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^[1]

$ (26)

Electrical Generation Revenue

$ 4,535

$ 4,564

$ 12,243

14,278

137

116

781

904

Regulated Operating Revenue

4,467

2,837

11,243

8,468

4,330

2,721

10,461

7,564

9,002

7,401

23,486

22,746

Purchased power

2,584

2,515

6,599

7,789

1,170

776

2,863

2,421

2,338

1,996

7,677

6,119

1,195

606

2,821

1,818

449

310

1,168

908

Gain (Loss) on Sale of Assets and Asset Impairment Charges

7,736

6,203

21,128

19,055

1,267

1,200

2,399

3,701

(506)

(243)

(1,148)

(724)

(10)

(31)

120

(244)

377

(179)

(396)

(497)

(802)

(934)

871

703

1,597

2,767

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

340

115

625

805

(5)

(1)

(16)

(3)

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

526

587

956

1,959

(42)

Net income attributable to common shareholders

490

629

930

1,959

Other comprehensive income (loss), net of income taxes

Prior service benefit reclassified to periodic benefit cost

(12)

(11)

(35)

Actuarial loss reclassified to periodic benefit cost

140

165

Other Comprehensive Income Pension And Non Pension Postretirement Benefit Plan Valuation Adjustment Net Of Tax

Unrealized gain (loss) on cash flow hedges

(3)

(4)

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

(4)

(10)

Unrealized loss on marketable securities

(1)

Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax

(8)

(17)

^[2]

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

562

619

1,052

2,047

(42)

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

$ 531

$ 661

$ 1,031

$ 2,047

Average shares of common stock outstanding:

Weighted average common shares outstanding — basic

925

913

924

879

Average common shares outstanding — diluted

927

915

926

883

Earnings per average common share:

Earnings per share - basic (in usd per share)

$ 0.53

$ 0.69

$ 1.01

$ 2.23

Earnings per average common share - diluted

Earnings per share - diluted (in usd per share)

0.53

0.69

1.00

2.22

Dividends per common share (in usd per share)

$ 0.318

$ 0.31

$ 0.946

$ 0.93

$ 48

$ 322

$ 435

738

691

1,966

1,950

788

740

2,293

2,386

Utilities Operating Expense, Purchased Power

171

207

466

584

233

171

110

198

168

166

501

529

103

201

198

126

125

Gain (Loss) on Disposition of Other Assets

584

586

1,740

1,885

204

154

553

502

(27)

(25)

(83)

(75)

(3)

(9)

(28)

(27)

(86)

(81)

176

127

467

421

121

122

Other comprehensive income (loss), net of income taxes

122

346

299

^[2]

122

346

299

Electrical Generation Revenue

4,533

4,562

12,234

14,270

502

206

1,129

571

5,035

4,768

13,363

14,841

2,584

2,516

6,599

7,789

1,189

1,088

3,855

3,399

147

153

478

461

632

264

1,329

774

136

123

380

369

Gain (Loss) on Sale of Assets and Asset Impairment Charges

4,693

4,147

12,651

12,803

342

622

743

2,045

(67)

(56)

(243)

(236)

(10)

(12)

(30)

(33)

185

(257)

395

(193)

108

(325)

122

(462)

450

297

865

1,583

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

173

(36)

293

371

(6)

(1)

(16)

(4)

Net income (loss) attributable to noncontrolling interests

271

332

556

1,208

(45)

(10)

Net income attributable to membership interest

236

377

538

1,218

Other comprehensive income (loss), net of income taxes

Unrealized gain (loss) on cash flow hedges

(3)

(7)

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

(4)

Unrealized loss on marketable securities

(2)

Other Comprehensive Income (Loss), Foreign Currency Transaction and Translation Gain (Loss) Arising During Period, Net of Tax

(8)

(17)

(13)

(24)

^[2]

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

275

319

558

1,184

245

364

545

1,194

Operating revenues

1,493

1,375

4,019

3,706

1,497

1,376

4,031

3,709

435

388

1,104

974

327

353

950

1,023

163

143

196

176

574

528

222

225

Gain (Loss) on Sale of Assets and Asset Impairment Charges

1,109

1,049

3,050

2,910

389

327

987

799

(194)

