30%)

(4.50%)

Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Percent

(0.00%)

^[4]

(0.00%)

(0.00%)

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent

^[4]

(0.00%)

Effective Income Tax Rate Reconciliation, Deduction, Other, Percent

^[4]

11.10%

3.60%

^[4]

(3.20%)

^[3]

0.80%

Internal Revenue Service (IRS) [Member]

47.20%

^[4]

33.90%

36.30%

[1]	Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.
[2]	At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.
[3]	Includes impacts of the PHI Global Settlement for Pepco, DPL, ACE, and PHI
[4]	DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2016	Mar. 24, 2016	Dec. 31, 2015
Operating Loss Carryforwards [Line Items]
Plant basis differences	$ (17,966)		$ (13,393)
Accrual based contracts	434		(136)
Derivatives and other financial instruments	(179)		(203)
Deferred pension and postretirement obligation	2,287		1,801
Nuclear decommissioning activities	(509)		(592)
Deferred debt refinancing costs	325		133
Deferred Tax Liabilities, Regulatory Assets and Liabilities	3,319		1,706
Tax loss carryforward	189		103
Tax credit carryforward	446		327
Investment in CENG	(650)		(595)
Other, net	1,485	$ (59)	1,112
Deferred income tax liabilities (net)	(17,457)		(13,149)
Unamortized investment tax credits	(658)		(622)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(18,115)		(13,771)
Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(4,192)		(4,269)
Accrual based contracts	(115)		(136)
Derivatives and other financial instruments	(162)		(181)
Deferred pension and postretirement obligation	(316)		(371)
Nuclear decommissioning activities	(509)		(592)
Deferred debt refinancing costs	44		48
Regulatory assets and liabilities			0
Deferred Tax Liabilities, Regulatory Assets and Liabilities	0
Tax loss carryforward	61		56
Tax credit carryforward	493		374
Investment in CENG	(650)		(595)
Other, net	403		425
Deferred income tax liabilities (net)	(4,943)		(5,241)
Unamortized investment tax credits	(626)		(598)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(5,569)		(5,839)
Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(5,034)		(4,424)
Accrual based contracts	0		0
Derivatives and other financial instruments	(3)		(4)
Deferred pension and postretirement obligation	(453)		(505)
Nuclear decommissioning activities	0		0
Deferred debt refinancing costs	13		15
Deferred Tax Liabilities, Regulatory Assets and Liabilities	226		219
Tax loss carryforward	29		0
Tax credit carryforward	0		0
Investment in CENG	0		0
Other, net	351		270
Deferred income tax liabilities (net)	(5,349)		(4,897)
Unamortized investment tax credits	(15)		(17)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(5,364)		(4,914)
PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(3,095)		(2,901)
Accrual based contracts	0		0
Derivatives and other financial instruments	0		0
Deferred pension and postretirement obligation	(18)		(9)
Nuclear decommissioning activities	0		0
Deferred debt refinancing costs	1		1
Deferred Tax Liabilities, Regulatory Assets and Liabilities	10		(16)
Tax loss carryforward	0		0
Tax credit carryforward	0		0
Investment in CENG	0		0
Other, net	99		105
Deferred income tax liabilities (net)	(3,005)		(2,790)
Unamortized investment tax credits	(1)		(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(3,006)		(2,792)
Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,977)		(1,821)
Accrual based contracts	0		0
Derivatives and other financial instruments	0		0
Deferred pension and postretirement obligation	(43)		(47)
Nuclear decommissioning activities	0		0
Deferred debt refinancing costs	3		4
Deferred Tax Liabilities, Regulatory Assets and Liabilities	240		264
Tax loss carryforward	22		33
Tax credit carryforward	0		0
Investment in CENG	0		0
Other, net	27		27
Deferred income tax liabilities (net)	(2,214)		(2,076)
Unamortized investment tax credits	(5)		(5)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(2,219)		(2,081)
Potomac Electric Power Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(1,678)		(1,599)
Accrual based contracts	0		0
Derivatives and other financial instruments	0		0
Deferred pension and postretirement obligation	(122)		(95)
Nuclear decommissioning activities	0		0
Deferred debt refinancing costs	7		8
Deferred Tax Liabilities, Regulatory Assets and Liabilities	194		202
Tax loss carryforward	27		141
Tax credit carryforward	0		0
Investment in CENG	0		0
Other, net	66		42
Deferred income tax liabilities (net)	(1,908)		(1,721)
Unamortized investment tax credits	(2)		(2)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(1,910)		(1,723)
Delmarva Power and Light Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(973)		(915)
Accrual based contracts	0		0
Derivatives and other financial instruments	0		0
Deferred pension and postretirement obligation	(74)		(82)
Nuclear decommissioning activities	0		0
Deferred debt refinancing costs	4		4
Deferred Tax Liabilities, Regulatory Assets and Liabilities	75		91
Tax loss carryforward	39		122
Tax credit carryforward	0		0
Investment in CENG	0		0
Other, net	34		29
Deferred income tax liabilities (net)	(1,053)		(941)
Unamortized investment tax credits	(3)		(4)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(1,056)		(945)
Atlantic City Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(869)		(791)
Accrual based contracts	0		0
Derivatives and other financial instruments	0		0
Deferred pension and postretirement obligation	(21)		(20)
Nuclear decommissioning activities	0		0
Deferred debt refinancing costs	2		3
Deferred Tax Liabilities, Regulatory Assets and Liabilities	69		93
Tax loss carryforward	14		8
Tax credit carryforward	0		0
Investment in CENG	0		0
Other, net	34		18
Deferred income tax liabilities (net)	(913)		(881)
Unamortized investment tax credits	(4)		(4)
Total deferred income tax liabilities (net) and unamortized investment tax credits	(917)		(885)
Pepco Holdings LLC [Member] \| Successor [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	(3,586)
Accrual based contracts	548
Derivatives and other financial instruments	(1)
Deferred pension and postretirement obligation	(111)
Nuclear decommissioning activities	0
Deferred debt refinancing costs	293
Deferred Tax Liabilities, Regulatory Assets and Liabilities	1,205
Tax loss carryforward	77
Tax credit carryforward	0
Investment in CENG	0
Other, net	225
Deferred income tax liabilities (net)	(3,760)
Unamortized investment tax credits	(9)
Total deferred income tax liabilities (net) and unamortized investment tax credits	$ (3,769)
Pepco Holdings LLC [Member] \| Predecessor [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences			(3,342)
Accrual based contracts			0
Derivatives and other financial instruments			(1)
Deferred pension and postretirement obligation			(92)
Nuclear decommissioning activities			0
Deferred debt refinancing costs			15
Deferred Tax Liabilities, Regulatory Assets and Liabilities			414
Tax loss carryforward			378
Tax credit carryforward			6
Investment in CENG			0
Other, net		$ (8)	103
Deferred income tax liabilities (net)			(3,377)
Unamortized investment tax credits			(15)
Total deferred income tax liabilities (net) and unamortized investment tax credits			$ (3,392)

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details)
$ in Millions

Dec. 31, 2016

USD ($)

State net operating losses and credit carryforwards

$ 99

282

^[1]

Internal Revenue Service (IRS) [Member] | Exelon Generation Co L L C [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | Commonwealth Edison Co [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | PECO Energy Co [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | Baltimore Gas and Electric Company [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | Potomac Electric Power Company [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | Delmarva Power and Light Company [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | Atlantic City Electric Company [Member]

State net operating losses and credit carryforwards

Internal Revenue Service (IRS) [Member] | Pepco Holdings LLC [Member] | Successor [Member]

State net operating losses and credit carryforwards

121

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Exelon Generation Co L L C [Member]

511

^[2]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Commonwealth Edison Co [Member]

509

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | PECO Energy Co [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Baltimore Gas and Electric Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Potomac Electric Power Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Delmarva Power and Light Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Atlantic City Electric Company [Member]

Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Pepco Holdings LLC [Member] | Successor [Member]

State and Local Jurisdiction [Member]

State net operating losses and credit carryforwards

3,501

^[3]

186

State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member]

State net operating losses and credit carryforwards

1,245

^[3]

State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member]

State net operating losses and credit carryforwards

State and Local Jurisdiction [Member] | PECO Energy Co [Member]

State net operating losses and credit carryforwards

State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member]

State net operating losses and credit carryforwards

425

^[4]

State and Local Jurisdiction [Member] | Potomac Electric Power Company [Member]

State net operating losses and credit carryforwards

360

^[5]

State and Local Jurisdiction [Member] | Delmarva Power and Light Company [Member]

State net operating losses and credit carryforwards

639

^[6]

State and Local Jurisdiction [Member] | Atlantic City Electric Company [Member]

State net operating losses and credit carryforwards

272

^[7]

State and Local Jurisdiction [Member] | Pepco Holdings LLC [Member] | Successor [Member]

State net operating losses and credit carryforwards

1,522

^[8]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 10

[1]	Exelon's federal net operating loss will begin expiring in 2032.
[2]	Exelon’s federal general business credit carryforwards will begin expiring in 2033.
[3]	Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2017.
[4]	BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026
[5]	Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2028
[6]	DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.
[7]	ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2032.
[8]	PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	$ 1,078	$ 1,829	$ 2,175
Increases based on tax positions related to current year	108	108	15
Unrecognized Tax Benefits, Increase Resulting from Acquisition	22
Unrecognized Tax Benefits, Period Increase (Decrease)	(332)	(705)	(255)
Increases based on tax positions prior to current year	88	79	18
Decreases based on tax positions prior to current year	(21)	(116)	(1)
Decrease from settlements with taxing authorities	(27)	(31)	(35)
Unrecognized tax benefits - ending balance	916	1,078	1,829
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	(86)	(88)
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	534	1,357	1,415
Increases based on tax positions related to current year	10	0	15
Unrecognized Tax Benefits, Increase Resulting from Acquisition	5
Unrecognized Tax Benefits, Period Increase (Decrease)	(12)	(659)	33
Increases based on tax positions prior to current year	0	65	18
Decreases based on tax positions prior to current year	(20)	(112)	(2)
Decrease from settlements with taxing authorities	(27)	(31)	(34)
Unrecognized tax benefits - ending balance	490	534	1,357
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	(86)	(88)
Commonwealth Edison Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	142	149	324
Increases based on tax positions related to current year	0	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	(154)	(7)	(175)
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	0
Unrecognized tax benefits - ending balance	(12)	142	149
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	0
PECO Energy Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	0	44	44
Increases based on tax positions related to current year	0	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	(44)	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	0
Unrecognized tax benefits - ending balance	0	0	44
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	0
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	120	0	0
Increases based on tax positions related to current year	0	106	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0	0
Increases based on tax positions prior to current year	0	14	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized tax benefits - ending balance	120	120	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	0
Potomac Electric Power Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	8	0	45
Increases based on tax positions related to current year	21	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0	(45)
Increases based on tax positions prior to current year	51	8	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized tax benefits - ending balance	80	8	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	0
Delmarva Power and Light Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	3	0	3
Increases based on tax positions related to current year	16	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0	(3)
Increases based on tax positions prior to current year	18	3	0
Decreases based on tax positions prior to current year	0	0	0
Decrease from settlements with taxing authorities	0	0	0
Unrecognized tax benefits - ending balance	37	3	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	0
Atlantic City Electric Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	0	0	3
Increases based on tax positions related to current year	22	0	0
Unrecognized Tax Benefits, Period Increase (Decrease)	0	0	(3)
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	0
Unrecognized tax benefits - ending balance	22	0	0
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0	0	0
Pepco Holdings LLC [Member] \| Successor [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	22
Increases based on tax positions related to current year	59
Unrecognized Tax Benefits, Increase Resulting from Acquisition	(5)
Unrecognized Tax Benefits, Period Increase (Decrease)	0
Increases based on tax positions prior to current year	96
Decreases based on tax positions prior to current year	0
Decrease from settlements with taxing authorities	0
Unrecognized tax benefits - ending balance	172	22
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations	0
Pepco Holdings LLC [Member] \| Predecessor [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance	$ 22	702	743
Increases based on tax positions related to current year		0	0
Unrecognized Tax Benefits, Period Increase (Decrease)		(688)	(41)
Increases based on tax positions prior to current year		11	0
Decreases based on tax positions prior to current year		0	0
Decrease from settlements with taxing authorities		0	0
Unrecognized tax benefits - ending balance		22	702
Unrecognized Tax Benefits, Reduction Resulting from Lapse of Applicable Statute of Limitations		$ (3)	$ 0

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended		12 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Mar. 23, 2016	Dec. 31, 2015	Mar. 31, 2013	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 15, 2016	Mar. 31, 2016	Mar. 24, 2016	Dec. 15, 2015	Dec. 31, 2013	Dec. 31, 1999
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits		$ 415		$ 83		$ 83	$ 415	$ 1,122
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		538		633		633	538	701
Unrecognized Tax Benefits		1,078		916		916	1,078	1,829					$ 2,175
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities						8
Common Stock, Value, Issued		(1,112)		(1,485)		(1,485)	(1,112)				$ 59
Deferred Tax Assets, State Taxes				1		1
Unrecognized Tax Benefits						21	116	1
IRS asserted penalties for understatement of tax						106
Taxes accrued		293		723		723	293
Unrecognized Tax Benefits, Income Tax Penalties Accrued				106		106
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits		20		7		7	20	680
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		509		483		483	509	672
Unrecognized Tax Benefits		534		490		490	534	1,357					1,415
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities						14
Common Stock, Value, Issued		(425)		(403)		(403)	(425)
Deferred Tax Assets, State Taxes				6		6
Allocation of federal tax benefit under tax sharing agreement		57		94		94	57	55
Unrecognized Tax Benefits						20	112	2
Taxes accrued		186		239		239	186
Unrecognized Tax Benefits, Income Tax Penalties Accrued				0		0
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits		120		120		120	120	0	$ 120			$ 120	0
Common Stock, Value, Issued		(27)		(27)		(27)	(27)
Proceeds from Contributions from Parent						61	7	0
Allocation of federal tax benefit under tax sharing agreement		7		8		8	7
Unrecognized Tax Benefits						0	0	0
Taxes accrued		23		78		78	23
Unrecognized Tax Benefits, Income Tax Penalties Accrued				0		0
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				21		21
Unrecognized Tax Benefits		8		80		80	8	0	59			8	45
Common Stock, Value, Issued		(42)		(66)		(66)	(42)
Tax Adjustments, Settlements, and Unusual Provisions		6
Unrecognized Tax Benefits, Interest on Income Taxes Expense		3
Proceeds from Contributions from Parent						187	112	80
Unrecognized Tax Benefits						0	0	0
Taxes accrued		56		48		48	56
Unrecognized Tax Benefits, Income Tax Penalties Accrued				0		0
Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				16		16
Unrecognized Tax Benefits		3		37		37	3	0	21			3	3
Common Stock, Value, Issued		(29)		(34)		(34)	(29)
Tax Adjustments, Settlements, and Unusual Provisions		3
Proceeds from Contributions from Parent						152	75	130
Unrecognized Tax Benefits						0	0	0
Taxes accrued		3		4		4	3
Unrecognized Tax Benefits, Income Tax Penalties Accrued				0		0
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits		142		(12)		(12)	142	149
Unrecognized Tax Benefits		142		(12)		(12)	142	149					324
Common Stock, Value, Issued		(270)		(351)		(351)	(270)
Proceeds from Contributions from Parent						315	202	273
Unrecognized Tax Benefits						0	0	0
IRS asserted penalties for understatement of tax						86
Taxes accrued		63		330		330	63
Unrecognized Tax Benefits, Income Tax Penalties Accrued				86		86
PECO Energy Co [Member]
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits								43
Unrecognized Tax Benefits		0		0		0	0	44					44
Common Stock, Value, Issued		(105)		(99)		(99)	(105)
Proceeds from Contributions from Parent						18	16	24
Allocation of federal tax benefit under tax sharing agreement		16		18		18	16	25
Unrecognized Tax Benefits						0	0	0
Taxes accrued		4		4		4	4
Unrecognized Tax Benefits, Income Tax Penalties Accrued				0		0
Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				93		93
Unrecognized Tax Benefits		22		172		172	22		$ 80
Common Stock, Value, Issued				(225)		(225)
Proceeds from Contributions from Parent				1,251
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent				35		35
Unrecognized Tax Benefits						0
Taxes accrued				65		65
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits								686
Unrecognized Tax Benefits that Would Impact Effective Tax Rate		11					11	15
Unrecognized Tax Benefits		22					22	702				$ 11	743
Common Stock, Value, Issued		(103)					(103)				$ 8
Tax Adjustments, Settlements, and Unusual Provisions		35
Federal Income Tax Expense (Benefit), Continuing Operations		26
Discontinued Operation, Tax Effect of Discontinued Operation		9
Unrecognized Tax Benefits, Interest on Income Taxes Expense		21
Unrecognized Tax Benefits							0	0
Taxes accrued		77					77
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				22		22
Unrecognized Tax Benefits		0		22		22	0	0					$ 3
Common Stock, Value, Issued		(18)		(34)		(34)	(18)
Tax Adjustments, Settlements, and Unusual Provisions		3
Proceeds from Contributions from Parent						139	95	0
Unrecognized Tax Benefits						0	0	0
Taxes accrued		$ 23		9		9	23
Unrecognized Tax Benefits, Income Tax Penalties Accrued				0		0
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				146		146
Deferred						607	566	576
Internal Revenue Service (IRS) [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				19		19
Deferred						(247)	16	(35)
Internal Revenue Service (IRS) [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Deferred						88	126	90
Internal Revenue Service (IRS) [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				21		21
Deferred						136	126	150
Internal Revenue Service (IRS) [Member] \| Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				16		16
Deferred						97	73	98
Internal Revenue Service (IRS) [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Deferred						379	310	395
Internal Revenue Service (IRS) [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Deferred						72	69	87
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				59		59
Deferred				283
Internal Revenue Service (IRS) [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Deferred	$ 10						103	261
Internal Revenue Service (IRS) [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				22		22
Deferred						22	27	31
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				244		244
Unrecognized Tax Benefits that Would Impact Effective Tax Rate				44		44
Deferred						79	208	(53)
State and Local Jurisdiction [Member] \| Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				44		44
Deferred						(1)	49	(137)
State and Local Jurisdiction [Member] \| Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				120		120
Deferred						31	39	27
State and Local Jurisdiction [Member] \| Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				59		59
Deferred						16	24	24
State and Local Jurisdiction [Member] \| Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				21		21
Deferred						12	1	13
State and Local Jurisdiction [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Deferred						63	45	39
State and Local Jurisdiction [Member] \| PECO Energy Co [Member]
Income Taxes [Line Items]
Deferred						5	20	1
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit				80		80
Deferred				13
State and Local Jurisdiction [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Deferred	$ 7						32	41
State and Local Jurisdiction [Member] \| Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Deferred						0	$ 5	$ 7
Like kind exchange [Member]
Income Taxes [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions					$ 106
Income Tax Examination, Interest Expense					94
Deferred						400
Payments for Other Taxes						1,000
Income Taxes Receivable				80		80
Investment Agreement, Early Termination Fee						1,250
Deferred gain on sale of property														$ 1,200
IRS asserted penalties for understatement of tax						90
Expected non-cash charge to earnings			$ 265
Taxes accrued				335		335				$ 360
Unrecognized Tax Benefits, Income Tax Penalties Accrued				1,400		1,400
Like kind exchange [Member] \| Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Tax Adjustments, Settlements, and Unusual Provisions					86
Income Tax Examination, Interest Expense					64
Proceeds from Contributions from Parent					$ 150
Payments for Other Taxes						0
Income Taxes Receivable				345		345
Expected non-cash charge to earnings			172
Noncash contributions from parent			$ 172
Unrecognized Tax Benefits, Income Tax Penalties Accrued				$ 300		$ 300