(80)

(364)

(238)

(3)

(10)

(80)

(72)

(277)

(79)

(446)

(234)

112

248

541

565

244

226

Other comprehensive income (loss), net of income taxes

149

297

339

149

297

339

412

468

733

656

1,993

1,910

812

725

2,421

2,388

Utilities Operating Expense, Purchased Power

164

159

399

497

182

141

486

373

109

167

150

138

494

412

101

307

271

172

169

Gain (Loss) on Sale of Assets and Asset Impairment Charges

697

616

2,061

1,976

115

110

360

413

(24)

(21)

(64)

(62)

(4)

(12)

(11)

(23)

(21)

(60)

300

353

109

141

Preferred security dividends and redemption

191

212

Net income attributable to common shareholders

183

202

Other comprehensive income (loss), net of income taxes

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

191

212

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

183

202

$ 57

129

1,096

1,317

3,680

1,153

1,336

3,809

471

570

1,575

294

287

875

152

166

474

105

120

349

1,048

1,152

3,344

105

184

465

(65)

(71)

(211)

(4)

(69)

(44)

(163)

140

302

105

Other comprehensive income (loss), net of income taxes

197

Actuarial loss reclassified to periodic benefit cost

Unrealized gain (loss) on cash flow hedges

$ 20

202

$ 46

1,366

2,485

1,394

2,565

370

658

207

362

200

870

182

355

124

248

1,115

2,561

279

(64)

(135)

(45)

(104)

234

(100)

(9)

Other comprehensive income (loss), net of income taxes

166

(91)

Actuarial loss reclassified to periodic benefit cost

166

$ (91)

634

591

1,692

1,637

635

592

1,695

1,641

200

340

573

129

223

100

110

488

324

221

191

105

100

287

289

503

477

1,579

1,380

132

115

124

261

(30)

(31)

(98)

(92)

(18)

(23)

(70)

(71)

114

190

Other comprehensive income (loss), net of income taxes

128

128

102

129

312

294

866

871

331

314

974

1,004

Utilities Operating Expense, Purchased Power

143

297

435

110

327

233

120

113

263

282

948

886

118

(12)

(37)

(9)

(8)

(28)

(29)

Other comprehensive income (loss), net of income taxes

(16)

(16)

420

385

979

1,001

421

386

982

1,003

206

214

491

552

336

205

130

135

338

335

1,002

899

(19)

104

(15)

(16)

(47)

(48)

(13)

(15)

(39)

(44)

(58)

(8)

Other comprehensive income (loss), net of income taxes

(50)

$ 47

$ 22

$ (50)

$ 37

[1]

In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments were probable not to occur. As a result, $26 million of anticipated payments were reclassified from AOCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.

[2]

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

Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Cash flows from operating activities
Net income	$ 956	$ 1,959
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	4,009	2,930
Impairment of long-lived assets and losses on regulatory assets	274	25
Gain on sales of assets	(41)	(10)
Deferred income taxes and amortization of investment tax credits	623	241
Net fair value changes related to derivatives	100	(363)
Gain (Loss) on Investments	243	(221)
Other non-cash operating activities	1,224	856
Changes in assets and liabilities:
Inventories	21	65
Accounts receivable	(296)	175
Accounts payable and accrued expenses	296	(115)
Option premiums (paid) received, net	(24)	27
Increase (Decrease) Cash Collateral from Counterparties	757	115
Income taxes	527	300
Pension and non-pension postretirement benefit contributions	(283)	(430)
Other assets and liabilities	(537)	(322)
Net cash flows provided by operating activities	7,363	5,674
Cash flows from investing activities
Capital expenditures	(6,368)	(5,443)
Proceeds from nuclear decommissioning trust fund sales	7,914	4,551
Investment in nuclear decommissioning trust funds	(8,093)	(4,737)
Acquisition of businesses, net of cash acquired	(6,896)	(28)
Proceeds from Sale of Property Held-for-sale	49	145
Proceeds from termination of direct financing lease investment	360	0
Change in restricted cash	(75)	(70)
Other investing activities	(110)	(107)
Net cash flows used in investing activities	(13,219)	(5,689)
Cash flows from financing activities
Changes in short-term borrowings	(1,014)	230
Proceeds from short-term borrowings with maturities greater than 90 days	195	0
Issuance of long-term debt	4,488	5,909
Proceeds from (Repayments of) Other Long-term Debt	(30)	0
Retirement of long-term debt	(944)	(1,745)
Dividends paid on common stock	(873)	(819)
Proceeds from employee stock plans	36	24
Other financing activities	35	(65)
Repayments of Short-term Debt, Maturing in More than Three Months	(452)	0
Payments for Repurchase of Redeemable Preferred Stock	(190)	0
Net cash flows provided by financing activities	1,251	5,402
(Decrease) Increase in cash and cash equivalents	(4,605)	5,387
Cash and cash equivalents at beginning of period	6,502	1,878
Cash and cash equivalents at end of period	1,897	7,265
Proceeds from Issuance of Common Stock	0	1,868
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	556	1,208
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	2,516	1,887
Impairment of long-lived assets and losses on regulatory assets	209	1
Gain on sales of assets	(31)	(7)
Deferred income taxes and amortization of investment tax credits	(133)	21
Net fair value changes related to derivatives	112	(252)
Gain (Loss) on Investments	243	(221)
Other non-cash operating activities	129	227
Changes in assets and liabilities:
Inventories	18	69
Accounts receivable	26	252
Change Receivables Payables From Affiliates	(56)	16
Accounts payable and accrued expenses	9	(146)
Option premiums (paid) received, net	(24)	27
Increase (Decrease) Cash Collateral from Counterparties	759	186
Income taxes	202	(70)
Pension and non-pension postretirement benefit contributions	(122)	(189)
Other assets and liabilities	(204)	(245)
Net cash flows provided by operating activities	3,723	3,206
Cash flows from investing activities
Capital expenditures	(2,651)	(2,774)
Proceeds from nuclear decommissioning trust fund sales	7,914	4,551
Investment in nuclear decommissioning trust funds	(8,093)	(4,737)
Acquisition of businesses, net of cash acquired	(255)	(28)
Proceeds from Sale of Property Held-for-sale	30	144
Change in restricted cash	(39)	(84)
Other investing activities	(184)	(92)
Net cash flows used in investing activities	(3,278)	(3,020)
Cash flows from financing activities
Repayments of Debt, Maturing in More than Three Months	(152)	0
Issuance of long-term debt	338	1,307
Proceeds from Debt, Maturing in More than Three Months	195	0
Retirement of long-term debt	(164)	(64)
Repayments of Related Party Debt	0	(550)
Other financing activities	92	(6)
Distribution to member	(167)	(2,368)
Proceeds from Contributions from Affiliates	142	55
Change in Exelon intercompany money pool borrowings	(785)	1,205
Net cash flows provided by financing activities	(501)	(421)
(Decrease) Increase in cash and cash equivalents	(56)	(235)
Cash and cash equivalents at beginning of period	431	780
Cash and cash equivalents at end of period	375	545
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	297	339
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	574	528
Gain on sales of assets	(6)	0
Deferred income taxes and amortization of investment tax credits	398	107
Other non-cash operating activities	122	312
Changes in assets and liabilities:
Inventories	4	(23)
Accounts receivable	(55)	(114)
Change Receivables Payables From Affiliates	(9)	(23)