Income Taxes - Summary of Interest Receivable (Payable) (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	$ (507)	$ (288)
Unrecognized Tax Benefits, Income Tax Penalties Accrued	(106)
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	46	80
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	(384)	(210)
Unrecognized Tax Benefits, Income Tax Penalties Accrued	(86)
PECO Energy Co [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	8	3
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	(1)	(1)
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	1	20
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0
Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	0	3
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	1	24
Unrecognized Tax Benefits, Income Tax Penalties Accrued	0
Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions	$ 2
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Net Interest Receivable Payable Related To Uncertain Tax Positions		$ (34)

Income Taxes - Summary of Interest Expense (Income) (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			$ 106
Net interest (income) expense recognized related to uncertain tax positions			165	$ (13)	$ (36)
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			(13)	(31)	(50)
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits, Income Tax Penalties Expense			86
Net interest (income) expense recognized related to uncertain tax positions			117	7	6
PECO Energy Co [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			0	0	0
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			0	0	1
Potomac Electric Power Company [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			6	(4)	(1)
Delmarva Power and Light Company [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			0	0	0
Atlantic City Electric Company [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions			$ (1)	0	(1)
Pepco Holdings LLC [Member] \| Successor [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions		$ (2)
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	$ 0			$ (34)	$ 0

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

^[1]

$ 446

$ 398

$ 345

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

446

397

345

$ 285

1,300

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

$ 10

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 8,246

8,246

6,961

436

387

Costs incurred to decommission retired plants

901

(9)

(3)

8,734

8,246

$ 6,961

^[2]

$ 90

$ 99

[1]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

Asset Retirement Obligations - Narrative (Details) - USD ($)	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligations [Line Items]
Asset Retirement Obligations, Noncurrent	$ 9,111,000,000		$ 9,111,000,000	$ 8,585,000,000
Asset Retirement Obligation, Revision of Estimate			$ 2,000,000
Percent of additional decommissioning shortfall with recourse	50.00%		50.00%
Nuclear decommissioning trust funds	$ 11,061,000,000		$ 11,061,000,000	10,342,000,000
Spent Nuclear Fuel Obligation, Noncurrent	1,024,000,000		1,024,000,000	1,021,000,000
Decommissioning Liability, Noncurrent	14,000,000		14,000,000	90,000,000
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)	165,000,000		288,000,000
Asset Retirement Obligations, Noncurrent	8,922,000,000		8,922,000,000	8,431,000,000
Asset Retirement Obligation, Revision of Estimate		$ 285,000,000		1,300,000,000
Shortfall of decommissioning funds with recourse	$ 50,000,000		$ 50,000,000
Percent of additional decommissioning shortfall with recourse	5.00%		5.00%
Nuclear decommissioning trust funds	$ 11,061,000,000		$ 11,061,000,000	10,342,000,000
Spent Nuclear Fuel Obligation, Noncurrent	1,024,000,000		1,024,000,000	1,021,000,000
ZionSolutions rent payable	1		1
EnergySolutions letter of credit	200,000,000		$ 200,000,000
Annual average accretion of the ARO			5.00%
Number of years used in present value measurement			30 years
Historical five-year annual average after-tax return on NDT funds			8.00%
Decommissioning Liability, Noncurrent	$ 14,000,000		$ 14,000,000	90,000,000
Exelon Generation Co L L C [Member] \| Minimum [Member]
Asset Retirement Obligations [Line Items]
Investment Interest Rate			2.00%
Years after cessation of plant operations			10 years
Estimated annual after tax return on nuclear decommissioning funds	5.30%		5.30%
Exelon Generation Co L L C [Member] \| Maximum [Member]
Asset Retirement Obligations [Line Items]
Investment Interest Rate			3.00%
Years after cessation of plant operations			70 years
Estimated annual after tax return on nuclear decommissioning funds	5.90%		5.90%
Nuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligations [Line Items]
Proceeds from Customers			$ 24,000,000
Nuclear Decommissioning Asset Retirement Obligation [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Revision of Estimate	$ 89,000,000		61,000,000	901,000,000
Nuclear Plant [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Period Increase (Decrease)			488,000,000	$ 630,000,000
Zion Station [Member] \| Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Decommissioning Liability, Noncurrent	$ 111,000,000		$ 111,000,000

Asset Retirement Obligations - Unrealized Gain on NDT Funds (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units

^[1]

$ 216

$ (282)

$ 180

Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units

^[2],[3]

194

(197)

134

Unrealized Gain Loss Investment Income Pledged Assets

$ (1)

$ 7

$ 29

[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 $(1) million, $7 million and $29 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2016, 2015 and 2014, 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, 2016

Dec. 31, 2015

Carrying value of Zion Station pledged assets

$ 113

$ 206

Asset Retirement Obligations, Noncurrent

9,111

8,585

Carrying value of Zion Station pledged assets

113

206

Asset Retirement Obligations, Noncurrent

8,922

8,431

Decommissioning Funds Withdrawal

^[1]

878

786

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

Carrying value of Zion Station pledged assets

113

206

Payable to Zion Solutions

^[2]

104

189

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[3]

$ 90

$ 99

[1]	(c)Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.
[2]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[3]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2016

Mar. 23, 2016

Dec. 31, 2016

Sep. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 2

^[1]

446

$ 398

$ 345

Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 355

^[2]

$ 355

^[2]

355

^[2]

346

^[3]

$ 8

(10)

^[4]

^[5]

(11)

(5)

$ 393

^[2]

393

^[2]

393

^[2]

355

^[2]

346

Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

^[3]

(10)

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

285

1,300

Asset Retirement Obligation, Period Increase (Decrease)

^[1]

446

397

345

165

288

285

1,300

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

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

(2)

Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

(2)

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

197

^[2]

197

^[2]

197

^[2]

194

^[3]

(12)

^[4]

^[5]

(6)

(3)

199

^[2]

199

^[2]

199

^[2]

197

^[2]

194

^[3]

(12)

Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[3]

(4)

^[4]

^[5]

(1)

^[2]

PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

^[3]

(4)

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[3]

^[4]

^[5]

(1)

^[2]

^[3]

Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Pepco Holdings LLC [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Successor [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[3]

^[4]

^[5]

^[2]

Pepco Holdings LLC [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Successor [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

^[3]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Pepco Holdings LLC [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Predecessor [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[5]

^[2]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Potomac Electric Power Company [Member] | Predecessor [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Potomac Electric Power Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[3]

^[4]

^[5]

^[2]

Potomac Electric Power Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

^[3]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

Delmarva Power and Light Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[3]

^[4]

^[5]

^[2]

Delmarva Power and Light Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

^[3]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[1]

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

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Atlantic City Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

^[2]

^[3]

^[4]

^[5]

^[2]

Atlantic City Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

^[3]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]

^[1]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 113

^[2]

$ 113

^[2]

113

^[2]

104

^[3]

^[4]

^[5]

(3)

(2)

121

^[2]

121

^[2]

121

^[2]

113

^[2]

$ 104

^[3]

Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member] | Disposal Group, Held-for-sale, Not Discontinued Operations [Member]

$ 2

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Asset Retirement Obligation, Period Increase (Decrease)

^[6]

$ 0

[1]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[2]	Excludes $1 million, $2 million and $3 million as the current portion of the ARO at December 31, 2016 for Generation, ComEd and BGE, respectively. Excludes $5 million, $2 million and $1 million as the current portion of the ARO at December 31, 2015 for Generation, ComEd and BGE, respectively. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.
[3]	During the year ended December 31, 2016, Generation recorded an increase of $1 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, 2016. 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.
[4]	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.
[5]	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.
[6]	Reflects a reduction to the ARO resulting primarily from the sales of the New Boston generating site and Upstream business in 2016 and Schuylkill generating station in 2015. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.

Retirement Benefits - Narrative (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2016

Jan. 01, 2016

Dec. 31, 2014

Jun. 30, 2016

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Increase (Decrease) in Pension Plan Obligations

$ 35

Benefit obligation increase (decrease) reflecting actual census data

AOCI valuation adjustment

Regulatory asset increase (decrease) due to updated valuation adjustment

Defined benefit plan, amounts recognized In regulatory liabilities, before tax

$ 3

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 310

Expected other postretirement benefit plan contributions

$ 44

Projected Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Accumulated Benefit Obligation In Excess Of Plan Assets [Member]

80.00%

81.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

84.00%

85.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 127

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Increase (decrease) in pension obligation

$ 25

Pepco Holdings LLC [Member] | Projected Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Pepco Holdings LLC [Member] | Accumulated Benefit Obligation In Excess Of Plan Assets [Member]

81.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

89.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

Expected other postretirement benefit plan contributions

Constellation Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 21

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.04%

3.94%

4.04%

4.29%

3.94%

Regulatory asset increase (decrease) due to updated valuation adjustment

$ 644

$ 476

$ 1,639

$ 959

$ (46)

$ 415

7.00%

^[1]

7.00%

^[1]

7.00%

^[1]

Increase (decrease) in pension obligation

4.29%

^[2]

3.94%

^[3]

4.80%

^[4]

$ 361

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 1,360

(554)

$ (571)

$ (420)

(60)

(14)

(13)

(14)

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax

(2)

^[5]

$ 1,010

(110)

$ 1,203

Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.20%

Regulatory asset increase (decrease) due to updated valuation adjustment

$ 0

$ 276

$ (13)

$ (6)

$ 212

^[1]

6.50%

7.00%

^[2]

4.20%

5.05%

$ (14)

$ (65)

$ (45)

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax

(2)

^[5]

$ (14)

$ (17)

$ 229

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

^[1]

5.00%

Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

6.50%

Other Postretirement Benefit Plan, Defined Benefit [Member]

3.96%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.04%

3.92%

4.04%

4.29%

3.92%

Regulatory asset increase (decrease) due to updated valuation adjustment

$ (101)

$ (194)

$ 561

$ 95

$ (60)

$ (217)

6.60%

6.71%

^[1]

6.50%

^[1]

6.59%

^[1]

Increase (decrease) in pension obligation

4.29%

^[2]

3.92%

^[3]

4.90%

^[4]

$ 117

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$ 244

(63)

$ (80)

$ (50)

(23)

(1,012)

185

174

122

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax

^[5]

$ 115

$ (123)

$ (379)

Other Postretirement Benefit Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.15%

4.55%

4.15%

Regulatory asset increase (decrease) due to updated valuation adjustment

$ 0

$ (39)

$ 62

$ 1

$ (34)

$ 72

^[1]

6.75%

7.25%

^[2]

4.55%

4.15%

5.00%

$ (2)

$ (8)

$ (3)

Defined Benefit Plan Accumulated Other Comprehensive Income And Regulatory Assets Before Tax

^[5]

$ 1

$ (34)

$ 72

Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase

^[1]

5.00%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

6.75%

3.80%

[1]	Not applicable to pension and other postretirement benefit plans that do not have plan asset
[2]	)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2016. Certain benefit plans used individual rates ranging from 3.68%-4.14% and 4.32%-4.43% for pension and other postretirement plans, respectivel
[3]	The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2015. Certain benefit plans used individual rates ranging from 3.29%-3.82% and 3.99%-4.06% for pension and other postretirement plans, respectively.
[4]	The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 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 for 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.
[5]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246QjAwMzBCMDJERTBGRUQzOTAyOTc5RjkyNUQyMzhDMUEM}

Retirement Benefits - Summary of Changes in Benefit Obligations (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

$ 17,753

$ 18,256

354

326

$ 293

830

710

749

567

(582)

Plan amendments

(60)

2,667

^[1]

(34)

(1,051)

(923)

Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

21,060

17,753

18,256

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

2,490

2,638

109

(30)

(151)

(2)

(163)

Other Postretirement Benefit Plan, Defined Benefit [Member]

2,496

2,490

2,638

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

3,938

4,197

107

119

117

185

167

186

(136)

(341)

Plan amendments

(23)

589

^[1]

(280)

(223)

Other Postretirement Benefit Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

4,457

3,938

4,197

Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]

563

$ 563

632

(5)

(61)

(1)

(39)

$ 564

$ 563

$ 632

[1]	____________________ (a)

Retirement Benefits - Summary of Changes in Plan Assets (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

$ 14,347

$ 14,874

1,061

(32)

347

462

(1,051)

(923)

2,087

^[1]

(34)

Other Postretirement Benefit Plan, Defined Benefit [Member]

16,791

14,347

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

2,293

2,430

128

(280)

(223)

333

^[1]

Predecessor [Member] | Pepco Holdings LLC [Member] | Pension Plan, Defined Benefit [Member]

2,578

2,293

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

2,018

2,236

(61)

(2)

(163)

Predecessor [Member] | Pepco Holdings LLC [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

2,020

2,018

Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]

348

$ 348

367

Defined Benefit Plan, Other Changes

(1)

(39)

$ 348

[1]	____________________ (a)

Retirement Benefits - Balance Sheet locations of Benefit Obligations and Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	$ 21	$ 21
Pension obligations	4,248	3,385
Non-pension postretirement benefit obligations	0	0
Unfunded status (net benefit obligation less plan assets)	4,269	3,406
Pension Plan, Defined Benefit [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities		6
Pension obligations		466
Non-pension postretirement benefit obligations		0
Unfunded status (net benefit obligation less plan assets)		472
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	31	27
Pension obligations	0	0
Non-pension postretirement benefit obligations	1,848	1,618
Unfunded status (net benefit obligation less plan assets)	$ 1,879	1,645
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Pepco Holdings LLC [Member] \| Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities		0
Pension obligations		0
Non-pension postretirement benefit obligations		215
Unfunded status (net benefit obligation less plan assets)		$ 215

Retirement Benefits - Projected Benefit Obligations and Accumulated Benefit Obligations in Excess of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Projected Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$ 21,060	$ 17,753
Fair value of net plan assets	16,791	14,347
Accumulated Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 19,930	16,792
Predecessor [Member] \| Pepco Holdings LLC [Member] \| Projected Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation		2,490
Fair value of net plan assets		2,018
Predecessor [Member] \| Pepco Holdings LLC [Member] \| Accumulated Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation		$ 2,275

Retirement Benefits - Components of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		$ 354	$ 326	$ 293
Interest cost		830	710	749
Expected return on assets		(1,141)	(1,026)	(994)
Prior service cost (credit)		14	13	14
Actuarial loss		554	571	420
Settlement and other charges(b)		2	2	2
Net periodic benefit cost		613	596	484
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		107	119	117
Interest cost		185	167	186
Expected return on assets		(162)	(151)	(154)
Prior service cost (credit)		(185)	(174)	(122)
Actuarial loss		63	80	50
Settlement and other charges(b)		0	0	0
Net periodic benefit cost		$ 8	41	77
Predecessor [Member] \| Pension Plan, Defined Benefit [Member] \| Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 12		57	44
Interest cost	26		109	109
Expected return on assets	(30)		(140)	(141)
Prior service cost (credit)	0		2	2
Actuarial loss	14		65	45
Net periodic benefit cost	22		93	59
Predecessor [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member] \| Pepco Holdings LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1		7	7
Interest cost	6		24	26
Expected return on assets	(5)		(22)	(24)
Prior service cost (credit)	(3)		(13)	(13)
Actuarial loss	2		8	3
Net periodic benefit cost	$ 1		$ 4	$ (1)

Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets (Liabilities) related to Retirement Plans (Details) - USD ($)
$ in Millions

3 Months Ended

12 Months Ended

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 27

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.04%

4.29%

3.94%

$ 644

$ 476

$ 1,639

(554)

(571)

(420)

(60)

DefinedBenefitPlanAccumulatedOtherComprehensiveIncomeAndRegulatoryAssetsAcqusition

(14)

(13)

(14)

994

Total recognized in AOCI and regulatory assets (liabilities)

(2)

^[1]

1,010

(110)

1,203

Defined benefit plan, amounts recognized in OCI, before tax

(64)

788

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 959

$ (46)

$ 415

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.04%

4.29%

3.92%

$ (101)

$ (194)

$ 561

(63)

(80)

(50)

(23)

(1,012)

DefinedBenefitPlanAccumulatedOtherComprehensiveIncomeAndRegulatoryAssetsAcqusition

185

174

122

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

115

(123)

(379)

Defined benefit plan, amounts recognized in OCI, before tax

(63)

(162)

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 95

(60)

$ (217)

Predecessor [Member] | Pepco Holdings LLC [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.20%

$ 0

$ 276

(14)

(65)

(45)

Total recognized in AOCI and regulatory assets (liabilities)

(2)

^[1]

(14)

(17)

229

Defined benefit plan, amounts recognized in OCI, before tax

(1)

(11)

Defined benefit plan, amounts recognized in regulatory assets, before tax

(13)

$ (6)

$ 212

Predecessor [Member] | Pepco Holdings LLC [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate

4.55%

4.15%

$ (39)

$ 62

(2)

(8)

(3)

Total recognized in AOCI and regulatory assets (liabilities)

^[1]

(34)

Defined benefit plan, amounts recognized in OCI, before tax

Defined benefit plan, amounts recognized in regulatory assets, before tax

$ 1

$ (34)

$ 72

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246QjAwMzBCMDJERTBGRUQzOTAyOTc5RjkyNUQyMzhDMUEM}

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, 2016

Dec. 31, 2015

$ (31)

$ 36

8,387

7,310

Benefits included in accumulated other comprehensive income

^[1]

8,356

7,346

4,297

4,246

Other Postretirement Benefit Plan, Defined Benefit [Member]

4,059

3,100

(710)

(812)

724

711

Benefits included in accumulated other comprehensive income

^[1]

(101)

(42)

(63)

Predecessor [Member] | Pepco Holdings [Member] | Pension Plan, Defined Benefit [Member]

$ 56

(38)

910

Benefits included in accumulated other comprehensive income

^[1]

916

Predecessor [Member] | Pepco Holdings [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

870

(88)

128

Benefits included in accumulated other comprehensive income

^[1]

$ 40

[1]

. Retirement Benefits (All Registrants) As of December 31, 2016, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all employees. Effective March 23, 2016, Exelon became the sponsor of all of PHI's defined benefit pension and other postretirement benefit plans, and assumed PHI's benefit plan obligations and related assets. As a result, PHI's benefit plan net obligation and related regulatory assets were transferred to Exelon and remeasured at the merger date using current assumptions, including discount rates. The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2016. Operating Company(e)Name of Plan: Generation ComEd PECO BGE BSC PHI Pepco DPL ACEQualified 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 Pepco Holdings LLC Retirement Plan(d) X X X X XNon-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 Energy 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 Pepco Holdings LLC 2011 Supplemental Executive Retirement Plan(d) X X X X XConectiv Supplemental Executive Retirement Plan (d) X X X XPepco Holdings LLC Combined Executive Retirement Plan (d) X X X Atlantic City Electric Director Retirement Plan (d) X X Operating Company(e)Name of Plan: Generation ComEd PECO BGE BSC PHI Pepco DPL ACEOther 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 Exelon Corporation Health Reimbursement Arrangement 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 Pepco Holdings LLC Welfare Plan for Retirees(d) X X X 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)These plans are collectively referred to as the legacy PHI plans.(e)Employees generally remain in their legacy benefit plans when transferring betwe

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, 2016

USD ($)

Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)

$ 1

Defined Benefit Plan, Future Amortization of Gain (Loss)

605

Benefits included in accumulated other comprehensive income

606

^[1]

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax

297

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

309

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)

(188)

Defined Benefit Plan, Future Amortization of Gain (Loss)

Benefits included in accumulated other comprehensive income

(133)

^[1]

Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax

(63)

$ (70)

[1]

___________________ (a)Of the $606 million related to pension benefits at December 31, 2016, $297 million and $309 million are expected to be amortized from AOCI and regulatory assets in 2017, respectively. Of the $(133) million related to other postretirement benefits at December 31, 2016, $(70) million and $(63) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2017, respectively.

Retirement Benefits - Assumptions Used in Calculations (Details)

3 Months Ended

12 Months Ended

Dec. 31, 2016

Jan. 01, 2016

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

4.04%

4.29%

3.94%

4.29%

^[1]

3.94%

^[2]

4.80%

^[3]

Pension Plan, Defined Benefit [Member] | Remeasurement [Member]

7.00%

^[4]

7.00%

^[4]

7.00%

^[4]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

6.59%

Pension Plan, Defined Benefit [Member] | First Five Years [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Pension Plan, Defined Benefit [Member] | Thereafter [Member]

3.25%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Other Postretirement Benefit Plan, Defined Benefit [Member]

3.75%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

4.04%

4.29%

3.92%

4.29%

^[1]

3.92%

^[2]

4.90%

^[3]

Health care cost trend rate

6.60%

6.71%

^[4]

6.50%

^[4]

6.59%

^[4]

5.50%

6.00%

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%

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%

3.99%

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%

4.06%

4.55%

CENG Legacy Benefit Plans [Member] | Minimum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

3.68%

3.29%

CENG Legacy Benefit Plans [Member] | Maximum [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Discount rate used for remeasurement due to design changes

4.14%

3.82%

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

3.60%

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

4.30%

Pepco Holdings LLC [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

Health care cost trend rate

5.40%

5.50%

DefinedBenefitPlanHealthCareCostTrendRateAssumedForNextFiscalYearAge

0.0633

0.0667

Ultimate health care cost trend rate

5.00%

Predecessor [Member] | Pepco Holdings LLC [Member] | Pension Plan, Defined Benefit [Member]

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

4.20%

^[1]

4.20%

5.05%

^[4]

6.50%

7.00%

5.00%

Predecessor [Member] | Pepco Holdings LLC [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

^[4]

5.00%

Defined Benefit Plan Assumptions Used In Calculations [Line Items]

4.55%

4.15%

^[1]

4.55%

4.15%

5.00%

^[4]

6.75%

7.25%

5.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[4]

5.00%

[1]	)The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2016. Certain benefit plans used individual rates ranging from 3.68%-4.14% and 4.32%-4.43% for pension and other postretirement plans, respectivel
[2]	The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended December 31, 2015. Certain benefit plans used individual rates ranging from 3.29%-3.82% and 3.99%-4.06% for pension and other postretirement plans, respectively.
[3]	The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 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 for 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]	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, 2016 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	$ 9
Effect of a one percentage point increase in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010	105
Effect of a one percentage point decrease in assumed healthcare cost trend on 2010 total service and interest cost components	(8)
Effect of a one percentage point decrease in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010	$ (95)

Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2016 USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	$ 23
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	23
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	1,360
2016	1,170
2017	1,191
2018	1,223
2019	1,275
2020 through 2024	6,791
Total estimated future benefit payments through 2026	13,010
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	1,360
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	244
2016	250
2017	256
2018	263
2019	272
2020 through 2024	1,456
Total estimated future benefit payments through 2026	2,741
Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months	$ 244

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Amount included in capital and operating & maintenance expense

$ 621

$ 637

$ 561

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

218

269

250

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

166

206

162

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 23

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 88

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

^[1]

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

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Amount included in capital and operating & maintenance expense

$ 9

$ 47

$ 37

$ 16

[1]	___(a)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, Pepco, DPL or ACE amounts

Retirement Benefits - Pension and Other Postretirement Benefit Plan Target Asset Allocations (Details)

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

100.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

100.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

43.00%

Equity Securities [Member] | Pension Plan, Defined Benefit [Member]

47.00%

43.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

33.00%

Fixed Income Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

33.00%

35.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

28.00%

Fixed Income Securities [Member] | Pension Plan, Defined Benefit [Member]

29.00%

27.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

39.00%

Alternative Investments [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

39.00%

34.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

29.00%

Alternative Investments [Member] | Pension Plan, Defined Benefit [Member]

^[1]

24.00%

30.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

28.00%

Predecessor [Member] | Pepco Holdings LLC [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

^[1]

28.00%

31.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

100.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Equity Securities [Member] | Pension Plan, Defined Benefit [Member]

63.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Fixed Income Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

28.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Fixed Income Securities [Member] | Pension Plan, Defined Benefit [Member]

34.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Alternative Investments [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]

66.00%

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Predecessor [Member] | Pepco Holdings LLC [Member] | Alternative Investments [Member] | Pension Plan, Defined Benefit [Member]

^[1]

3.00%

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]

6.00%

[1]	___(a)Alternative investments include private equity, hedge funds, real estate, and private

Retirement Benefits - Summary of Defined Contribution Savings Plan (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 164

$ 148

$ 103

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

^[1]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

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

^[2]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 1

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 2

CENG [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 10

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

$ 3

$ 14

$ 13

[1]	(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 amount
[2]	____(a)Includes $13 million, $9 million and $5 million related to CENG for the years ended December 31, 2016, December 31, 2015 and for the period from April 1, 2014 to December 31, 2014, respe

Severance - Narrative (Details)
$ in Millions

1 Months Ended

3 Months Ended

12 Months Ended

Aug. 31, 2015

Dec. 31, 2016

USD ($)

Dec. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

$ 19

$ 18

Exelon Generation Co L L C [Member] | Facility Closing [Member]

^[1]

$ 15

Cost Management Project [Member]

$ 44

Restructuring and Related Cost, Expected Number of Positions Eliminated

^[2]

500

Cost Management Project [Member] | Corporate, Non-Segment [Member]

Restructuring and Related Cost, Expected Number of Positions Eliminated

250

Cost Management Project [Member] | Exelon Generation Co L L C [Member]

Restructuring and Related Cost, Expected Number of Positions Eliminated

^[2]

250

Cost Management Project [Member] | Exelon Generation Co L L C [Member] | Corporate, Non-Segment [Member]

$ 7

[1]	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.
[2]	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2016.

Severance - Ongoing Severance Plans (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

$ 19

$ 18

^[1]

^[1]

^[1]

^[1]

$ 1

^[1]

$ 1

^[1]

$ 0

[1]	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.

Severance - Cost Management Program-Related Severance (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Cost Management Project [Member]

$ 19

$ 18

^[1]

Exelon Generation Co L L C [Member] | Cost Management Project [Member]

^[2]

Exelon Generation Co L L C [Member] | Cost Management Project [Member] | Corporate, Non-Segment [Member]

^[1]

Commonwealth Edison Co [Member] | Cost Management Project [Member]

^[2]

Commonwealth Edison Co [Member] | Cost Management Project [Member] | Corporate, Non-Segment [Member]

^[1]

PECO Energy Co [Member] | Cost Management Project [Member]

^[2]

PECO Energy Co [Member] | Cost Management Project [Member] | Corporate, Non-Segment [Member]

^[1]

Baltimore Gas and Electric Company [Member] | Cost Management Project [Member]

^[2]

$ 1

Baltimore Gas and Electric Company [Member] | Cost Management Project [Member] | Corporate, Non-Segment [Member]

^[1]

$ 1

[1]	The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2016.
[2]	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.

Severance - Severance Benefit Related to the PHI Merger (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

$ 19

$ 18

$ 11,388

11,388

6,824

PHI Merger [Member]

^[1]

Exelon Generation Co L L C [Member] | PHI Merger [Member]

^[2]

Exelon Generation Co L L C [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

^[1]

^[2]

Commonwealth Edison Co [Member] | PHI Merger [Member]

1,167

1,113

Commonwealth Edison Co [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

^[1]

^[2]

PECO Energy Co [Member] | PHI Merger [Member]

1,710

1,617

PECO Energy Co [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

^[1]

^[2]

Baltimore Gas and Electric Company [Member] | PHI Merger [Member]

712

781

Baltimore Gas and Electric Company [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

^[1]

Pepco Holdings LLC [Member] | PHI Merger [Member]

^[2]

Pepco Holdings LLC [Member] | Successor [Member] | PHI Merger [Member]

3,504

^[1]

Potomac Electric Power Company [Member] | PHI Merger [Member]

852

801

^[1],[3]

Potomac Electric Power Company [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

Delmarva Power and Light Company [Member] | PHI Merger [Member]

348

371

^[1],[4]

Delmarva Power and Light Company [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

Atlantic City Electric Company [Member] | PHI Merger [Member]

501

$ 512

^[1]

Atlantic City Electric Company [Member] | Corporate, Non-Segment [Member] | PHI Merger [Member]

Severance Costs [Member] | Potomac Electric Power Company [Member] | PHI Merger [Member]

Severance Costs [Member] | Delmarva Power and Light Company [Member] | PHI Merger [Member]

$ 4

[1]	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $8 million, $2 million, $1 million, $1 million, $20 million, $12 million and $10 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the year ended December 31, 2016.
[2]	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.
[3]	Pepco established a regulatory asset of $11 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.
[4]	DPL established a regulatory asset of $4 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.

Severance - Severance Liabilities Rollforward (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

$ 35

$ 50

(46)

(31)

$ 88

Severance [Member]

^[1]

^[2]

(9)

(21)

Exelon Generation Co L L C [Member] | Severance [Member]

^[1]

^[2]

(2)

(1)

Commonwealth Edison Co [Member] | Severance [Member]

^[1]

PECO Energy Co [Member] | Severance [Member]

^[2]

^[1]

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

^[2]

(1)

^[1]

^[3]

^[2]

^[3]

(27)

Pepco Holdings LLC [Member] | Successor [Member] | Severance [Member]

^[3]

^[1],[3]

^[3]

^[2]

^[3]

(3)

Pepco Holdings LLC [Member] | Predecessor [Member] | Severance [Member]

^[3]

^[1],[3]

(1)

Potomac Electric Power Company [Member] | Severance [Member]

^[1]

(1)

Delmarva Power and Light Company [Member] | Severance [Member]

^[1]

$ 0

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

$ 0

Common Stock Narrative Information [Line Items]

^[1]

$ 0

[1]	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.
[2]	The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.
[3]	For PHI, the successor period includes activity for the period from March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year ended December 31, 2015 and the period January 1, 2016 through March 23, 2016. There was no activity in the 2016 PHI predecessor period.

Mezzanine Equity Contingently Redeemable Noncontrolling Interest (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Noncontrolling Interest [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	18,000
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	$ 396		$ 1,548
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	0	$ 28
Temporary Equity, Other Changes		4	(528)
Payments to Acquire Businesses, Gross	6,934	40	386
Pepco Holdings LLC [Member]
Noncontrolling Interest [Line Items]
Derivative Asset, Not Subject to Master Netting Arrangement	18
Exelon Generation Co L L C [Member]
Noncontrolling Interest [Line Items]
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	396	1	5
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	0	28	0
Temporary Equity, Accretion to Redemption Value	129	32
Temporary Equity, Other Changes	(157)		(4)
Payments to Acquire Businesses, Gross	$ 293	$ 40	$ 386

Shareholder Equity Schedule of Common Stock Authorized and Outstanding (Details) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Class of Stock [Line Items]
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	924,035,059	919,924,742
Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 12.50
Common stock, shares authorized	250,000,000
Common Stock, Shares, Outstanding	127,017,157	127,016,973
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
Pepco Holdings LLC [Member] \| Predecessor [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Common stock, shares authorized	400,000,000	400,000,000.00
Common Stock, Shares, Outstanding		254,289,261.00
Potomac Electric Power Company [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 0.01
Common stock, shares authorized	200,000,000
Common Stock, Shares, Outstanding	100	100
Delmarva Power and Light Company [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 2.25
Common stock, shares authorized	1,000
Common Stock, Shares, Outstanding	1,000	1,000
Atlantic City Electric Company [Member]
Class of Stock [Line Items]
Common Stock, Par or Stated Value Per Share	$ 3.00
Common stock, shares authorized	25,000,000
Common Stock, Shares, Outstanding	8,546,017	8,546,017

Shareholder Equity Shareholder Narrative (Details) $ / shares in Units, $ in Millions			3 Months Ended	9 Months Ended
	Sep. 18, 2016 shares	Jul. 03, 2016 shares	Sep. 30, 2016 USD ($) shares	Sep. 30, 2016 USD ($) shares	Dec. 31, 2016 USD ($) warrant $ / shares shares	Dec. 31, 2015 USD ($) warrant shares	Jul. 30, 2015 USD ($) $ / shares shares	Jun. 30, 2014 USD ($) $ / shares shares
Schedule of Capitalization, Equity [Line Items]
Shares Issued, Price Per Share \| $ / shares								$ 35
Junior Subordinated Notes, Noncurrent \| $								$ 1,150
Treasury stock, at cost \| $					$ 2,327	$ 2,327
Treasury Stock, Number of Shares Held					35,000,000	35,000,000
Forward Contract Indexed to Issuer's Equity, Indexed Shares								23,000,000
Sale of Stock, Price Per Share \| $ / shares							$ 32.48
Temporary Equity, Share Subscriptions							57,500,000	57,500,000
Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized					100,000,000
Minimum [Member]
Schedule of Capitalization, Equity [Line Items]
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value \| $							$ 1,870
Commonwealth Edison Co [Member]
Schedule of Capitalization, Equity [Line Items]
Number Of Warrants Outstanding \| warrant					72,859	73,434
Common Stock Shares Reserved For Warrant Conversion					24,286	24,478
Commonwealth Edison Co [Member] \| Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized					850,000	6,810,451
Baltimore Gas and Electric Company [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Shares Authorized					6,500,000
Stock Redeemed or Called During Period, Shares	500,000	400,000	600,000	400,000
Stock Redeemed or Called During Period, Value \| $			$ 100	$ 90
Preferred Stock, Dividend Rate, Percentage	6.97%	7.125%	6.99%	6.70%
Baltimore Gas and Electric Company [Member] \| Preferred Stock [Member]
Schedule of Capitalization, Equity [Line Items]
Preferred Stock, Par or Stated Value Per Share \| $ / shares					$ 100

Shareholder Equity Preferred and Preference Securities (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 0	$ 190
Preferred Stock, Shares Outstanding	0.00	1,900,000.00
Pepco Holdings LLC [Member] \| Predecessor [Member]
Class of Stock [Line Items]
Preferred Stock, Shares Outstanding		18,000
Series 6.97% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 0	$ 50
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	0.00	500,000.00
Series 6.7% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 0	$ 40
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	0.00	400,000.00
Series 6.99% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 0	$ 60
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	0.00	600,000.00
Series 7.125% Preferred Stock [Member] \| Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Preferred Stock, Value, Outstanding	$ 0	$ 40
Preferred Stock, Redemption Price Per Share	$ 100.00
Preferred Stock, Shares Outstanding	0.00	400,000.00

Stock-Based Compensation Plans - Narrative (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Classification Of Obligations Related To Outstanding Performance Share Awards Not Yet Settled Deferred Credits And Other Liabilities

^[1]

$ 52

$ 32

^[2]

Expiration period

10 years

Obligations of outstanding restricted stock not settled

$ 101

Settlement of restricted stock

$ 43

Settlement of performance shares

Settlement of performance shares in cash

Unrecognized compensation costs of performance based shares

$ 51

Weighted-average period of recognition of unrecognized compensation costs of performance based shares

2 years

Common Stock Narrative Information [Line Items]

Obligations of outstanding restricted stock not settled

$ 1

Settlement of restricted stock

$ 6

Settlement of performance shares

$ 3

Performance Shares [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%

Weighted average grant date fair value (in usd per share)

$ 28.85

$ 35.88

$ 28.75

Performance Shares [Member] | Pepco Holdings LLC [Member]

Common Stock Narrative Information [Line Items]

Weighted average grant date fair value (in usd per share)

26.10

27.01

Employee Stock Option [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

4 years

Common Stock Narrative Information [Line Items]

Weighted-average period of recognition of unrecognized compensation costs

2 years

Restricted Stock [Member] | Pepco Holdings LLC [Member]

Common Stock Narrative Information [Line Items]

Weighted average grant date fair value (in usd per share)

26.80

Restricted Stock Units (RSUs) [Member]

Common Stock Narrative Information [Line Items]

Weighted average grant date fair value (in usd per share)

$ 28.14

36.55

28.71

Unrecognized compensation costs of performance based shares

$ 58

Restricted Stock Units (RSUs) [Member] | Pepco Holdings LLC [Member]

Common Stock Narrative Information [Line Items]

Weighted average grant date fair value (in usd per share)

27.40

19.77

Restricted Stock Units (RSUs) [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Common Stock Narrative Information [Line Items]

Weighted average grant date fair value (in usd per share)

$ 26.01

Performance based RSU [Member] | Pepco Holdings LLC [Member]

Common Stock Narrative Information [Line Items]

Weighted average grant date fair value (in usd per share)

$ 26.08

$ 18.53

Settlement of restricted stock

$ 15

$ 9

Minimum [Member] | Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

3 years

Maximum [Member] | Restricted Stock [Member]

Common Stock Narrative Information [Line Items]

Requisite service period

5 years

LTIP [Member]

Common Stock Narrative Information [Line Items]

Shares authorized

[1]	Represents the long-term liability related to performance share awards expected to be settled in cash.
[2]	Excludes $8 million of common stock for PHI at December 31, 2015

Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

$ 175

$ 119

$ 127

(68)

(46)

(47)

Allocated Share-based Compensation Expense, Net of Tax

107

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

(18)

(11)

Restricted Stock Units (RSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

(27)

(30)

(17)

Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Stock Compensation Plan [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 4

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

$ 3

(1)

(5)

(7)

Allocated Share-based Compensation Expense, Net of Tax

Predecessor [Member] | Pepco Holdings LLC [Member] | Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

(5)

(4)

Predecessor [Member] | Pepco Holdings LLC [Member] | Restricted Stock Units (RSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Employee Service Share-based Compensation, Tax Benefit from Compensation Expense

(2)

(3)

Predecessor [Member] | Pepco Holdings LLC [Member] | Employee Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

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

^[2]

^[1]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 3

$ 7

^[1],[2]

$ 13

^[2]

$ 18

^[2]

[1]	's stock-based compensation expense for the year ended December 31, 2016 and for the period January 1, 2016 through March 23, 2016 was not material. PHI's stock-based compensation expense for the year ended December 31, 2016 includes $3 million of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.
[2]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE or PHI amounts above.

Stock-Based Compensation Plans - Schedule of Pre-Tax Stock-based Compensation Expense (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 175

$ 119

$ 127

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]

$ 4

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

$ 3

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

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

^[2]

^[1]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]

$ 3

$ 7

^[1],[2]

$ 13

^[2]

$ 18

^[2]

[1]	's stock-based compensation expense for the year ended December 31, 2016 and for the period January 1, 2016 through March 23, 2016 was not material. PHI's stock-based compensation expense for the year ended December 31, 2016 includes $3 million of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.
[2]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE or PHI amounts above.

Stock-Based Compensation Plans - Components of Tax Benefits from Stock-based Compensation (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation		$ 68	$ 46	$ 47
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options		18	3	(8)
Restricted Stock Units (RSUs) [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation		27	30	17
Performance Shares [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation		$ 18	18	11
Pepco Holdings LLC [Member] \| Predecessor [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation	$ 1		5	7
Pepco Holdings LLC [Member] \| Predecessor [Member] \| Restricted Stock Units (RSUs) [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation	0		2	3
Pepco Holdings LLC [Member] \| Predecessor [Member] \| Performance Shares [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Tax benefit on stock compensation	0		5	4
Pepco Holdings LLC [Member] \| Predecessor [Member] \| Employee Stock Option [Member]
Deferred Compensation Arrangement with Individual, Share-based Payments [Line Items]
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options	$ 0		$ 0	$ 1

Stock-Based Compensation Plans - Summary of Stock Option Activity (Details) - Employee Stock Option [Member] - USD ($)
$ / shares in Units, $ in Millions

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

15,572,757

(840,672)

(2,200,494)

12,531,591

Weighted Average Exercise Price (in usd per share)

$ 46.23

$ 46.68

Options Reinstated, Weighted Average Exercise Price (in usd per share)

22.12

Options Forfeited, Weighted Average Exercise Price (in usd per share)

0.00

Options Expired, Weighted Average Exercise Price (in usd per share)

$ 58.60

Shares Outstanding, Weighted Average Remaining Contractual Life

3 years 6 months

Exercisable at December 31, 2014

^[1]

12,531,591

Shares Exercisable, Weighted Average Exercise Price (in usd per share)

^[1]

$ 46.23

Shares Exercisable, Weighted Average Remaining Contractual Life

^[1]

3 years 6 months

Shares Exercisable, Aggregate Intrinsic Value

^[1]

$ 13

[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, 2016

Dec. 31, 2015

Dec. 31, 2014

Common Stock [Abstract]

Aggregate value

^[1]

$ 11

$ 0

$ 3

Cash received for exercise price

$ 19

$ 0

$ 7

[1]	Includes stock options issued to retirement eligible employees.