Accounts payable and accrued expenses	145	(18)
Increase (Decrease) Cash Collateral from Counterparties	(2)	(43)
Income taxes	206	389
Pension and non-pension postretirement benefit contributions	(35)	(142)
Other assets and liabilities	104	34
Net cash flows provided by operating activities	1,749	1,346
Cash flows from investing activities
Capital expenditures	(1,950)	(1,670)
Change in restricted cash	0	2
Other investing activities	31	22
Net cash flows used in investing activities	(1,919)	(1,646)
Cash flows from financing activities
Changes in short-term borrowings	(284)	300
Issuance of long-term debt	1,200	400
Retirement of long-term debt	(665)	(260)
Dividends paid on common stock	(275)	(226)
Other financing activities	(17)	(4)
Contributions from parent	188	75
Net cash flows provided by financing activities	147	285
(Decrease) Increase in cash and cash equivalents	(23)	(15)
Cash and cash equivalents at beginning of period	67	66
Cash and cash equivalents at end of period	44	51
PECO Energy Co [Member]
Cash flows from operating activities
Net income	346	299
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	201	198
Deferred income taxes and amortization of investment tax credits	69	11
Other non-cash operating activities	49	69
Changes in assets and liabilities:
Inventories	5	8
Accounts receivable	(50)	(15)
Change Receivables Payables From Affiliates	9	0
Accounts payable and accrued expenses	(12)	(19)
Income taxes	43	69
Pension and non-pension postretirement benefit contributions	(29)	(37)
Other assets and liabilities	(49)	(16)
Net cash flows provided by operating activities	582	567
Cash flows from investing activities
Capital expenditures	(448)	(435)
Change in restricted cash	0	(1)
Other investing activities	10	11
Net cash flows used in investing activities	(438)	(425)
Cash flows from financing activities
Issuance of long-term debt	300	0
Proceeds from (Repayments of) Other Long-term Debt	(30)	0
Dividends paid on common stock	(208)	(209)
Other financing activities	(3)	(2)
Contributions from parent	18	16
Change in Exelon intercompany money pool borrowings		55
Net cash flows provided by financing activities	77	(140)
(Decrease) Increase in cash and cash equivalents	221	2
Cash and cash equivalents at beginning of period	295	30
Cash and cash equivalents at end of period	516	32
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	191	212
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	307	271
Impairment of long-lived assets and losses on regulatory assets	52
Gain on sales of assets		(1)
Deferred income taxes and amortization of investment tax credits	54	79
Other non-cash operating activities	109	111
Changes in assets and liabilities:
Inventories	(7)	10
Accounts receivable	(50)	62
Change Receivables Payables From Affiliates	(10)	(8)
Accounts payable and accrued expenses	43	34
Increase (Decrease) Cash Collateral from Counterparties	0	(27)
Income taxes	19	(6)
Pension and non-pension postretirement benefit contributions	(46)	(14)
Other assets and liabilities	(2)	(28)
Net cash flows provided by operating activities	660	696
Cash flows from investing activities
Capital expenditures	(611)	(506)
Change in restricted cash	(22)	2
Other investing activities	19	13
Net cash flows used in investing activities	(614)	(491)
Cash flows from financing activities
Changes in short-term borrowings	(210)	(70)
Issuance of long-term debt	850	0
Proceeds from (Repayments of) Other Long-term Debt	(190)
Retirement of long-term debt	(39)	(37)
Dividends paid on common stock	(134)	(116)
Other financing activities	(11)	(15)
Contributions from parent	28	6
Dividends paid on preference stock	(8)	(10)
Net cash flows provided by financing activities	286	(242)
(Decrease) Increase in cash and cash equivalents	332	(37)
Cash and cash equivalents at beginning of period	9	64
Cash and cash equivalents at end of period	341	27
Pepco Holdings LLC [Member] \| Successor [Member]
Cash flows from financing activities
Cash and cash equivalents at end of period	299
Pepco Holdings LLC [Member] \| Predecessor [Member]
Cash flows from operating activities
Net income		197
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization		474
Deferred income taxes and amortization of investment tax credits		107
Net fair value changes related to derivatives		(15)
Other non-cash operating activities		143
Changes in assets and liabilities:
Inventories		(5)
Accounts receivable		(211)
Change Receivables Payables From Affiliates		0
Accounts payable and accrued expenses		23
Increase (Decrease) Cash Collateral from Counterparties		0
Income taxes		12
Pension and non-pension postretirement benefit contributions		(12)
Other assets and liabilities		(112)
Net cash flows provided by operating activities		601
Cash flows from investing activities
Capital expenditures		(855)
Purchases of investments		0
Change in restricted cash		6
Other investing activities		14
Net cash flows used in investing activities		(835)
Cash flows from financing activities
Changes in short-term borrowings		99
Proceeds from short-term borrowings with maturities greater than 90 days		300
Issuance of long-term debt		408
Retirement of long-term debt		(163)
Dividends paid on common stock		(206)
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and employee-related compensation		23
Distribution to member		0
Other financing activities		(24)
Contributions from parent		0
Change in Exelon intercompany money pool borrowings		0
Issuance of preferred stock		54
Net cash flows provided by financing activities		491
(Decrease) Increase in cash and cash equivalents		257
Cash and cash equivalents at beginning of period	26	15
Cash and cash equivalents at end of period		272
Potomac Electric Power Company [Member]
Cash flows from operating activities
Net income	20	128
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	221	191
Deferred income taxes and amortization of investment tax credits	96	70
Other non-cash operating activities	168	42
Changes in assets and liabilities:
Inventories	3	(5)
Accounts receivable	(105)	(113)
Change Receivables Payables From Affiliates	44	2
Accounts payable and accrued expenses	7	(1)
Income taxes	139	0
Pension and non-pension postretirement benefit contributions	(6)	(7)
Other assets and liabilities	(83)	(94)
Net cash flows provided by operating activities	504	213
Cash flows from investing activities
Capital expenditures	(392)	(374)
Proceeds from Sale of Property Held-for-sale	12
Purchases of investments	(32)	0
Change in restricted cash	(31)	3
Other investing activities	8	14
Net cash flows used in investing activities	(435)	(357)
Cash flows from financing activities
Changes in short-term borrowings	(64)	(56)
Issuance of long-term debt	2	208
Retirement of long-term debt	(5)	(17)
Dividends paid on common stock	(92)	(91)
Other financing activities	0	(8)
Contributions from parent	187	112
Net cash flows provided by financing activities	28	148
(Decrease) Increase in cash and cash equivalents	97	4
Cash and cash equivalents at beginning of period	5	6
Cash and cash equivalents at end of period	102	10
Potomac Electric Power Company [Member] \| Successor [Member]
Cash flows from investing activities
Acquisition of businesses, net of cash acquired	(33)
Delmarva Power and Light Company [Member]
Cash flows from operating activities
Net income	(16)	55
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	120	113
Deferred income taxes and amortization of investment tax credits	69	40
Other non-cash operating activities	99	31
Changes in assets and liabilities:
Inventories	0	4
Accounts receivable	8	(33)
Change Receivables Payables From Affiliates	12	5
Accounts payable and accrued expenses	(8)	(5)
Increase (Decrease) Cash Collateral from Counterparties	1	0
Income taxes	52	0
Other assets and liabilities	(70)	(22)
Net cash flows provided by operating activities	267	188
Cash flows from investing activities
Capital expenditures	(260)	(246)
Proceeds from Sale of Property Held-for-sale	4
Change in restricted cash	0	5
Other investing activities	2	1
Net cash flows used in investing activities	(254)	(240)
Cash flows from financing activities
Changes in short-term borrowings	(88)	(40)
Issuance of long-term debt	0	200
Retirement of long-term debt	0	(100)
Dividends paid on common stock	(39)	(80)
Other financing activities	0	(2)
Contributions from parent	113	75
Net cash flows provided by financing activities	(14)	53
(Decrease) Increase in cash and cash equivalents	(1)	1
Cash and cash equivalents at beginning of period	5	4
Cash and cash equivalents at end of period	4	5
Atlantic City Electric Company [Member]
Cash flows from operating activities
Net income	(50)	37
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	130	135
Deferred income taxes and amortization of investment tax credits	14	13
Other non-cash operating activities	138	27
Changes in assets and liabilities:
Inventories	(1)	(1)
Accounts receivable	(32)	(87)
Change Receivables Payables From Affiliates	9	1
Accounts payable and accrued expenses	10	35
Income taxes	184	10
Other assets and liabilities	(87)	8
Net cash flows provided by operating activities	315	178
Cash flows from investing activities
Capital expenditures	(227)	(212)
Proceeds from Sale of Property Held-for-sale	2
Change in restricted cash	(4)	(6)
Other investing activities	2	2
Net cash flows used in investing activities	(227)	(216)
Cash flows from financing activities
Changes in short-term borrowings	(5)	98
Retirement of long-term debt	(35)	(46)
Dividends paid on common stock	(24)	(12)
Other financing activities	(1)	0
Contributions from parent	139	0
Net cash flows provided by financing activities	74	40
(Decrease) Increase in cash and cash equivalents	162	2
Cash and cash equivalents at beginning of period	3	2
Cash and cash equivalents at end of period	$ 165	$ 4