Stock-Based Compensation Plans - Summary of Nonvested Stock Option Activity (Details) - $ / shares

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

1,319,372

975,116

Nonvested Stock Option [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]

^[1]

82,250

(82,250)

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

^[1]

$ 0.00

$ 39.81

Vested, Weighted Average Exercise Price (in usd per share)

$ 39.81

Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Number

279,000

[1]	Excludes 279,000 of stock options issued to retirement-eligible employees as of December 31, 2015 as they are fully vested.

Stock-Based Compensation Plans - Summary of Nonvested Restrict Stock Unit Activity (Details) - $ / shares

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Restricted Stock Units (RSUs) [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[1]

3,563,254

Granted

3,042,184

Undistributed vested awards

(1,797,536)

Forfeited

(85,940)

(897,546)

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

3,824,416

3,563,254

^[1]

$ 32.92

Granted, Weighted Average Grant Date Fair Value (in usd per share)

28.14

$ 36.55

$ 28.71

Vested, Weighted Average Exercise Price (in usd per share)

32.44

Forfeited, Weighted Average Exercise Price (in usd per share)

30.08

Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)

28.35

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

$ 30.49

$ 32.92

Restricted Stock Units (RSUs) [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

628,514

Nonvested, Weighted Average Exercise Price (in usd per share)

628,514

$ 24.71

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 27.40

19.77

Nonvested, Weighted Average Exercise Price (in usd per share)

$ 24.96

$ 24.71

Restricted Stock Units (RSUs) [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

152,928

781,442

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 26.01

Vested, Weighted Average Exercise Price (in usd per share)

0.00

Forfeited, Weighted Average Exercise Price (in usd per share)

$ 0.00

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

1,319,372

975,116

Restricted Stock [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 26.80

Restricted Stock [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[2]

54,165

Nonvested, Weighted Average Exercise Price (in usd per share)

^[2]

54,165

^[2]

$ 26.80

Vested, Weighted Average Exercise Price (in usd per share)

0.00

Nonvested, Weighted Average Exercise Price (in usd per share)

^[2]

$ 26.80

PerformancebasedRSU1 [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

408,638

Nonvested, Weighted Average Exercise Price (in usd per share)

408,638

$ 18.56

Nonvested, Weighted Average Exercise Price (in usd per share)

$ 21.45

$ 18.56

PerformancebasedRSU1 [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

305,856

4,950

1,238

708,306

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 25.41

Vested, Weighted Average Exercise Price (in usd per share)

26.08

Forfeited, Weighted Average Exercise Price (in usd per share)

$ 26.08

[1]	Excludes 1,319,372 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.
[2]	Excludes 2,443,409 and 1,817,883 of performance share awards issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.

Stock-Based Compensation Plans - Summary of Nonvested Performance Share Awards Activity (Details) - $ / shares

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Performance Shares [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[1]

2,557,159

Granted

2,319,407

Undistributed vested awards

(949,315)

Forfeited

(70,876)

^[2]

(1,367,417)

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

3,116,261

2,557,159

^[1]

$ 30.77

$ 31.88

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 28.85

$ 35.88

$ 28.75

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Period Increase (Decrease)

627,303

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Change in Performance, Weighted Average Grant Date Fair Value

$ 30.04

Vested, Weighted Average Exercise Price (in usd per share)

31.31

Forfeited, Weighted Average Exercise Price (in usd per share)

30.90

Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)

^[2]

$ 28.33

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

2,443,409

1,817,883

Performance Shares [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 26.10

27.01

Performance Shares [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[1]

24,717

(24,717)

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

24,717

^[1]

$ 0.00

$ 26.10

Vested, Weighted Average Exercise Price (in usd per share)

$ 26.10

PerformancebasedRSU1 [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

408,638

Nonvested, Weighted Average Exercise Price (in usd per share)

408,638

$ 21.45

$ 18.56

PerformancebasedRSU1 [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

305,856

4,950

1,238

708,306

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 25.41

Vested, Weighted Average Exercise Price (in usd per share)

26.08

Forfeited, Weighted Average Exercise Price (in usd per share)

$ 26.08

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees

1,319,372

975,116

Restricted Stock [Member] | Pepco Holdings LLC [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

Granted, Weighted Average Grant Date Fair Value (in usd per share)

$ 26.80

Restricted Stock [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]

^[1]

54,165

Nonvested, Weighted Average Exercise Price (in usd per share)

^[1]

54,165

^[1]

$ 26.80

Vested, Weighted Average Exercise Price (in usd per share)

$ 0.00

[1]	Excludes 2,443,409 and 1,817,883 of performance share awards issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully vested.
[2]	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2016.

Stock-Based Compensation Plans - Balance Sheet Classification of Obligations related to Outstanding Performance Share Awards Not Yet Settled (Details) - USD ($)
$ in Millions

Dec. 31, 2016

Dec. 31, 2015

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Current liabilities

^[1]

$ 49

$ 28

^[2]

Deferred credits and other liabilities

^[3]

^[2]

^[2]

$ 141

^[2]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

$ 8

[1]	Represents the current liability related to performance share awards expected to be settled in cash.
[2]	Excludes $8 million of common stock for PHI at December 31, 2015
[3]	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, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 204	$ 490	$ 267	$ 173	$ 309	$ 629	$ 638	$ 693	$ 1,134	$ 2,269	$ 1,623
Weighted average common shares outstanding—basic	925	925	924	923	921	913	863	862	924	890	860
Assumed exercise and/or distributions of stock-based awards									3	3	4
Weighted average common shares outstanding—diluted	928	927	926	925	924	915	866	867	927	893	864

Earnings Per Share and Equity - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
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)	12,000,000	16,000,000	17,000,000
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

3 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ 27,612

$ 27,294

$ 24,133

$ 22,940

186

136

^[1]

^[2]

150

196

^[1],[3]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(36)

^[1]

(644)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(17)

(19)

^[1]

(28)

^[1]

^[1]

^[1],[3]

Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

^[1]

(1)

Accumulated Defined Benefit Plans Adjustment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(2,610)

(2,565)

^[1]

(2,640)

182

100

^[1]

137

175

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

Accumulated Translation Adjustment [Member]

(45)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(30)

(40)

^[1]

(19)

(5)

Accumulated Equity Investment [Member]

(21)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(7)

(3)

^[1]

^[1]

AOCI Including Portion Attributable to Noncontrolling Interest [Member]

(4)

(3)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(2,660)

(2,624)

(2,684)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[2]

^[1],[3]

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(27)

^[1]

(250)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(19)

(21)

^[1]

(18)

^[1]

^[1]

^[1],[3]

Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

(3)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

^[1]

(1)

Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(30)

(40)

^[1]

(19)

(5)

^[1]

Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]

(21)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(7)

(3)

^[1]

^[1]

Exelon Generation Co L L C [Member] | AOCI Including Portion Attributable to Noncontrolling Interest [Member]

(4)

(3)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(54)

(63)

(36)

PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

^[1]

PECO Energy Co [Member] | AOCI Including Portion Attributable to Noncontrolling Interest [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ 1

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1],[3]

(5)

^[2]

$ 1

^[1],[3]

Predecessor [Member] | Pepco Holdings LLC [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[1]

(12)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(8)

^[1]

(9)

^[1]

^[1]

Predecessor [Member] | Pepco Holdings LLC [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

(27)

(28)

^[1]

(37)

^[1]

^[1]

(5)

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

Predecessor [Member] | Pepco Holdings LLC [Member] | AOCI Including Portion Attributable to Noncontrolling Interest [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

$ (35)

$ (36)

$ (46)

[1]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[2]	Amounts in parenthesis represent a decrease in net income.
[3]	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

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

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

$ 7,875

$ 9,002

$ 6,910

$ 7,573

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 31,360

$ 29,447

$ 27,429

(1,123)

(1,079)

(610)

413

(46)

455

1,989

3,330

2,486

(761)

(1,073)

(666)

Net Income (Loss) Available to Common Stockholders, Basic

1,204

2,250

1,820

204

490

267

173

309

629

638

693

1,134

2,269

1,623

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(150)

(196)

^[2],[3]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(8)

(21)

^[2],[3]

Accumulated Defined Benefit Plans Adjustment [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(137)

(175)

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

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

^[1]

(224)

(287)

Reclassification from AOCI, Current Period, Tax

^[1]

(87)

(112)

Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent [Member]

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

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

^[1],[4]

Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member]

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

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

^[1]

(302)

^[4]

(361)

^[5]

Accumulated Translation Adjustment [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(5)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]

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

^[1]

(13)

(35)

^[1]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member] | Energy Related Derivative [Member]

^[1]

(8)

(21)

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

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

^[1]

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

^[1]

(13)

(11)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Translation Adjustment [Member]

^[1]

(26)

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

^[1]

(5)

^[1]

$ 0

^[1]

^[1]

(5)

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

$ 4,388

$ 5,035

$ 3,589

$ 4,739

4,294

4,768

4,232

5,840

17,751

19,135

17,393

(425)

401

(60)

406

(290)

(502)

(207)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

558

1,340

1,019

^[1]

(13)

(5)

^[2],[3]

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(8)

(5)

^[2],[3]

Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(5)

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]

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

^[1]

(13)

(9)

^[1]

(4)

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

^[1]

(8)

(5)

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

^[1]

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Translation Adjustment [Member]

(13)

^[1]

(11)

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

^[1]

(5)

^[1]

(5)

^[1]

Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

(5)

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

^[1]

$ (137)

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

1,153

$ 1,126

$ 1,336

$ 1,119

$ 1,354

4,935

4,808

(69)

(192)

(225)

(4)

(17)

(163)

(138)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

327

$ 242

^[1]

(1)

(5)

^[2],[3]

Predecessor [Member] | Pepco Holdings LLC [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[2]

(1)

Predecessor [Member] | Pepco Holdings LLC [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

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

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(1)

(4)

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

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

^[1]

(1)

(6)

Reclassification from AOCI, Current Period, Tax

^[1]

(2)

Predecessor [Member] | Pepco Holdings LLC [Member] | Accumulated Defined Benefit Plans Adjustment, Net Prior Service Attributable to Parent [Member]

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

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

^[1],[4]

Predecessor [Member] | Pepco Holdings LLC [Member] | Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Attributable to Parent [Member]

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

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

^[1],[4]

(1)

(6)

Predecessor [Member] | Pepco Holdings LLC [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Cash Flow Hedges Including Portion Attributable to Noncontrolling Interest [Member]

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

^[1]

(1)

^[1]

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

^[1]

(1)

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

^[1]

Predecessor [Member] | Pepco Holdings LLC [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Translation Adjustment [Member]

^[1]

$ (1)

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

^[1]

^[1]

^[1]

^[1]

Predecessor [Member] | Pension Plan, Defined Benefit [Member] | Pepco Holdings LLC [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

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

Operating Leases Future Minimum Payments Due [Line Items]

^[1]

$ (1)

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[3]	See next tables for details about these reclassifications.
[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	3 Months Ended	12 Months Ended
	Mar. 23, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gain (loss) on cash flow hedges, taxes		$ 0	$ (6)	$ 96
Change in unrealized gain (loss) on equity investments taxes		3	1	73
Other comprehensive income, income taxes		30	(53)	412
Accumulated Defined Benefit Plans Adjustment, Net Prior Service Including Portion Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income, income taxes		30	30	19
Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income, income taxes		118	140	93
Accumulated Defined Benefit Plans Adjustment Including Portion Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income, income taxes		115	62	317
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)	2	84
Change in unrealized gain (loss) on equity investments taxes		3	1	73
Other comprehensive income, income taxes		$ 1	3	157
Predecessor [Member] \| Pepco Holdings LLC [Member] \| Accumulated Defined Benefit Plans Adjustment, Net Gain (Loss) Including Portion Attributable to Noncontrolling Interest [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other comprehensive income, income taxes	$ 0		$ 6	$ 5

Commitments and Contingencies - Narrative (Details)	3 Months Ended			12 Months Ended
Commitments and Contingencies - Narrative (Details)	Dec. 31, 2016 USD ($) a MGPSite Open_claim MW	Sep. 30, 2016 USD ($)	Sep. 30, 2015 gal	Dec. 31, 2016 USD ($) a MGPSite Open_claim Customer MW	Dec. 31, 2015 USD ($)	Dec. 31, 1999 Principle_responsible_party	Dec. 31, 2014 USD ($)	May 30, 2012 USD ($)
Commitments and Contingencies [Line Items]
Power Volume \| MW				220
Loss Contingency Accrual, Payments	$ 44,000,000
Litigation Settlement, Amount				$ (28,000,000)
Nuclear insurance liability limit per incident					$ 21,000,000
BusinessAcquisitionResidualcommitment \| MW	55
Loss Contingency, Loss in Period	$ 50,000,000
Guarantee obligations maximum exposure	50,000,000			50,000,000
Asbestos liability reserve	83,000,000			83,000,000	95,000,000
Probable contingency (liability)	$ 22,000,000			$ 22,000,000
Open asbestos liability claims \| Open_claim	230			230
Asbestos liability reserve related to anticipated claims	$ 61,000,000			$ 61,000,000
Rossville ash site [Member]
Commitments and Contingencies [Line Items]
Area of property \| a	32			32
Exelon Generation Co L L C [Member]
Commitments and Contingencies [Line Items]
Loss Contingency Accrual	$ 0			$ 0
Loss Contingency, Damages Sought, Value				14,000,000
Nuclear financial protection pool value	450,000,000			450,000,000
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses	13,000,000,000.0			13,000,000,000.0
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident	2,700,000,000			2,700,000,000
Total retrospective premium obligation under insurance from a nuclear industry mutual insurance company	353,000,000			353,000,000
Mutual Replacement Power Cost Insurance Maximum Retrospective Premium Obligation	3,200,000,000			3,200,000,000
Cost of spent nuclear fuel disposal per kWh of net nuclear generation	0.001			0.001
Net nuclear fuel disposal fees					49,000,000
Department of Energy SNF one-time fee applicable to nuclear generation	277,000,000			277,000,000
DOE SNF one-time fee with interest	1,024,000,000			$ 1,024,000,000
13-week Treasury Rate used to calculate DOE SNF one-time fee				0.355%
Environmental loss contingencies					$ 90,000,000
Total cost of remediation to be shared by PRPs				$ 90,000,000
Estimate of possible loss	$ 4,000,000			$ 4,000,000
Open asbestos liability claims \| Open_claim	300			300
Costs Incurred, Development Costs				$ 454,000,000
Exelon Generation Co L L C [Member] \| Minimum [Member]
Commitments and Contingencies [Line Items]
Total cost of remediation to be shared by PRPs	$ 225
Business Acquisition, Development Of New Generation Cost	450,000,000			$ 450,000,000
Business Acquisition, Expected New Generation Mwh \| MW				285
Exelon Generation Co L L C [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Total cost of remediation to be shared by PRPs	650
Business Acquisition, Development Of New Generation Cost	500,000,000			$ 500,000,000
Business Acquisition, Expected New Generation Mwh \| MW				300
Exelon Generation Co L L C [Member] \| Equity Method Investments [Member]
Commitments and Contingencies [Line Items]
Purchase obligations, due within two years	5,000,000			$ 5,000,000
Unrecorded Unconditional Purchase Obligation	39,000,000			39,000,000
Unrecorded unconditional purchase obligation, due in next 12 months	34,000,000			34,000,000
Other unrecorded amounts	20,000,000			20,000,000
Exelon Generation Co L L C [Member] \| Nuclear Insurance Premiums [Member]
Commitments and Contingencies [Line Items]
Nuclear insurance liability limit per incident	13,400,000,000.0			13,400,000,000.0
Exelon Generation Co L L C [Member] \| Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Commitments and Contingencies [Line Items]
Mutual Property Insurance Distribution To Members	$ 21,000,000			$ 21,000,000			$ 18,000,000
Commonwealth Edison Co [Member]
Commitments and Contingencies [Line Items]
Total number of MGP sites \| MGPSite	42			42
Sites approved for clean-up \| MGPSite	18			18
Sites under study/remediation \| MGPSite	24			24
Increase (decrease) in accrual for environmental loss contingencies		$ 7,000,000
Minimum number of customers ComEd can be held liable to for power interruption \| Customer				30,000
PECO Energy Co [Member]
Commitments and Contingencies [Line Items]
Total number of MGP sites \| MGPSite	26			26
Sites approved for clean-up \| MGPSite	17			17
Sites under study/remediation \| MGPSite	9			9
Increase (decrease) in accrual for environmental loss contingencies		0
Baltimore Gas and Electric Company [Member]
Commitments and Contingencies [Line Items]
Litigation Settlement, Amount				$ (28,000,000)
Total number of MGP sites \| MGPSite	13			13
Sites under study/remediation \| MGPSite	2			2
Number of parties jointly and severally liable In environmental protection agency action \| Principle_responsible_party						19
Baltimore Gas and Electric Company [Member] \| Deferrable Interest Subordinated Debentures [Member]
Commitments and Contingencies [Line Items]
Interest rate on long-term debt	6.20%			6.20%
Baltimore Gas and Electric Company [Member] \| Minimum [Member]
Commitments and Contingencies [Line Items]
Estimate of possible loss	$ 50,000,000			$ 50,000,000
Baltimore Gas and Electric Company [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Estimate of possible loss	64,000,000			64,000,000				$ 1,700,000
Calpine Corporation [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Estimate of possible loss	$ 10,000,000			10,000,000
Pepco Holdings LLC [Member]
Commitments and Contingencies [Line Items]
Litigation Settlement, Amount				$ 1,600,000
Number of Real Estate Properties \| MGPSite	9			9
Pepco Holdings LLC [Member] \| Minimum [Member]
Commitments and Contingencies [Line Items]
Estimate of possible loss	$ 7,000,000			$ 7,000,000
Pepco Holdings LLC [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Estimate of possible loss	$ 18,000,000			18,000,000
Potomac Electric Power Company [Member]
Commitments and Contingencies [Line Items]
Guarantee obligations maximum exposure		14,000,000
QuantityOfMineralOilSPill \| gal			6,100
Quantity of Mineral Oil Spill Recovered			80.00%
Potomac Electric Power Company [Member] \| Minimum [Member]
Commitments and Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost				3,000,000
Potomac Electric Power Company [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost				$ 6,000,000
Delmarva Power and Light Company [Member]
Commitments and Contingencies [Line Items]
Total number of MGP sites \| MGPSite	2			2
Guarantee obligations maximum exposure		17,000,000
Atlantic City Electric Company [Member]
Commitments and Contingencies [Line Items]
Guarantee obligations maximum exposure		$ 13,000,000
Merger Commitment [Member]
Commitments and Contingencies [Line Items]
Investments	$ 0			$ 0
Merger Commitment [Member] \| Minimum [Member]
Commitments and Contingencies [Line Items]
Investments	0			0
Merger Commitment [Member] \| Maximum [Member]
Commitments and Contingencies [Line Items]
Investments	$ 0			$ 0

Commitments and Contingencies - Schedule of Government Agreement Settlements (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Schedule of Government Agreements [Line Items]
Nontrade Receivables, Current		$ 109	$ 76
Nontrade Receivables, Noncurrent		15	14
Accounts Payable, Other, Current		(13)	$ (5)
Exelon Generation Co L L C [Member]
Schedule of Government Agreements [Line Items]
Spent Nuclear Fuel Storage Reimbursement		1,038
Spent Nuclear Fuel Storage Reimbursement Net Co Owners		$ 887
Department of Energy [Member] \| Exelon Generation Co L L C [Member]
Schedule of Government Agreements [Line Items]
Spent Nuclear Fuel Storage Reimbursement	$ 53
Spent Nuclear Fuel Storage Reimbursement Net Co Owners	$ 49

Commitments and Contingencies - Schedule of Energy Supply Procurement, Curtailment Services, REC and AEC Purchase Commitments (Details)	12 Months Ended
	Dec. 31, 2016
Commonwealth Edison Co [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Term of contract	20 years

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) - Equity Method Investments [Member] - Exelon Generation Co L L C [Member] $ in Millions	Dec. 31, 2016 USD ($)
Guarantor Obligations [Line Items]
2016	$ 34
2017	5
Total	$ 39

Commitments and Contingencies - Schedule of Minimum Future Operating Lease Payments (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Nov. 30, 2016

$ 777

$ 922

$ 865

2015

$ 183

183

179

123

140

133

968

1,726

Operating Leases Future Minimum Payments Due [Line Items]

^[1]

667

851

806

644

914

Operating Leases Future Minimum Payments Due [Line Items]

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

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

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

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases, Future Minimum Payments, Due Thereafter

$ 21

$ 14

Remaining years

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

199

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

211

418

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

$ 0

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

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

110

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

$ 13

$ 12

Operating Leases Future Minimum Payments Due [Line Items]

$ 54

[1]

Commitments and Contingencies - Schedule of Future Rental Expense under Operating Leases (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 777

$ 922

$ 865

Operating Leases Future Minimum Payments Due [Line Items]

Long Term Contract For Purchase Of Electric Power Capacity

^[1]

667

851

806

$ 604

604

798

755

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

Operating Leases Future Minimum Payments Due [Line Items]

$ 0

$ 49

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]

$ 13

$ 12

[1]

Commitments and Contingencies - Schedule of Environmental Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 429	$ 369
Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	325	301
Exelon Generation Co L L C [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	72	63
Exelon Generation Co L L C [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	0	0
Commonwealth Edison Co [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	292	266
Commonwealth Edison Co [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	291	264
PECO Energy Co [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	33	37
PECO Energy Co [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	31	35
Baltimore Gas and Electric Company [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	2	3
Baltimore Gas and Electric Company [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	2	2
Pepco Holdings LLC [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	30	33
Pepco Holdings LLC [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	1	1
Potomac Electric Power Company [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	27	24
Potomac Electric Power Company [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	0	0
Delmarva Power and Light Company [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	2	3
Delmarva Power and Light Company [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	1	1
Atlantic City Electric Company [Member] \| Total Accrual For Environmental Loss Contingencies [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	1	1
Atlantic City Electric Company [Member] \| Accrual For MGP Investigation And Remediation [Member]
Loss Contingencies [Line Items]
Accrual for Environmental Loss Contingencies	$ 0	$ 0

Supplemental Financial Information - Summary of Taxes other than Income (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

^[1]

$ 753

$ 474

$ 456

483

407

396

226

201

200

114

118

102

1,576

1,200

1,154

Supplemental Financial Information Tables [Line Items]

^[1]

122

105

246

250

240

117

118

506

489

465

Supplemental Financial Information Tables [Line Items]

^[1]

242

236

238

(4)

293

296

293

Supplemental Financial Information Tables [Line Items]

^[1]

136

133

128

164

160

159

Supplemental Financial Information Tables [Line Items]

^[1]

123

119

114

229

224

221

Supplemental Financial Information Tables [Line Items]

^[1]

$ 253

$ 354

Supplemental Financial Information Tables [Line Items]

^[1]

$ 78

326

324

$ 105

455

437

Supplemental Financial Information Tables [Line Items]

^[1]

312

308

307

377

376

369

Supplemental Financial Information Tables [Line Items]

^[1]

Supplemental Financial Information Tables [Line Items]

^[1]

(1)

Supplemental Financial Information Tables [Line Items]

$ 7

$ 4

[1]

Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Jun. 30, 2016

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

$ 237

$ 232

$ 216

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

126

156

159

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

216

(282)

180

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

194

(197)

134

Regulatory offset to decommissioning trust fund-related activities

(1)

^[2]

(372)

(358)

400

(63)

360

Interest income related to uncertain income tax positions

Income Tax Examination, Penalties and Interest Expense

(106)

(3)

^[3]

(26)

(22)

(48)

437

Reclassification out of Accumulated Other Comprehensive Income [Member]

413

(46)

455

Supplemental Financial Information Tables [Line Items]

Gain (Loss) on Sale of Derivatives

Supplemental Financial Information Tables [Line Items]

Supplemental Financial Information Tables [Line Items]

$ 4,200

Predecessor [Member]

$ 0

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

237

232

216

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

126

156

159

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

216

(282)

180

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

194

(197)

134

Regulatory offset to decommissioning trust fund-related activities

(1)

^[2]

(372)

(358)

400

(63)

360

Interest income related to uncertain income tax positions

(59)

437

(5)

(1)

(9)

Exelon Generation Co L L C [Member] | Senior Notes [Member]

401

(60)

406

Supplemental Financial Information Tables [Line Items]

$ 750

750

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Interest income related to uncertain income tax positions

Income Tax Examination, Penalties and Interest Expense

(86)

(65)

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

(1)

(2)

(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

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

^[4]

Interest income related to uncertain income tax positions

(1)

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

Interest income related to uncertain income tax positions

(1)

(1)

$ 44

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

^[2]

Interest income related to uncertain income tax positions

(11)

$ (4)

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

^[2]

Interest income related to uncertain income tax positions

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

^[2]

Interest income related to uncertain income tax positions

Supplemental Financial Information Tables [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Regulatory offset to decommissioning trust fund-related activities

^[2]

^[2]

^[4]

Interest income related to uncertain income tax positions

Supplemental Financial Information Tables [Line Items]

$ 9

$ 3

[1]	Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning trust funds.
[2]	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
[3]	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 AOCI to Other, net in Exelon's Consolidated Statements of Operations and Comprehensive Income.
[4]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246MkMyOTM5MEM5NEQyN0U2MTAwODM5RjkyNUQyNTcxNzkM}

Supplemental Financial Information - Summary of Depreciation, Amortization, Accretion and Depletion (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 3,477

$ 2,227

$ 2,080

407

170

191

179

^[1]

1,159

1,116

1,073

^[2]

446

398

345

5,576

3,987

3,868

Supplemental Financial Information Tables [Line Items]

1,835

1,007

922

179

^[1]

1,159

1,116

1,073

^[2]

446

397

345

3,519

2,589

2,519

Supplemental Financial Information Tables [Line Items]

708

635

588

^[1]

^[2]

775

707

687

Supplemental Financial Information Tables [Line Items]

244

240

227

^[1]

^[2]

270

260

236

Supplemental Financial Information Tables [Line Items]

299

289

288

124

^[1]

^[2]

423

366

371

Supplemental Financial Information Tables [Line Items]

$ 325

190

^[1]

^[2]

515

Supplemental Financial Information Tables [Line Items]

$ 94

^[1]

^[2]

152

624

526

Supplemental Financial Information Tables [Line Items]

175

164

155

120

^[1]

^[2]

Potomac Electric Power Company [Member] | Predecessor [Member]

295

256

212

Supplemental Financial Information Tables [Line Items]

392

363

232

163

^[1]

^[2]

Supplemental Financial Information Tables [Line Items]

110

103

^[1]

^[2]

157

148

122

Supplemental Financial Information Tables [Line Items]

^[1]

^[2]

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

165

175

155

Supplemental Financial Information Tables [Line Items]

^[1]

Unamortized Energy Contracts [Member]

^[2]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]

^[3]

135

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Commonwealth Edison Co [Member]

^[3]

135

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]

Unamortized Energy Contracts [Member] | Pepco Holdings LLC [Member] | Successor [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Potomac Electric Power Company [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Potomac Electric Power Company [Member] | Predecessor [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Delmarva Power and Light Company [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Atlantic City Electric Company [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Unamortized Energy Contracts [Member] | Atlantic City Electric Company [Member] | Predecessor [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member]

^[3]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Exelon Generation Co L L C [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Commonwealth Edison Co [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | PECO Energy Co [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Baltimore Gas and Electric Company [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ 0

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Potomac Electric Power Company [Member]

$ 0

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Potomac Electric Power Company [Member] | Predecessor [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Delmarva Power and Light Company [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Atlantic City Electric Company [Member]

Supplemental Financial Information Tables [Line Items]

Other Intangible Assets [Member] | Atlantic City Electric Company [Member] | Predecessor [Member]

$ 0

Supplemental Financial Information Tables [Line Items]

Supplemental Cash Flow Information [Line Items]

$ 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 ($)

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Mar. 31, 2015

Dec. 31, 2016

Sep. 30, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Mar. 24, 2016

$ 1,340,000,000

$ 930,000,000

$ 940,000,000

Pension and non-pension postretirement benefit costs

(441,000,000)

342,000,000

314,000,000

619,000,000

637,000,000

560,000,000

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

24,000,000

7,000,000

20,000,000

22,000,000

155,000,000

120,000,000

156,000,000

12,000,000

10,000,000

5,000,000

111,000,000

97,000,000

91,000,000

(384,000,000)

(82,000,000)

(132,000,000)

Amortization of regulatory asset related to debt costs

(11,000,000)

21,000,000

122,000,000

9,000,000

7,000,000

11,000,000

76,000,000

73,000,000

65,000,000

(11,000,000)

(17,000,000)

(23,000,000)

558,000,000

44,000,000

99,000,000

2,000,000

35,000,000

144,000,000

53,000,000

8,000,000

58,000,000

53,000,000

Litigation Settlement, Amount

37,000,000

23,000,000

29,000,000

(28,000,000)

Proceeds from Collection of Other Receivables

(13,000,000)

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

35,000,000

11,000,000

(2,000,000)

1,333,000,000

1,109,000,000

1,054,000,000

Other Noncash Expense

77,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 191,000,000

191,000,000

885,000,000

72,000,000

(128,000,000)

(96,000,000)

(220,000,000)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

6,934,000,000

40,000,000

386,000,000

(54,000,000)

Consolidated VIE dividend to noncontrolling

4,000,000

Fair value of net assets recorded upon CENG consolidation

3,400,000,000

(131,000,000)

Non Cash Licensing Agreement

95,000,000

Antelope Valle [Member]

Supplemental Cash Flow Information [Line Items]

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(170,000,000)

Capital Project [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

(95,000,000)

Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

70,000,000

(57,000,000)

Supplemental Cash Flow Information [Line Items]

339,000,000

348,000,000

322,000,000

Pension and non-pension postretirement benefit costs

435,000,000

476,000,000

227,000,000

218,000,000

269,000,000

249,000,000

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

$ (19,000,000)

20,000,000

25,000,000

8,000,000

(20,000,000)

19,000,000

22,000,000

14,000,000

6,000,000

9,000,000

5,000,000

(384,000,000)

(82,000,000)

(132,000,000)

Amortization of regulatory asset related to debt costs

(11,000,000)

21,000,000

122,000,000

(11,000,000)

(17,000,000)

(23,000,000)

53,000,000

44,000,000

22,000,000

$ 285,000,000

1,300,000,000

17,000,000

15,000,000

12,000,000

36,000,000

23,000,000

29,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

25,000,000

6,000,000

15,000,000

268,000,000

346,000,000

Other Noncash Expense

77,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

191,000,000

885,000,000

72,000,000

(50,000,000)

(82,000,000)

(61,000,000)

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

293,000,000

40,000,000

386,000,000

(54,000,000)

Consolidated VIE dividend to noncontrolling

645,000,000

Fair value of net assets recorded upon CENG consolidation

3,400,000,000

Exelon Generation Co L L C [Member] | Capital Project [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

(95,000,000)

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

(57,000,000)

Supplemental Cash Flow Information [Line Items]

298,000,000

308,000,000

292,000,000

Pension and non-pension postretirement benefit costs

(444,000,000)

(265,000,000)

(6,000,000)

166,000,000

206,000,000

162,000,000

41,000,000

53,000,000

26,000,000

4,000,000

1,000,000

Amortization of regulatory asset related to debt costs

4,000,000

5,000,000

8,000,000

4,000,000

8,000,000

144,000,000

53,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(12,000,000)

3,000,000

2,000,000

215,000,000

416,000,000

255,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(91,000,000)

(34,000,000)

(78,000,000)

Fair value of net assets recorded upon CENG consolidation

Commonwealth Edison Co [Member] | Capital Project [Member]

5,000,000

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Commonwealth Edison Co [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

158,000,000

7,000,000

Supplemental Cash Flow Information [Line Items]

104,000,000

94,000,000

Pension and non-pension postretirement benefit costs

64,000,000

85,000,000

33,000,000

39,000,000

36,000,000

30,000,000

52,000,000

Amortization of regulatory asset related to debt costs

1,000,000

2,000,000

3,000,000

3,000,000

2,000,000

1,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(3,000,000)

(1,000,000)

65,000,000

70,000,000

92,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(11,000,000)

(13,000,000)

Fair value of net assets recorded upon CENG consolidation

PECO Energy Co [Member] | Capital Project [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

PECO Energy Co [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Supplemental Cash Flow Information [Line Items]

92,000,000

120,000,000

111,000,000

Pension and non-pension postretirement benefit costs

31,000,000

73,000,000

(21,000,000)

67,000,000

65,000,000

64,000,000

1,000,000

15,000,000

64,000,000

Amortization of regulatory asset related to debt costs

81,000,000

73,000,000

65,000,000

1,000,000

2,000,000

Litigation Settlement, Amount

(28,000,000)

Proceeds from Collection of Other Receivables

(13,000,000)

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(21,000,000)

(18,000,000)

(15,000,000)

88,000,000

137,000,000

180,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(86,000,000)

(9,000,000)

(25,000,000)

Fair value of net assets recorded upon CENG consolidation

Baltimore Gas and Electric Company [Member] | Capital Project [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Baltimore Gas and Electric Company [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Supplemental Cash Flow Information [Line Items]

Litigation Settlement, Amount

1,600,000

Pepco Holdings LLC [Member] | Deferred Compensation, Share-based Payments [Member]

Supplemental Cash Flow Information [Line Items]

^[1]

29,000,000

Supplemental Cash Flow Information [Line Items]

209,000,000

Pension and non-pension postretirement benefit costs

258,000,000

86,000,000

65,000,000

1,000,000

Amortization of regulatory asset related to debt costs

3,000,000

(5,000,000)

317,000,000

56,000,000

2,000,000

1,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(12,000,000)

514,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

$ 0

(21,000,000)

NonCashFairValueAdjustment

127,000,000

Business Combination, Contingent Consideration, Liability, Noncurrent

$ 53,000,000

Supplemental Cash Flow Information [Line Items]

$ 43,000,000

268,000,000

257,000,000

Pension and non-pension postretirement benefit costs

11,000,000

(13,000,000)

(2,000,000)

23,000,000

97,000,000

58,000,000

16,000,000

61,000,000

49,000,000

1,000,000

3,000,000

13,000,000

18,000,000

Amortization of regulatory asset related to debt costs

1,000,000

5,000,000

5,000,000

(2,000,000)

2,000,000

2,000,000

1,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(3,000,000)

(10,000,000)

(6,000,000)

46,000,000

167,000,000

127,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(11,000,000)

(6,000,000)

(28,000,000)

Fair value of net assets recorded upon CENG consolidation

Pepco Holdings LLC [Member] | Indemnification Agreement [Member] | Successor [Member]

Supplemental Cash Flow Information [Line Items]

Pepco Holdings LLC [Member] | Indemnification Agreement [Member] | Predecessor [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

$ 0

Supplemental Cash Flow Information [Line Items]

118,000,000

116,000,000

111,000,000

Pension and non-pension postretirement benefit costs

216,000,000

(6,000,000)

(58,000,000)

31,000,000

30,000,000

22,000,000

29,000,000

21,000,000

17,000,000

3,000,000

Amortization of regulatory asset related to debt costs

2,000,000

3,000,000

(12,000,000)

1,000,000

3,000,000

125,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

5,000,000

(8,000,000)

183,000,000

54,000,000

37,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(27,000,000)

(1,000,000)

(10,000,000)

Fair value of net assets recorded upon CENG consolidation

33,000,000

Potomac Electric Power Company [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Supplemental Cash Flow Information [Line Items]

47,000,000

45,000,000

Pension and non-pension postretirement benefit costs

115,000,000

(5,000,000)

(43,000,000)

18,000,000

15,000,000

7,000,000

23,000,000

20,000,000

14,000,000

1,000,000

Amortization of regulatory asset related to debt costs

1,000,000

2,000,000

2,000,000

(3,000,000)

(1,000,000)

82,000,000

1,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(14,000,000)

114,000,000

33,000,000

22,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(12,000,000)

(3,000,000)

(8,000,000)

Fair value of net assets recorded upon CENG consolidation

Delmarva Power and Light Company [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Supplemental Cash Flow Information [Line Items]

62,000,000

63,000,000

61,000,000

Pension and non-pension postretirement benefit costs

200,000,000

(3,000,000)

15,000,000

13,000,000

32,000,000

20,000,000

13,000,000

1,000,000

Amortization of regulatory asset related to debt costs

1,000,000

110,000,000

2,000,000

Adjustments, Noncash Items, to Reconcile Net Income (Loss) to Cash Provided by (Used in) Operating Activities

(6,000,000)

1,000,000

155,000,000

37,000,000

26,000,000

Fair value of net assets contributed to Generation in connection with the PHI Merger, net of cash

(11,000,000)

(3,000,000)

(9,000,000)

Fair value of net assets recorded upon CENG consolidation

Atlantic City Electric Company [Member] | Indemnification Agreement [Member]

Supplemental Cash Flow Information [Line Items]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

$ 0

$ 0

Supplemental Cash Flow Information [Line Items]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Successor [Member]

^[2]

62,000,000

Supplemental Cash Flow Information [Line Items]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Successor [Member] | Deferred Compensation, Share-based Payments [Member]

33,000,000

Supplemental Cash Flow Information [Line Items]

Severance [Member] | Pepco Holdings LLC [Member] | Predecessor [Member]

$ 29,000,000

Supplemental Cash Flow Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

$ 0

[1]

[2]

he liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon. See Note 4 — Mergers, Acquisitions, and Dispositions.