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

Sep. 30, 2016

Dec. 31, 2015

Sep. 30, 2015

Dec. 31, 2014

$ 1,897

$ 6,502

$ 7,265

$ 1,878

321

205

4,061

3,187

1,013

912

754

1,365

126

374

462

1,188

1,104

1,410

759

1,064

752

12,208

15,334

71,214

57,439

10,022

6,065

11,076

10,342

592

639

6,672

2,672

669

758

473

484

135

206

1,474

1,445

31,113

22,611

114,535

95,384

567

533

2,512

1,500

3,044

2,883

3,236

2,376

Mark-to-market derivative liabilities (current liabilities)

548

369

222

205

452

100

Energy Marketing Accounts Payable

1,068

842

356

302

Accounts Payable and Accrued Liabilities, Current

145

12,158

9,118

32,330

23,645

642

641

18,115

13,776

9,348

8,585

3,765

3,385

Spent nuclear fuel obligation

1,921

1,618

1,023

1,021

Mark-to-market derivative liabilities (noncurrent liabilities)

4,437

4,201

422

374

Payable for Zion Station decommissioning

927

117

1,928

1,491

41,919

34,658

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[1]

87,049

68,062

Stockholders' Equity Attributable to Parent [Abstract]

Treasury stock, at cost (35 shares at September 30, 2016 and December 31, 2015, respectively)

18,756

18,676

(2,327)

12,121

12,068

^[2]

(2,523)

(2,624)

(2,596)

(2,684)

Preferred Stock, Value, Issued

26,027

25,793

193

Noncontrolling interests

1,433

1,308

27,460

27,294

114,535

95,384

12,121

12,068

Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities

^[2]

(2,523)

(2,624)

(2,596)

(2,684)

^[3]

489

147

Variable Interest Entity, Primary Beneficiary [Member]

160

164

101

100

264

219

140

192

181

866

882

5,139

5,160

2,173

2,036

257

8,514

8,268

191

111

201

216

Mark-to-market derivative liabilities (current liabilities)

102

115

566

472

661

666

^[4]

2,070

1,999

106

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

3,438

3,264

8,514

8,268

3,438

3,264

375

431

545

780

162

123

2,318

2,095

301

360

754

1,365

Receivables from affiliates

126

170

292

384

849

880

788

535

6,135

6,342

26,374

25,843

11,076

10,342

381

210

630

733

Deferred Tax Assets, Net, Noncurrent

472

484

135

206

692

627

1,621

1,689

15,059

14,344

47,568

46,529

254

1,465

1,583

942

935

Other Short-term Borrowings

118

104

461

1,252

Mark-to-market derivative liabilities (current liabilities)

203

182

100

Energy Marketing Accounts Payable

392

356

356

302

4,307

4,933

Long-term debt to affiliate

8,077

7,936

924

933

5,684

5,845

9,160

8,431

Spent nuclear fuel obligation

932

924

1,023

1,021

Due to Affiliate, Noncurrent

2,704

2,577

Mark-to-market derivative liabilities (noncurrent liabilities)

197

150

Payable for Zion Station decommissioning

117

691

602

20,521

19,757

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[5]

33,829

33,559

Stockholders' Equity Attributable to Parent [Abstract]

3,072

2,701

^[2]

(56)

(63)

(60)

(36)

Noncontrolling interests

1,432

1,307

47,568

46,529

Members' Capital

9,265

8,997

3,072

2,701

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

^[2]

(56)

(63)

(60)

(36)

Total member's equity

12,281

11,635

13,713

12,942

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

160

164

264

219

140

192

181

801

854

5,139

5,160

2,173

2,036

223

8,415

8,235

201

216

Mark-to-market derivative liabilities (current liabilities)