Supplemental Financial Information - Narrative (Details) - PECO Energy Co [Member] $ in Millions	12 Months Ended
	Dec. 31, 2016 USD ($)
Supplemental Financial Information Tables [Line Items]
Amount included in capital expenditures	$ 2
Smart Grid Grant Reimbursements	$ 5

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

Dec. 31, 2016

Dec. 31, 2015

Net investment in leases(b)

$ 311

$ 112

^[1]

358

629

639

^[2]

1,199

1,014

723

293

1,234

915

260

133

Financing Trusts [Member]

3,460

2,376

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

^[3]

Bloom Energy [Member]

Supplemental Balance Sheet Information [Line Items]

216

Net Power [Member]

Other Equity Method Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Trust for Benefit of Employees [Member]

Supplemental Balance Sheet Information [Line Items]

Other Investments [Member]

^[4]

232

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

Net investment in leases(b)

288

^[1]

418

210

^[2]

557

547

239

186

114

Exelon Generation Co L L C [Member] | Financing Trusts [Member]

989

935

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]

216

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] | 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]

Supplemental Balance Sheet Information [Line Items]

^[2]

199

183

330

609

443

110

Commonwealth Edison Co [Member] | Financing Trusts [Member]

1,250

706

Supplemental Balance Sheet Information [Line Items]

Commonwealth Edison Co [Member] | Malacha [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

^[2]

PECO Energy Co [Member] | Financing Trusts [Member]

104

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]

^[2]

Baltimore Gas and Electric Company [Member] | Financing Trusts [Member]

175

110

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]

^[4]

Supplemental Balance Sheet Information [Line Items]

133

^[2]

112

272

Supplemental Balance Sheet Information [Line Items]

^[2]

Pepco Holdings LLC [Member] | Financing Trusts [Member] | Successor [Member]

266

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Financing Trusts [Member] | Predecessor [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Bloom Energy [Member] | Successor [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Bloom Energy [Member] | Predecessor [Member]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Net Power [Member] | Successor [Member]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Net Power [Member] | Predecessor [Member]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Other Equity Method Investments [Member] | Successor [Member]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Other Equity Method Investments [Member] | Predecessor [Member]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Trust for Benefit of Employees [Member] | Successor [Member]

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Trust for Benefit of Employees [Member] | Predecessor [Member]

133

Supplemental Balance Sheet Information [Line Items]

Pepco Holdings LLC [Member] | Other Investments [Member] | Predecessor [Member]

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

102

^[2]

Potomac Electric Power Company [Member] | Financing Trusts [Member]

113

119

Supplemental Balance Sheet Information [Line Items]

Potomac Electric Power Company [Member] | Bloom Energy [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Potomac Electric Power Company [Member] | Net Power [Member]

Supplemental Balance Sheet Information [Line Items]

Potomac Electric Power Company [Member] | Other Equity Method Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Potomac Electric Power Company [Member] | Trust for Benefit of Employees [Member]

Supplemental Balance Sheet Information [Line Items]

Potomac Electric Power Company [Member] | Other Investments [Member]

102

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

^[2]

Delmarva Power and Light Company [Member] | Financing Trusts [Member]

Supplemental Balance Sheet Information [Line Items]

Delmarva Power and Light Company [Member] | Bloom Energy [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Delmarva Power and Light Company [Member] | Net Power [Member]

Supplemental Balance Sheet Information [Line Items]

Delmarva Power and Light Company [Member] | Other Equity Method Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Delmarva Power and Light Company [Member] | Trust for Benefit of Employees [Member]

Supplemental Balance Sheet Information [Line Items]

Delmarva Power and Light Company [Member] | Other Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Supplemental Balance Sheet Information [Line Items]

^[2]

Atlantic City Electric Company [Member] | Financing Trusts [Member]

Supplemental Balance Sheet Information [Line Items]

Atlantic City Electric Company [Member] | Bloom Energy [Member]

^[3]

Supplemental Balance Sheet Information [Line Items]

Atlantic City Electric Company [Member] | Net Power [Member]

Supplemental Balance Sheet Information [Line Items]

Atlantic City Electric Company [Member] | Other Equity Method Investments [Member]

Supplemental Balance Sheet Information [Line Items]

Atlantic City Electric Company [Member] | Trust for Benefit of Employees [Member]

Supplemental Balance Sheet Information [Line Items]

Atlantic City Electric Company [Member] | Other Investments [Member]

$ 0

Supplemental Balance Sheet Information [Line Items]

$ 0

[1]	Represents direct financing lease investments.
[2]	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
[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.

Segment Information - Narrative (Details)	12 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2016 Reportable_segment
Segment Reporting Information [Line Items]
Number of reportable segments	12
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	6
Pepco Holdings LLC [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	3

Segment Information - Analysis and Reconciliation to Consolidated Financial Statements (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 13,960

$ 15,200

$ 13,773

13,869

9,876

9,467

1,166

1,176

1,325

211

757

154

2,146

2,433

2,704

3,936

2,450

2,314

Equity in earnings (losses) of unconsolidated affiliates

^[1]

28,200

25,056

25,039

(20)

(24)

(7)

Income (loss) from continuing operations before income taxes

1,536

1,033

1,065

1,989

3,330

2,486

761

1,073

666

1,204

2,250

1,820

^[2]

$ 114,904

$ 95,384

$ 114,904

114,904

95,384

^[3]

753

474

456

8,553

7,624

6,077

PECO Energy Co Affiliate [Member]

^[4]

^[5]

$ 1,096

4,770

4,614

^[5]

165

194

327

242

16,188

^[5]

^[5]

3,506

^[5]

(61)

21,025

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

^[5]

^[6]

^[6]

^[6]

^[6]

^[6]

^[6]

Equity in earnings (losses) of unconsolidated affiliates

^[1],[6]

1,928

1,444

1,353

^[6]

^[6]

Income (loss) from continuing operations before income taxes

^[6]

290

123

169

^[6]

(555)

(219)

(227)

^[6]

(156)

(41)

(63)

^[6]

(398)

(177)

(164)

^[6]

10,369

15,389

10,369

15,389

^[6]

113

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

^[6]

1,648

1,372

1,285

^[5],[7]

210

264

^[5],[7]

^[7]

^[7]

220

350

Income (loss) from continuing operations before income taxes

^[7]

^[7]

306

^[7]

(16)

(48)

(228)

^[7]

(44)

(78)

^[7]

7,162

^[7]

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

^[5],[7]

^[5],[7]

^[5],[7]

^[7]

^[7]

Income (loss) from continuing operations before income taxes

^[7]

^[7]

(84)

^[7]

(23)

^[7]

(34)

^[7]

10,804

^[7]

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

^[5],[7]

^[5]

268

1,295

1,210

^[5]

175

155

251

1,161

1,073

Income (loss) from continuing operations before income taxes

3,387

300

225

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

^[5]

^[5]

989

^[5]

128

1,000

Income (loss) from continuing operations before income taxes

(51)

(5)

(47)

3,457

218

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

^[5]

^[5]

279

1,138

1,088

^[5]

164

194

148

122

284

1,137

1,075

Income (loss) from continuing operations before income taxes

125

169

104

3,969

352

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

^[5]

^[5]

850

^[5]

120

952

Income (loss) from continuing operations before income taxes

(30)

(35)

4,153

277

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

^[5]

^[5]

511

2,129

2,055

^[5]

256

212

443

1,790

1,706

Income (loss) from continuing operations before income taxes

124

115

289

264

102

187

171

6,908

544

567

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

^[5]

^[5]

1,675

^[5]

224

1,577

Income (loss) from continuing operations before income taxes

7,335

489

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

^[5]

152

624

526

1,048

4,308

4,203

Income (loss) from continuing operations before income taxes

280

269

481

380

163

138

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

273

1,230

1,223

^[6],[8]

^[6],[8]

3,506

^[6],[8]

^[6],[8]

^[6],[8]

515

^[8]

Equity in earnings (losses) of unconsolidated affiliates

3,549

^[6],[8]

^[8]

^[8]

Income (loss) from continuing operations before income taxes

195

^[8]

(58)

^[8]

^[8]

^[8]

(61)

^[8]

21,025

1,008

^[8]

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

^[6],[8]

^[9]

15,390

15,944

14,533

^[9]

^[9]

^[9]

215

758

155

^[9]

2,146

2,433

2,705

^[9]

1,879

1,054

967

Equity in earnings (losses) of unconsolidated affiliates

^[1],[9]

16,856

16,872

16,923

^[9]

(20)

^[9]

(25)

(8)

Income (loss) from continuing operations before income taxes

^[9]

364

365

356

^[9]

873

1,850

1,226

^[9]

290

502

207

^[9]

558

1,340

1,019

^[9]

46,974

46,529

46,974

46,529

^[9]

3,078

3,841

3,012

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

^[9]

5,254

4,905

4,564

775

707

687

Equity in earnings (losses) of unconsolidated affiliates

^[1]

4,056

3,889

3,586

Income (loss) from continuing operations before income taxes

461

332

321

679

706

676

301

280

268

378

426

408

28,335

26,532

28,335

26,532

2,734

2,398

1,689

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

2,531

2,486

2,448

463

546

646

270

260

236

Equity in earnings (losses) of unconsolidated affiliates

^[1]

2,292

2,404

2,522

Income (loss) from continuing operations before income taxes

123

114

113

587

521

466

149

143

114

438

378

352

10,831

10,367

10,831

10,367

686

601

661

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

^[10]

^[10]

2,609

2,490

2,460

^[10]

624

645

705

^[10]

^[10]

^[10]

423

366

371

Equity in earnings (losses) of unconsolidated affiliates

^[1],[10]

2,683

2,578

2,726

^[10]

^[10]

Income (loss) from continuing operations before income taxes

^[10]

103

106

^[10]

468

477

351

^[10]

174

189

140

^[10]

294

288

211

^[10]

8,704

8,295

8,704

8,295

^[10]

934

719

620

Intersegment Eliminations [Member]

^[10]

(1,430)

(744)

(760)

(31)

(5)

(13)

(15)

(26)

(4)

(1)

(1)

^[8]

Equity in earnings (losses) of unconsolidated affiliates

^[1]

(3,164)

(2,131)

(2,071)

Income (loss) from continuing operations before income taxes

(5)

(6)

(5)

(6)

(11,334)

(11,728)

(11,334)

(11,728)

Intersegment Eliminations [Member] | Predecessor [Member]

(1,686)

(1,367)

(1,279)

^[5]

(4)

(2)

(3)

^[5]

(1)

(5,238)

Intersegment Eliminations [Member] | Successor [Member]

^[5]

^[5]

(13)

^[5]

(4,724)

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

^[5]

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

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

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

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

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

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

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

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

^[1],[8]

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

1,428

745

^[8],[9]

762

^[8],[9]

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

^[8]

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

^[8]

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

^[8],[10]

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

^[1]

1,647

^[10]

1,367

^[8]

1,280

^[8]

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

^[7]

Intersegment Eliminations [Member] | Generation Midwest [Member]

^[7]

Intersegment Eliminations [Member] | Segment Elimination [Member]

(2)

(13)

Intersegment Eliminations [Member] | Segment Elimination [Member] | Predecessor [Member]

^[8]

(3,159)

(2,127)

(2,067)

(4)

(15)

(16)

(4)

(1)

(3)

(1)

Income (loss) from continuing operations before income taxes

(2)

(1)

(118)

(29)

(435)

178

Intersegment Eliminations [Member] | Segment Elimination [Member] | Successor [Member]

(13)

(13)

Income (loss) from continuing operations before income taxes

Equity in earnings (losses) of unconsolidated affiliates

1,439

749

779

(25)

(8)

Income (loss) from continuing operations before income taxes

$ 19

(20)

873

1,850

1,226

290

502

207

558

1,340

1,019

^[11]

46,974

46,529

46,974

46,529

^[3]

122

105

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

3,078

3,841

3,012

Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]

^[12]

290

224

198

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

^[13]

608

502

387

Exelon Generation Co L L C [Member] | Potomac Electric Power Company [Member]

^[14]

176

Exelon Generation Co L L C [Member] | Delmarva Power and Light Company [Member]

^[13]

295

Exelon Generation Co L L C [Member] | Atlantic City Electric Company [Member]

^[13]

154

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

^[13]

^[14]

5,239

4,901

4,560

301

280

268

$ 37

$ 145

$ 115

$ 149

$ 99

$ 90

378

426

408

28,335

26,532

28,335

26,532

^[3]

242

236

238

Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member]

2,734

2,398

1,689

2,524

2,485

2,446

462

545

646

Income (loss) from continuing operations before income taxes

587

521

466

149

143

114

438

378

352

10,831

10,367

10,831

10,367

^[3]

136

133

128

PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]

686

601

661

PECO Energy Co [Member] | Exelon Generation Co L L C [Member]

2,603

2,490

2,460

609

631

680

Income (loss) from continuing operations before income taxes

468

477

351

174

189

140

294

288

211

^[15]

8,704

8,295

8,704

8,295

^[3]

Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]

934

719

620

Baltimore Gas and Electric Company [Member] | Commonwealth Edison Co Affiliate [Member]

1,096

4,770

4,614

165

194

Income (loss) from continuing operations before income taxes

481

380

163

138

327

242

^[16]

16,188

^[3]

326

324

$ 273

1,230

1,223

3,506

Income (loss) from continuing operations before income taxes

(58)

(61)

^[16]

21,025

^[3]

253

1,008

2,181

2,124

2,050

Income (loss) from continuing operations before income taxes

289

264

102

187

171

7,335

6,908

7,335

6,908

^[3]

312

308

307

586

544

567

1,122

1,132

1,081

148

164

194

Income (loss) from continuing operations before income taxes

125

169

(9)

104

4,153

3,969

4,153

3,969

^[3]

349

352

1,254

1,291

1,206

Income (loss) from continuing operations before income taxes

(46)

(4)

(42)

^[17]

$ 3,457

$ 3,387

$ 3,457

3,457

3,387

^[3]

$ 311

$ 300

$ 225

[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]	Exelon’s consolidated assets include $8,893 million and $8,268 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,356 million and $3,264 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[3]	Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[4]	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 Statements of Operations. See Note 3—Regulatory Matters for additional information.
[5]	Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses on the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 25 — Supplemental Financial Information for total utility taxes for the year ended December 31, 2016 and 2015
[6]	(c)For the years ended December 31, 2016, 2015 and 2014, utility taxes of $122 million, $105 million and $89 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $242 million, $236 million and $238 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $136 million, $133 million and $128 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $85 million, $85 million and $86 million are included in revenues and expenses for BGE, respectively.
[7]	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.
[8]	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the years ended December 31, 2015
[9]	Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended December 31, 2016, intersegment revenues for Generation include revenue from sales to PECO of $290 million, sales to BGE of $608 million, sales to Pepco of $295 million, sales to DPL of $154 million and sales to ACE of $37 million in the Mid-Atlantic region, and sales to ComEd of $47 million in the Midwest region, which eliminate upon consolidation. 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, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.
[10]	(b)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[11]	Generation’s consolidated assets include $8,817 million and $8,235 million at December 31, 2016 and 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,170 million and $3,135 million at December 31, 2016 and 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[12]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. See Note 3—Regulatory Matters for additional information.
[13]	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.
[14]	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.
[15]	BGE’s consolidated assets include $26 million and $26 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million and $122 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.
[16]	PHI’s consolidated total assets include $49 million and $30 million at December 31, 2016 and 2015, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $143 million and $172 million at December 31, 2016 and 2015, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities.
[17]	ACE’s consolidated assets include $32 million and $30 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated liabilities include $126 million and $172 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities.

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

3 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 7,875

$ 9,002

$ 6,910

$ 7,573

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 31,360

$ 29,447

$ 27,429

Generation Mid Atlantic [Member]

Generation Midwest [Member]

6,179

5,900

5,259

Generation New England [Member]

4,412

4,710

4,475

Generation New York [Member]

1,769

2,212

1,422

Generation ERCOT [Member]

1,156

985

843

Generation Other Regions [Member]

837

857

935

Generation Reportable Segments Total [Member]

^[1]

907

1,102

1,309

Generation All Other Segments [Member]

15,260

15,766

14,243

^[2]

2,491

3,369

3,150

(41)

(591)

Generation Total Consolidated Group [Member]

257

Scenario, Adjustment [Member] | Generation Reportable Segments Total [Member]

17,751

19,135

17,393

Scenario, Adjustment [Member] | Generation All Other Segments [Member]

(284)

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

284

Operating Segments [Member] | Generation Midwest [Member]

^[3]

6,212

5,974

5,414

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

^[3]

4,402

4,712

4,488

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

^[3]

1,778

2,217

1,468

Operating Segments [Member] | Generation ERCOT [Member]

^[3]

1,198

996

846

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

^[3]

831

863

938

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

^[1],[3]

969

1,182

1,379

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

^[3]

15,390

15,944

14,533

Amortization of intangible assets related to commodity contracts

^[2],[3]

2,361

3,191

2,860

289

(500)

(174)

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

203

Operating Segments [Member] | Scenario, Adjustment [Member] | Generation Reportable Segments Total [Member]

^[3]

17,751

19,135

17,393

Operating Segments [Member] | Scenario, Adjustment [Member] | Generation All Other Segments [Member]

284

Intersegment Eliminations [Member]

(284)

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

^[4]

Intersegment Eliminations [Member] | Generation Midwest [Member]

(33)

(74)

(155)

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

(2)

(13)

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

(9)

(5)

(46)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

(42)

(11)

(3)

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

(6)

(3)

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

^[1]

(62)

(80)

(70)

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

(130)

(178)

(290)

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

^[2]

130

178

290

Scenario, Adjustment [Member]

$ 0

[1]	(b)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants
[2]	(c)Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $52 million decrease to revenues, a $7 million increase to revenues, and a $289 million decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2016, 2015, and 2014, respectively, unrealized mark-to-market losses of $500 million, gains of $203 million, and losses of $174 million for the years ended December 31, 2016, 2015, and 2014, 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]	Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the years ended December 31, 2015

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

12 Months Ended

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Revenue net of purchased power and fuel expense, Total

$ 19

Generation Mid Atlantic [Member]

Revenue net of purchased power and fuel expense, Total

$ 3,317

$ 3,571

3,431

Generation Midwest [Member]

Revenue net of purchased power and fuel expense, Total

2,971

2,892

2,599

Generation New England [Member]

Revenue net of purchased power and fuel expense, Total

438

461

351

Generation New York [Member]

Revenue net of purchased power and fuel expense, Total

742

634

483

Generation ERCOT [Member]

Revenue net of purchased power and fuel expense, Total

281

293

317

Generation Other Regions [Member]

Revenue net of purchased power and fuel expense, Total

^[1]

336

250

327

Generation Reportable Segments Total [Member]

Revenue net of purchased power and fuel expense, Total

8,085

8,101

7,508

Generation Reportable Segments Total [Member] | Scenario, Adjustment [Member]

Revenue net of purchased power and fuel expense from external customers

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

Generation All Other Segments [Member]

Revenue net of purchased power and fuel expense, Total

^[2]

836

1,013

(40)

Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel

(57)

(124)

(257)

Generation All Other Segments [Member] | Scenario, Adjustment [Member]

591

Revenue net of purchased power and fuel expense from external customers

(11)

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(8)

Generation Total Consolidated Group [Member]

Revenue net of purchased power and fuel expense, Total

8,921

9,114

7,468

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

Revenue net of purchased power and fuel expense from external customers

^[3]

3,282

3,556

3,544

Operating Segments [Member] | Generation Midwest [Member]

Revenue net of purchased power and fuel expense from external customers

^[3]

2,969

2,912

2,607

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

Revenue net of purchased power and fuel expense from external customers

^[3]

467

519

450

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

Revenue net of purchased power and fuel expense from external customers

^[3]

761

584

439

Operating Segments [Member] | Generation ERCOT [Member]

Revenue net of purchased power and fuel expense from external customers

^[3]

412

425

573

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

Revenue net of purchased power and fuel expense from external customers

^[1],[3]

483

440

517

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

Revenue net of purchased power and fuel expense from external customers

^[3]

8,374

8,436

8,130

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

Revenue net of purchased power and fuel expense from external customers

^[2],[3]

547

678

(662)

(203)

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

500

174

Revenue net of purchased power and fuel expense from external customers

^[3]

8,921

9,114

7,468

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(113)

Intersegment Eliminations [Member] | Generation Midwest [Member]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(20)

(8)

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(29)

(58)

(99)

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(19)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(131)

(132)

(256)

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

^[1]

(147)

(190)

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

(289)

(335)

(622)

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

^[2]

289

335

622

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

Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity

$ 0

[1]	(b)Includes purchases and sales from third parties and affiliated sales to the Utility Registrants.
[2]	(c)Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $57 million decrease in RNF, a $8 million increase in RNF, and a $124 million decrease in RNF for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended December 31, 2016, 2015, and 2014, respectively, unrealized mark-to-market losses of $41 million, gains of $257 million, and losses of $591 million for the years ended December 31, 2016, 2015, and 2014, respectively, accelerated nuclear fuel amortization associated with the initial early retirement decision for Clinton and Quad Cities as discussed in Note 9 - Early Nuclear Plant Retirements of $60 million for the year ended December 31, 2016, and the elimination of intersegment revenues net of purchased power and fuel expense.
[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 net of purchased power and fuel expense are included on a fully consolidated basis.

Related Party Transactions - Related Party Transactions included in Consolidated Income Statement (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 10

$ 9

$ 23

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

(20)

(24)

(7)

1,166

1,105

1,065

531

PECO Energy Co Affiliate [Member]

10,048

8,322

8,568

Constellation Energy Nuclear Group Llc Affiliate [Member]

^[1]

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

^[2]

^[2]

(19)

^[3]

282

Keystone Fuels LLC Affiliate [Member]

^[1]

Conemaugh Fuels LLC Affiliate [Member]

^[4]

138

SafeHarborWaterPowerCorp [Member]

^[4]

PECO Trust Three Affiliate [Member]

^[4]

PECO Trust Four Affiliate [Member]

BGE Capital Trust II [Member]

Other Affiliate [Member]

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

Qualifying Facilities And Domestic Power Projects Affiliate [Member]

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

(25)

(8)

(1)

227

195

166

369

299

307

315

202

273

315

202

273

1,411

1,301

1,001

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

1,303

1,372

1,263

Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member]

^[5]

176

Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]

^[6]

369

299

307

Commonwealth Edison Co [Member] | Baltimore Gas and Electric Company [Member]

315

202

273

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

^[6]

225

195

166

^[6]

112

103

139

139

614

708

664

Atlantic City Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

410

268

247

Atlantic City Electric Company [Member] | PHI Service Co Affiliate [Member]

^[7]

Atlantic City Electric Company [Member] | Exelon Corporation Affiliate [Member]

155

143

124

Contribution from member

139

Atlantic City Electric Company [Member] | Other Affiliate [Member]

Atlantic City Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

^[8]

132

118

103

179

158

528

602

733

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

605

565

614

^[9]

Baltimore Gas and Electric Company [Member] | Commonwealth Edison Co Affiliate [Member]

^[10]

604

498

382

Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]

Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]

179

158

Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

^[11]

130

118

103

^[11]

146

110

277

279

320

598

735

740

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

665

684

767

^[12]

PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]

^[13]

287

220

194

PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]

277

279

320

PECO Energy Co [Member] | Baltimore Gas and Electric Company [Member]

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

^[14]

142

107

^[14]

$ 0

275

272

471

1,986

1,940

$ 294

1,156

1,183

$ 45

273

1,251

925

Pepco Holdings LLC [Member] | Exelon Generation Co LLC Affiliate [Member] | Successor [Member]

1,144

Pepco Holdings LLC [Member] | PHI Service Co Affiliate [Member] | Successor [Member]

486

Pepco Holdings LLC [Member] | Exelon Corporation Affiliate [Member]

1,251

Pepco Holdings LLC [Member] | Exelon Business Services Co Affiliate [Member] | Successor [Member]

273

$ 86

136

146

187

112

187

112

411

719

735

Potomac Electric Power Company [Member] | Corporate, Non-Segment [Member]

607

435

386

Potomac Electric Power Company [Member] | Exelon Generation Co LLC Affiliate [Member]

302

266

250

^[15]

Potomac Electric Power Company [Member] | PHI Service Co Affiliate [Member]

^[16]

295

^[17]

Potomac Electric Power Company [Member] | Pepco Energy Services Affiliate [Member]

263

240

220

Potomac Electric Power Company [Member] | Exelon Corporation Affiliate [Member]

136

146

Potomac Electric Power Company [Member] | Exelon Business Services Co Affiliate [Member]

187

112

^[17]

100

152

130

152

130

369

555

536

Delmarva Power and Light Company [Member] | Corporate, Non-Segment [Member]

422

303

266

Delmarva Power and Light Company [Member] | Exelon Generation Co LLC Affiliate [Member]

202

182

163

Delmarva Power and Light Company [Member] | PHI Service Co Affiliate [Member]

^[18]

154

^[19]

Delmarva Power and Light Company [Member] | Pepco Energy Services Affiliate [Member]

194

179

163

Delmarva Power and Light Company [Member] | Exelon Corporation Affiliate [Member]

100

Delmarva Power and Light Company [Member] | Other Affiliate [Member]

152

130

Delmarva Power and Light Company [Member] | Exelon Business Services Co Affiliate [Member]

^[19]

1,439

749

779

663

620

623

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

(25)

(8)

$ 19

(20)

922

2,474

645

Contribution from member

142

170

557

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

4,978

4,688

4,943

^[20]

176

^[21]

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

^[22]

290

224

198

Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]

^[21]

^[23]

608

502

387

^[21]

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member]

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

^[24]

^[24]

(19)

Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]

^[25]

282

Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member]

922

2,474

645

Contribution from member

142

Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member]

^[26]

138

Exelon Generation Co L L C [Member] | SafeHarborWaterPowerCorp [Member]

^[26]

Exelon Generation Co L L C [Member] | Other Affiliate [Member]

Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member]

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

(25)

(8)

(1)

Exelon Generation Co L L C [Member] | Pepco Holdings LLC [Member]

Exelon Generation Co L L C [Member] | Potomac Electric Power Company [Member]

^[23]

295

Exelon Generation Co L L C [Member] | Delmarva Power and Light Company [Member]

Exelon Generation Co L L C [Member] | Atlantic City Electric Company [Member]

^[23]

154

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

^[23]

Total payables to affiliates (current)

^[27]

650

614

618

^[6]

$ 98

$ 76

$ 91

[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 Statements 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]	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.
[6]	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.
[7]	.
[8]	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[9]	BGE provides energy to Generation for Generation’s own use.
[10]	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.
[11]	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.
[12]	PECO provides energy to Generation for Generation’s own use.
[13]	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.
[14]	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.
[15]	Pepco provides energy to Generation for Generation’s own use.
[16]	Pepco procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[17]	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[18]	DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[19]	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[20]	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.
[21]	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
[22]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. See Note 3—Regulatory Matters for additional information.
[23]	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.
[24]	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.
[25]	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.
[26]	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.
[27]	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Related Party Transactions - Related Party Transactions included in Consolidated Balance Sheet (Details) - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2015

Dec. 31, 2012

Dec. 31, 2016

$ 0

$ (706)

641

BGE Capital Trust II [Member]

252

205

PECO Trust Three Affiliate [Member]

PECO Trust Four Affiliate [Member]

103

Potomac Electric Power Company [Member] | PHI Service Co Affiliate [Member]

Potomac Electric Power Company [Member] | Delmarva Power and Light Company [Member]

^[1]

Potomac Electric Power Company [Member] | Exelon Corporation Affiliate [Member]

Potomac Electric Power Company [Member] | Other Affiliate [Member]

Potomac Electric Power Company [Member] | Exelon Generation Co LLC Affiliate [Member]

Potomac Electric Power Company [Member] | Exelon Business Services Co Affiliate [Member]

^[2]

Potomac Electric Power Company [Member] | Pepco Energy Services Affiliate [Member]

^[1]

^[3]

Delmarva Power and Light Company [Member] | PHI Service Co Affiliate [Member]

Delmarva Power and Light Company [Member] | Atlantic City Electric Company [Member]

^[4]

Delmarva Power and Light Company [Member] | Other Affiliate [Member]

Delmarva Power and Light Company [Member] | Potomac Electric Power Company [Member]

Delmarva Power and Light Company [Member] | Exelon Generation Co LLC Affiliate [Member]

Delmarva Power and Light Company [Member] | Exelon Business Services Co Affiliate [Member]

^[4]

252

Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]

252

Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]

Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

^[5]

Baltimore Gas and Electric Company [Member] | Commonwealth Edison Co Affiliate [Member]

^[6]

Total payables to affiliates (current)

(1)

Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]

405

438

184

PECO Energy Co [Member] | Voluntary Employee Beneficiary Association Trust [Member]

Prepaid Expense Other, Noncurrent

^[7]

PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]

PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]

PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]

103

PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]

PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[8]

405

438

PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]

^[9]

PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]

^[10]

199

356

2,172

2,170

205

Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]

205

Commonwealth Edison Co [Member] | Voluntary Employee Beneficiary Association Trust [Member]

Prepaid Expense Other, Noncurrent

^[11]

Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]

Commonwealth Edison Co [Member] | Other Affiliate [Member]

188

^[12]

345

Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]

^[13]

2,172

2,169

Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]

^[14]

Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member]

^[15]

Pepco Holdings LLC [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Pepco Holdings LLC [Member] | Exelon Corporation Affiliate [Member] | Successor [Member]

Pepco Holdings LLC [Member] | Exelon Generation Co LLC Affiliate [Member] | Successor [Member]

Pepco Holdings LLC [Member] | Exelon Business Services Co Affiliate [Member] | Successor [Member]

Atlantic City Electric Company [Member] | PHI Service Co Affiliate [Member]

Atlantic City Electric Company [Member] | Delmarva Power and Light Company [Member]

^[16]

Atlantic City Electric Company [Member] | Other Affiliate [Member]

Atlantic City Electric Company [Member] | Potomac Electric Power Company [Member]

Atlantic City Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]

Atlantic City Electric Company [Member] | Exelon Business Services Co Affiliate [Member]

^[17]

Constellation Energy Group LLC [Member] | Electricite De France LLC [Member]

$ 0

^[16]

Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased

49.99%

Due to Related Parties, Current

$ 83

156

1,252

Notes Payable, Related Parties, Current

933

922

1,252

104

137

Exelon Generation Co L L C [Member] | PHI Service Co Affiliate [Member]

$ 2,577

2,608

Exelon Generation Co L L C [Member] | Pepco Holdings LLC [Member]

^[18]

Due to Related Parties, Current

Exelon Generation Co L L C [Member] | Atlantic City Electric Company [Member]

Exelon Generation Co L L C [Member] | Delmarva Power and Light Company [Member]

^[19]

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

^[20]

Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased

85.00%

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member]

Long-term Contract for Purchase of Electric Power, Share of Plant Output Being Purchased

50.01%

Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]

Due to Related Parties, Current

$ 0

Notes Payable, Related Parties, Current

^[21]

933

922

1,252

Exelon Generation Co L L C [Member] | Other Affiliate [Member]

^[22]

Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]

Exelon Generation Co L L C [Member] | Potomac Electric Power Company [Member]

^[23]

Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]

^[24]

^[18]

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

^[18]

^[25]

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

^[26]

2,172

2,169

^[27]

Selected Quarterly Financial Information [Line Items]

^[26]

$ 405

$ 438

[1]	Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[2]	Pepco procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[3]	Pepco bills customers on behalf of PES where PES has performed work for certain government agencies under a General Services Administration area-wide agreement on behalf of Pepco.
[4]	DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[5]	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.
[6]	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.
[7]	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.
[8]	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.
[9]	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.
[10]	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.
[11]	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.
[12]	Represents indemnification from Exelon Corporate related to the like-kind exchange.
[13]	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.
[14]	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.
[15]	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.
[16]	.
[17]	ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[18]	Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[19]	(f)Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process. See Note 3—Regulatory Matters for additional information.
[20]	(e)Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[21]	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.
[22]	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.
[23]	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.
[24]	See Note 3—Regulatory Matters for additional information.(d)Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC. See Note 3—Regulatory Matters for additional information.
[25]	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.
[26]	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
[27]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs. See Note 3—Regulatory Matters for additional information.

Quarterly Data (Unaudited) - Quarterly Operating Results (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Dec. 31, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

$ 7,875

$ 9,002

$ 6,910

$ 7,573

$ 6,702

$ 7,401

$ 6,514

$ 8,830

$ 31,360

$ 29,447

$ 27,429

Net Income (Loss) Attributable to Common Stockholders

714

1,267

647

483

707

1,200

1,134

1,366

3,112

4,409

3,096

204

490

267

173

309

629

638

693

1,134

2,269

1,623

1,204

2,250

1,820

Selected Quarterly Financial Information [Line Items]

4,388

5,035

3,589

4,739

4,294

4,768

4,232

5,840

17,751

19,135

17,393

Net (Loss) Income Attributable to Membership Interest

342

(13)

415

230

622

703

719

836

2,275

1,176

(41)

236

(8)

310

154

377

398

443

496

1,372

835

558

1,340

1,019

Selected Quarterly Financial Information [Line Items]

1,223

1,497

1,286

1,249

1,196

1,376

1,148

1,185

5,254

4,905

4,564

217

389

324

274

217

327

243

230

1,205

1,017

980

145

115

149

378

426

408

Selected Quarterly Financial Information [Line Items]

701

788

664

841

645

740

661

985

2,994

3,032

3,094

Net Income (Loss) Attributable to Common Stockholders

150

204

152

196

128

154

124

223

702

630

572

122

100

124

139

438

378

352

438

378

352

Selected Quarterly Financial Information [Line Items]

812

680

929

746

725

628

1,036

3,233

3,135

3,165

Net Income (Loss) Attributable to Common Stockholders

190

115

187

144

110

204

550

558

439

103

106

286

275

198

294

288

211

Selected Quarterly Financial Information [Line Items]

1,078

1,394

1,066

105

^[1]

$ 3,643

Net (Loss) Income Attributable to Membership Interest

279

136

(411)

^[1]

166

(309)

^[1]

(61)

$ (61)

Selected Quarterly Financial Information [Line Items]

$ 1,153

1,126

1,336

1,119

1,354

4,935

4,808

Net (Loss) Income Attributable to Membership Interest

105

208

184

139

142

673

605

130

327

242

$ 19

327

242

Selected Quarterly Financial Information [Line Items]

491

635

509

551

488

592

504

545

2,186

2,129

2,055

Net Income (Loss) Attributable to Common Stockholders

132

(105)

123

115

174

385

349

(108)

187

171

187

171

Selected Quarterly Financial Information [Line Items]

303

331

281

362

296

314

271

421

1,277

1,302

1,282

Net Income (Loss) Attributable to Common Stockholders

(72)

165

207

(72)

(9)

104

(9)

104

Selected Quarterly Financial Information [Line Items]

275

421

270

291

386

285

334

1,257

1,295

1,210

Net Income (Loss) Attributable to Common Stockholders

(121)

134

137

$ 8

$ 47

$ 3

$ (100)

$ 3

$ 22

$ 6

$ 9

(42)

$ (42)

$ 40

$ 46

[1]	Amounts for March 31, 2016 reflect the PHI Successor activity for the period March 24, 2016 to March 31, 2016.

Quarterly Data (Unaudited) - Quarterly Per Share Information (Details) - $ / shares shares in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Weighted average common shares outstanding—basic	925	925	924	923	921	913	863	862	924	890	860
Net Income per Basic Share	$ 0.22	$ 0.53	$ 0.29	$ 0.19	$ 0.34	$ 0.69	$ 0.74	$ 0.80
Weighted average common shares outstanding—diluted	928	927	926	925	924	915	866	867	927	893	864
Net Income per Diluted Share	$ 0.22	$ 0.53	$ 0.29	$ 0.19	$ 0.33	$ 0.69	$ 0.74	$ 0.80	$ 1.22	$ 2.54	$ 1.88

Quarterly Data (Unaudited) - Quarterly Composite Common Stock Prices and Dividends (Details) - USD ($)	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015
Quarterly Financial Data [Abstract]
High price	$ 36.36	$ 37.70	$ 36.37	$ 35.95	$ 31.37	$ 34.44	$ 34.98	$ 38.25
Low price	$ 29.82	$ 32.86	$ 33.18	$ 26.26	$ 25.09	$ 28.41	$ 31.28	$ 31.71
Close	$ 35.49	$ 33.29	$ 36.36	$ 35.86	$ 27.77	$ 29.70	$ 31.42	$ 33.61
Dividends	$ 0.318	$ 0.318	$ 0.318	$ 0.310	$ 0.310	$ 0.310	$ 0.310	$ 0.310

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, 2016

Sep. 30, 2016

Jun. 30, 2016

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Operating Expenses [Abstract]

$ 10,048

$ 8,322

$ 8,568

28,200

25,056

25,039

$ 714

$ 1,267

$ 647

$ 483

$ 707

$ 1,200

$ 1,134

$ 1,366

3,112

4,409

3,096

(1,495)

(992)

(1,024)

(24)

(7)

413

(46)

455

(1,123)

(1,079)

(610)

1,989

3,330

2,486

761

1,073

666

Pension and non-pension postretirement benefit plans:

1,204

2,250

1,820

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

Actuarial loss reclassified to periodic cost, net of tax

184

220

147

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

$ 0

(148)

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

(4)

(3)

Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax

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

(21)

(9)

(116)

(36)

^[1]

(644)

1,098

2,329

979

Operating Expenses [Abstract]

221

276

(276)

(47)

(50)

(312)

(168)

(237)

Interest income from affiliates, net

1,521

2,461

1,779

(43)

(2)

1,255

2,293

1,593

979

2,246

1,543

(155)

(23)

(80)

Pension and non-pension postretirement benefit plans:

1,134

2,269

1,623

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

Actuarial loss reclassified to periodic cost, net of tax

184

220

147

Other Comprehensive Income (Loss), Finalization of Pension and Other Postretirement Benefit Plan Valuation, Net of Tax

181

497

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

(148)

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

(4)

(3)

Other Comprehensive Income (Loss), Available-for-sale Securities Adjustment, Net of Tax

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

(21)

(9)

116

(36)

(644)

$ 1,098

$ 2,329

$ 979

[1]	All amounts are net of tax and noncontrolling interests. 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, 2016	Dec. 31, 2015	Dec. 31, 2014
Net cash flows provided by operating activities		$ 8,445	$ 7,616	$ 4,457
Cash flows from investing activities
Proceeds From Lease Termination	$ 335	360
Proceeds from Sale and Collection of Lease Receivables		360	0	335
Capital expenditures		(8,553)	(7,624)	(6,077)
Cash and restricted cash acquired from Constellation		0	0	140
Change in restricted cash		(42)	66	(104)
Other investing activities		(153)	(119)	(88)
Net cash flows used in investing activities		(15,503)	(7,822)	(4,599)
Cash flows from financing activities
Changes in short-term borrowings		240	0	0
Issuance of long-term debt		4,716	6,709	3,463
Retirement of long-term debt		(1,936)	(2,687)	(1,545)
Proceeds from Issuance of Common Stock		0	1,868	0
Dividends paid on common stock		(1,166)	(1,105)	(1,065)
Proceeds from employee stock plans		55	32	35
Other financing activities		(85)	(99)	(178)
Net cash flows provided by financing activities		1,191	4,830	411
(Decrease) Increase in cash and cash equivalents		(5,867)	4,624	269
Cash and cash equivalents at beginning of period		6,502	1,878	1,609
Cash and cash equivalents at end of period		635	6,502	1,878
Exelon Corporate [Member]
Net cash flows provided by operating activities		1,029	3,071	806
Cash flows from investing activities
Payments to Acquire Businesses, Net of Cash Acquired		(6,962)
Proceeds from Sale and Collection of Lease Receivables		0	0	335
Increase (Decrease) Due from Affiliates		1,390	(1,217)	(83)
Increase (Decrease) in Due from Affiliates, Current		0	550	0
Capital expenditures		0	0	1
Investment in affiliates		(1,757)	(212)	(70)
Other investing activities		5	(55)	(126)
Net cash flows used in investing activities		(7,324)	(934)	57
Cash flows from financing activities
Issuance of long-term debt		1,800	4,200	1,150
Retirement of long-term debt		(46)	(2,263)	(23)
Proceeds from Issuance of Common Stock		0	1,868	0
Dividends paid on common stock		(1,166)	(1,105)	(1,065)
Proceeds from employee stock plans		55	32	35
Other financing activities		(20)	(58)	(84)
Net cash flows provided by financing activities		623	2,674	13
(Decrease) Increase in cash and cash equivalents		(5,672)	4,811	876
Cash and cash equivalents at beginning of period		5,690	879	3
Cash and cash equivalents at end of period		$ 18	$ 5,690	$ 879

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet (Details) - USD ($)
$ in Millions

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

$ 635

$ 6,502

$ 1,878

$ 1,609

Prepaid Taxes

1,250

1,201

912

1,342

759

930

752

12,412

15,334

71,555

57,439

10,046

6,065

1,472

1,445

^[1]

114,904

95,384

Short-term Debt

1,267

533

706

2,430

1,500

3,441

2,883

407

100

3,460

2,376

602

369

981

842

13,457

9,118

31,575

23,645

4,187

4,201

4,248

3,385

1,848

1,618

1,827

1,491

^[1]

87,292

68,062

Treasury stock, at cost (35 shares at December 31, 2016 and 2015, respectively)

18,794

18,676

(2,327)

12,030

12,068

(2,660)

(2,624)

BGE preference stock not subject to mandatory redemption

25,837

25,793

193

114,904

95,384

5,690

$ 879

$ 3

272

1,478

263

241

1,250

1,740

7,706

4,033

3,072

34,869

26,119

Receivable from affiliates

2,107

2,036

922

933

Defined Benefit Plan, Assets for Plan Benefits, Noncurrent

108

Total deferred debits and other assets

256

404

42,187

32,672

43,978

40,431

Short-term Debt

188

706

570

489

440

Pension and Other Postretirement Defined Benefit Plans, Current Liabilities

1,891

809

7,193

6,017

8,608

7,520

226

134

182

122

9,054

7,807

Commitments and Contingencies

18,138

14,633

Treasury stock, at cost (35 shares at December 31, 2016 and 2015, respectively)

18,797

18,678

(2,327)

12,030

12,068

(2,660)

(2,624)

BGE preference stock not subject to mandatory redemption

25,840

25,795

$ 43,978

$ 40,431

[1]

Exelon’s consolidated assets include $8,893 million and $8,268 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,356 million and $3,264 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet - Phantom (Details) - $ / shares	Dec. 31, 2016	Dec. 31, 2015
Common stock, par value	$ 0	$ 0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	924,035,059	919,924,742
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
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, 2016
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	100.00%
Commonwealth Edison Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	99.00%
Baltimore Gas and Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	100.00%
Baltimore Gas and Electric Company [Member] \| Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	0.00%
PECO Energy Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	100.00%
PECO Energy Co [Member] \| Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest	0.00%

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Narrative (Details)

Dec. 31, 2016

USD ($)

Line of Credit Facility, Capacity Available for Trade Purchases

$ 7,108,000,000

^[1]

Line of Credit Facility, Capacity Available for Trade Purchases

571,000,000

^[1]

Revolving Credit Facility [Member] | Exelon Corporate [Member]

9,500,000,000

^[2]

$ 600,000,000

^[3],[4]

[1]	Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. The borrowing capacity may be increased or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of credit used at any given time by each of Pepco, DPL or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
[2]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
[3]	Excludes $500 million and $275 million in bilateral credit facilities that do not back Generation's commercial paper program at December 31, 2016 and 2015, respectively
[4]	Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million, $34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities' service territories. These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Outstanding Long-term Debt (Details) - USD ($)

Dec. 31, 2016

Dec. 31, 2015

Jun. 30, 2015

$ 33,311,000,000

$ 25,113,000,000

(68,000,000)

(63,000,000)

31,575,000,000

23,645,000,000

Junior Subordinated Debt [Member]

^[1]

(200,000,000)

(180,000,000)

1,150,000,000

$ 1,150,000,000.00

contract Payments Junior Subordinate Debt [Member]

11,868,000,000

9,803,000,000

Maximum [Member] | Junior Subordinated Debt [Member]

$ 19,000,000

64,000,000

Maximum [Member] | Senior Notes [Member]

6.50%

Maximum [Member] | contract Payments Junior Subordinate Debt [Member]

7.60%

Minimum [Member] | Senior Notes [Member]

2.50%

1.55%

$ 7,608,000,000

5,853,000,000

Fair value adjustment of consolidated subsidiary

(8,000,000)

(4,000,000)

220,000,000

275,000,000

(570,000,000)

(60,000,000)

7,193,000,000

6,017,000,000

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

(57,000,000)

(47,000,000)

$ 1,150,000,000

1,150,000,000

Exelon Corporate [Member] | Senior Notes [Member]

6.50%

Exelon Corporate [Member] | contract Payments Junior Subordinate Debt [Member]

Unsecured Long Term Debt

^[2]

$ 6,439,000,000

4,639,000,000

$ 19,000,000

$ 64,000,000

Exelon Corporate [Member] | Maximum [Member] | Senior Notes [Member]

2.50%

Exelon Corporate [Member] | Minimum [Member] | Senior Notes [Member]

^[2]

7.60%

^[2]

1.60%

[1]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjY2ZTAyZGU0MjJhODQwMGQ4YTI0ZmVhYjg5OGIyNGRifFRleHRTZWxlY3Rpb246QjFDN0Q4OTA0OTQyMUZCQTgxMDE5RjkyNUQyN0VERjAM}

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Debt Maturities (Details)
$ in Millions

Dec. 31, 2016

USD ($)

$ 2,430

1,742

1,060

3,331

2,400

22,996

^[1]

33,959

570

1,450

300

5,288

$ 7,608

[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, 2016

Dec. 31, 2015

Dec. 31, 2014

$ (24)

$ (7)

$ 0

706

Interest income from affiliates, net

Cash contributions received from affiliates

1,521

2,461

1,779

1,912

3,209

1,370

1,478

34,869

26,119

922

933

Exelon Corporate [Member] | Business Services Company [Member]

706

^[1]

^[1]

^[1]

226

^[1]

194

191

Exelon Corporate [Member] | PHI Service Co Affiliate [Member]

361

Exelon Corporate [Member] | Potomac Capital Investment Affiliate [Member]

Exelon Corporate [Member] | Exelon Energy Delivery Company LLC [Member]

^[2]

^[3]

1,041

1,079

958

Exelon Corporate [Member] | Exelon Ventures Company LLC [Member]

^[3]

23,003

14,163

Exelon Corporate [Member] | UII LLC [Member]

^[2]

926

(9)

(6)

Exelon Corporate [Member] | Exelon Transmission Company LLC [Member]

102

(13)

(8)

(7)

Exelon Corporate [Member] | ExelonEnterprise [Member]

(1)

Exelon Corporate [Member] | Exelon Consolidations [Member]

Exelon Corporate [Member] | Exelon Generation Co L L C [Member]

(6)

Interest income from affiliates, net

496

1,371

$ (91)

1,252

11,488

11,637

Exelon Corporate [Member] | Commonwealth Edison Co [Member]

922

933

Exelon Corporate [Member] | PECO Energy Co [Member]

345

188

Exelon Corporate [Member] | Baltimore Gas and Electric Company [Member]

Exelon Corporate [Member] | VEBA [Member]

Allowance for Uncollectible Accounts [Member]

$ (5)

$ 7

[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 Ventures Company, LLC primarily consisted of Generation
[3]	Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.

Schedule II - Valuation and Qualifying Accounts Schedule II - Valuation and Qualifying Accounts (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Mar. 23, 2016

Dec. 31, 2016

Dec. 31, 2015

Dec. 31, 2014

Movement in Valuation Allowances and Reserves [Roll Forward]

^[1]

$ 284

$ 311

$ 272

^[1]

162

113

175

^[1],[2]

^[3]

^[1],[4]

211

167

205

Deferred Tax Valuation Allowance [Member]

^[1]

$ 334

334

284

311

Movement in Valuation Allowances and Reserves [Roll Forward]

^[3]

(27)

Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

105

^[3]

Exelon Generation Co L L C [Member] | Allowance for Uncollectible Accounts [Member]

113

105

Movement in Valuation Allowances and Reserves [Roll Forward]

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]

102

(1)

Commonwealth Edison Co [Member] | Allowance for Uncollectible Accounts [Member]

106

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]

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

Movement in Valuation Allowances and Reserves [Roll Forward]

PECO Energy Co [Member] | Allowance for Doubtful Accounts, Noncurrent [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Baltimore Gas and Electric Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[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]

Movement in Valuation Allowances and Reserves [Roll Forward]

Movement in Valuation Allowances and Reserves [Roll Forward]

Potomac Electric Power Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[12]

^[13]

Potomac Electric Power Company [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Potomac Electric Power Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Movement in Valuation Allowances and Reserves [Roll Forward]

Delmarva Power and Light Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[14]

^[15]

Delmarva Power and Light Company [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Delmarva Power and Light Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Atlantic City Electric Company [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[16]

^[17]

Atlantic City Electric Company [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Atlantic City Electric Company [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Successor [Member] | Pepco Holdings LLC [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[18]

^[19]

Successor [Member] | Pepco Holdings LLC [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

(53)

Successor [Member] | Pepco Holdings LLC [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

(1)

Predecessor [Member] | Pepco Holdings LLC [Member] | Allowance for Uncollectible Accounts [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

^[18]

^[19]

Predecessor [Member] | Pepco Holdings LLC [Member] | Deferred Tax Valuation Allowance [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

Predecessor [Member] | Pepco Holdings LLC [Member] | Reserve for Obsolete Materials [Member]

Movement in Valuation Allowances and Reserves [Roll Forward]

$ 0

Impairment of Long-Lived Assets Held-for-use

$ 0

[1]	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $23 million, $8 million, and $8 million for the years ended December 31, 2016, 2015, and 2014, respectively.
[2]	Includes charges for late payments and non-service receivables.
[3]	Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger
[4]	Write-off of individual accounts receivable.
[5]	Primarily charges for late payments and non-service receivables.
[6]	Write-off of individual accounts receivable.
[7]	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $23 million, $8 million, and $8 million for the years ended December 31, 2016, 2015, and 2014, respectively.
[8]	Primarily charges for late payments.
[9]	Write-off of individual accounts receivable.
[10]	Primarily charges for late payments.
[11]	Write-off of individual accounts receivable.
[12]	Primarily charges for late payments.
[13]	Write-off of individual accounts receivable.
[14]	Primarily charges for late payments.
[15]	Write-off of individual accounts receivable.
[16]	Primarily charges for late payments.
[17]	Write-off of individual accounts receivable.
[18]	Primarily charges for late payments.
[19]	Write-off of individual accounts receivable.

Label

Element

Value

Predecessor [Member]

us-gaap_ImpairmentOfLongLivedAssetsHeldForUse

$ 0

Successor [Member]

Impairment of Long-Lived Assets Held-for-use

us-gaap_ImpairmentOfLongLivedAssetsHeldForUse

PECO Energy Co [Member] | DSP Program costs [Member]

PECO Energy Co [Member] | Over-Recovered Electric Transmission Cost [Member]

us-gaap_RegulatoryLiabilities

35,000,000

PECO Energy Co [Member] | OverRecoveredNaturalGasSupply [Member]

us-gaap_RegulatoryLiabilities

3,000,000

PECO Energy Co [Member] | Minimum [Member] | Energy Efficiency And Demand Response Programs [Member]

us-gaap_RegulatoryLiabilities

$ 22,000,000

Cumulative Consumption Reduction Targets

exc_CumulativeConsumptionReductionTargets

1,962,659

Baltimore Gas and Electric Company [Member] | Stride Program [Member]

Captial and OM estimates current year

exc_CapitalandOMestimatescurrentyear

$ 131,000,000

us-gaap_RegulatoryLiabilities

2,000,000

Proceeds from Stock Plans

us-gaap_ProceedsFromStockPlans

2,000,000

Unrealized Gain (Loss) on Derivatives

us-gaap_UnrealizedGainLossOnDerivatives

(18,000,000)

Cash and Cash Equivalents, Period Increase (Decrease)

us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease

293,000,000

Proceeds from (Repayments of) Short-term Debt

us-gaap_ProceedsFromRepaymentsOfShortTermDebt

(121,000,000)

Increase (Decrease) in Inventories

us-gaap_IncreaseDecreaseInInventories

4,000,000

Proceeds from (Payments for) Other Financing Activities

us-gaap_ProceedsFromPaymentsForOtherFinancingActivities

2,000,000

Other Noncash Income (Expense)

us-gaap_OtherNoncashIncomeExpense

(46,000,000)

Net Cash Provided by (Used in) Investing Activities

us-gaap_NetCashProvidedByUsedInInvestingActivities

(343,000,000)

Repayments of Debt, Maturing in More than Three Months

us-gaap_RepaymentsOfDebtMaturingInMoreThanThreeMonths

Change Receivables Payables From Affiliates

exc_ChangeReceivablesPayablesFromAffiliates

Increase (Decrease) in Other Operating Assets and Liabilities, Net

us-gaap_RepaymentsOfLongTermDebt

11,000,000

us-gaap_IncreaseDecreaseInOtherOperatingCapitalNet

9,000,000

Increase (Decrease) in Receivables

us-gaap_IncreaseDecreaseInReceivables

28,000,000

Proceeds from Issuance of Long-term Debt

us-gaap_ProceedsFromIssuanceOfLongTermDebt

Increase (Decrease) Cash Collateral from Counterparties

us-gaap_IncreaseDecreaseCashCollateralFromCounterparties

1,000,000

Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest

us-gaap_IncomeLossFromDiscontinuedOperationsNetOfTax

Proceeds from Sale of Property Held-for-sale

us-gaap_ProceedsFromSaleOfPropertyHeldForSale

Deferred Income Taxes and Tax Credits

us-gaap_DeferredIncomeTaxesAndTaxCredits

19,000,000

Increase (Decrease) in Income Taxes Payable

us-gaap_IncreaseDecreaseInAccruedIncomeTaxesPayable

12,000,000

Net Cash Provided by (Used in) Operating Activities

us-gaap_NetCashProvidedByUsedInOperatingActivities

264,000,000

Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less

us-gaap_ProceedsFromRepaymentsOfShortTermDebtMaturingInThreeMonthsOrLess

500,000,000

Payments to Acquire Marketable Securities

us-gaap_PaymentsToAcquireMarketableSecurities

68,000,000

Payments for (Proceeds from) Other Investing Activities

us-gaap_PaymentsForProceedsFromOtherInvestingActivities

5,000,000

Increase (Decrease) in Restricted Cash

us-gaap_IncreaseDecreaseInRestrictedCash

(3,000,000)

Proceeds from Issuance of Preferred Stock and Preference Stock

us-gaap_ProceedsFromIssuanceOfPreferredStockAndPreferenceStock

Net Cash Provided by (Used in) Financing Activities

us-gaap_NetCashProvidedByUsedInFinancingActivities

372,000,000

Increase (Decrease) in Accounts Payable and Accrued Liabilities

us-gaap_IncreaseDecreaseInAccountsPayableAndAccruedLiabilities

42,000,000

Increase (Decrease) in Due to Affiliates

us-gaap_IncreaseDecreaseInDueToAffiliates

Proceeds from Stock Plans

us-gaap_ProceedsFromStockPlans

Unrealized Gain (Loss) on Derivatives

us-gaap_UnrealizedGainLossOnDerivatives

Cash and Cash Equivalents, Period Increase (Decrease)

us-gaap_CashAndCashEquivalentsPeriodIncreaseDecrease

(149,000,000)

Proceeds from (Repayments of) Short-term Debt

us-gaap_ProceedsFromRepaymentsOfShortTermDebt

(515,000,000)

Increase (Decrease) in Inventories

us-gaap_IncreaseDecreaseInInventories

(3,000,000)

Proceeds from (Payments for) Other Financing Activities

us-gaap_ProceedsFromPaymentsForOtherFinancingActivities

(5,000,000)

Other Noncash Income (Expense)

us-gaap_OtherNoncashIncomeExpense

(514,000,000)

Net Cash Provided by (Used in) Investing Activities

us-gaap_NetCashProvidedByUsedInInvestingActivities

(1,030,000,000)

Repayments of Debt, Maturing in More than Three Months

us-gaap_RepaymentsOfDebtMaturingInMoreThanThreeMonths

300,000,000

Change Receivables Payables From Affiliates

exc_ChangeReceivablesPayablesFromAffiliates

42,000,000

Increase (Decrease) in Other Operating Assets and Liabilities, Net

us-gaap_RepaymentsOfLongTermDebt

338,000,000

us-gaap_IncreaseDecreaseInOtherOperatingCapitalNet

311,000,000

Increase (Decrease) in Receivables

us-gaap_IncreaseDecreaseInReceivables

21,000,000

Proceeds from Issuance of Long-term Debt

us-gaap_ProceedsFromIssuanceOfLongTermDebt

179,000,000

Increase (Decrease) Cash Collateral from Counterparties

us-gaap_IncreaseDecreaseCashCollateralFromCounterparties

Income (Loss) from Discontinued Operations, Net of Tax, Including Portion Attributable to Noncontrolling Interest

us-gaap_IncomeLossFromDiscontinuedOperationsNetOfTax

Proceeds from Sale of Property Held-for-sale

us-gaap_ProceedsFromSaleOfPropertyHeldForSale

24,000,000

Deferred Income Taxes and Tax Credits

us-gaap_DeferredIncomeTaxesAndTaxCredits

295,000,000

Increase (Decrease) in Income Taxes Payable

us-gaap_IncreaseDecreaseInAccruedIncomeTaxesPayable

(22,000,000)

Net Cash Provided by (Used in) Operating Activities

us-gaap_NetCashProvidedByUsedInOperatingActivities

888,000,000

Proceeds from (Repayments of) Short-term Debt, Maturing in Three Months or Less

us-gaap_ProceedsFromRepaymentsOfShortTermDebtMaturingInThreeMonthsOrLess

Payments to Acquire Marketable Securities

us-gaap_PaymentsToAcquireMarketableSecurities

Payments for (Proceeds from) Other Investing Activities

us-gaap_PaymentsForProceedsFromOtherInvestingActivities

9,000,000

Increase (Decrease) in Restricted Cash

us-gaap_IncreaseDecreaseInRestrictedCash

37,000,000

Proceeds from Issuance of Preferred Stock and Preference Stock

us-gaap_ProceedsFromIssuanceOfPreferredStockAndPreferenceStock

Net Cash Provided by (Used in) Financing Activities

us-gaap_NetCashProvidedByUsedInFinancingActivities

(7,000,000)

Increase (Decrease) in Accounts Payable and Accrued Liabilities

us-gaap_IncreaseDecreaseInAccountsPayableAndAccruedLiabilities

19,000,000

Increase (Decrease) in Due to Affiliates

us-gaap_IncreaseDecreaseInDueToAffiliates

(6,000,000)

Retained Earnings [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

10,358,000,000

Retained Earnings [Member] | Baltimore Gas and Electric Company [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

1,005,000,000

Retained Earnings [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_MembersEquity

Treasury Stock [Member]

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

(2,327,000,000)

Common Stock [Member]

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

us-gaap_EmployeeServiceShareBasedCompensationTaxBenefitRealizedFromExerciseOfStockOptions

(18,000,000)

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

16,741,000,000

Common Stock [Member] | Baltimore Gas and Electric Company [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

1,360,000,000

Common Stock Including Additional Paid in Capital [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Business Combination, Contingent Consideration, Liability, Noncurrent

us-gaap_MembersEquity

7,200,000,000

^[1]

us-gaap_BusinessCombinationContingentConsiderationLiabilityNoncurrent

53,000,000

Noncontrolling Interest [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

15,000,000

Noncontrolling Interest [Member] | Exelon Generation Co L L C [Member]

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest

1,774,000,000

Noncontrolling Interest, Increase from Sale of Parent Equity Interest

us-gaap_NoncontrollingInterestIncreaseFromSaleOfParentEquityInterest

2,000,000

AOCI Attributable to Parent [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

(2,040,000,000)

AOCI Attributable to Parent [Member] | Exelon Generation Co L L C [Member]

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest

(54,000,000)

AOCI Attributable to Parent [Member] | Pepco Holdings LLC [Member] | Successor [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

us-gaap_MembersEquity

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

193,000,000

Preference Stock Not Subject To Mandatory Redemption [Member] | Baltimore Gas and Electric Company [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

190,000,000

Undistributed Earnings [Member] | Exelon Generation Co L L C [Member]

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest

2,275,000,000

Membership Interest [Member] | Exelon Generation Co L L C [Member]

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_LimitedLiabilityCompanyLlcMembersEquityIncludingPortionAttributableToNoncontrollingInterest

9,261,000,000

Membership Interest [Member] | Baltimore Gas and Electric Company [Member]

Stockholders' Equity, Including Portion Attributable to Noncontrolling Interest

us-gaap_StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest

2,365,000,000

Pepco Holdings LLC [Member] | Commitments [Member] | Successor [Member]