113

435

386

550

623

2,070

1,999

^[4]

106

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

3,196

3,135

8,415

8,235

3,196

3,135

546

533

Receivables from affiliates

259

272

359

199

205

218

Inventories, net

156

164

1,634

1,518

18,811

17,502

987

895

2,625

Receivable from affiliate

332

324

2,238

2,172

1,387

1,490

7,575

7,512

28,020

26,532

294

425

665

625

660

1,045

706

Mark-to-market derivative liabilities (current liabilities)

204

155

126

131

2,589

2,766

6,606

5,844

205

5,320

4,914

118

111

244

259

Mark-to-market derivative liabilities (noncurrent liabilities)

3,577

3,459

225

224

526

507

10,010

9,474

19,410

18,289

Stockholders' Equity Attributable to Parent [Abstract]

1,588

1,000

978

Other paid-in capital

6,022

5,677

8,610

8,243

28,020

26,532

1,000

978

516

295

271

258

Receivables from affiliates

132

146

Prepaid utility taxes

1,121

842

7,400

7,141

1,651

1,583

Receivable from affiliate

466

405

353

347

2,520

2,384

11,041

10,367

300

282

281

108

109

128

112

968

944

2,579

2,280

184

2,964

2,792

288

287

551

527

3,918

3,723

7,649

7,131

Stockholders' Equity Attributable to Parent [Abstract]

2,473

2,455

918

780

^[2]

3,392

3,236

11,041

10,367

918

780

^[2]

341

332

300

100

112

214

267

Prepaid utility taxes

1,114

845

6,904

6,597

508

514

310

319

839

853

^[6]

8,857

8,295

210

381

378

239

209

144

110

108

102

1,003

1,134

2,281

1,480

252

2,149

2,081

204

209

118

184

2,564

2,552

Stockholders' Equity Attributable to Parent [Abstract]

^[6]

6,100

5,418

1,388

1,367

1,369

1,320

Preferred Stock, Value, Issued

2,757

2,687

190

2,757

2,877

8,857

8,295

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

1,369

1,320

Mark-to-market derivative liabilities (current liabilities)

^[4]

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

122

122

4,000

272

581

319

122

305

1,474

10,864

2,277

Notes, Loans and Financing Receivable, Gross, Noncurrent

1,406

Deferred Tax Assets, Net, Noncurrent

3,850

16,188

958

456

404

266

Mark-to-market derivative liabilities (current liabilities)

107

2,327

4,823

3,406

466

215

Mark-to-market derivative liabilities (noncurrent liabilities)

147

200

4,442

Temporary Equity, Par Value

11,592

183

Stockholders' Equity Attributable to Parent [Abstract]

617

Preferred Stock, Shares Outstanding

$ (36)

18,000

Preferred Stock, Par or Stated Value Per Share

$ 4,413

$ 0.01

$ 16,188

Members' Capital

3,832

617

(36)

Total member's equity

4,413

299

595

345

118

650

2,118

11,311

2,945

132

Notes, Loans and Financing Receivable, Gross, Noncurrent

4,000

Deferred Tax Assets, Net, Noncurrent

470

7,634

21,063

517

545

335

325

Exelon Money Pool Borrowing Current

Mark-to-market derivative liabilities (current liabilities)

101

376

125

2,547

5,499

3,746

139

Mark-to-market derivative liabilities (noncurrent liabilities)

167

830

234

5,130

Temporary Equity, Par Value

13,176

Stockholders' Equity Attributable to Parent [Abstract]

(91)

21,063

Members' Capital

7,978

(91)

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

Total member's equity

7,887

7,887

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Predecessor [Member]

Mark-to-market derivative liabilities (current liabilities)

124

^[4]

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Successor [Member]

172

Mark-to-market derivative liabilities (current liabilities)

111

^[4]

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member] | Predecessor [Member]

156

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member] | Successor [Member]

172

156

102

292

230

148

261

122

140

764

726

5,409

5,162

676

661

100

266

287

1,046

1,020

7,219

6,908

139

145

145

119

520

455

2,338

2,340

1,845

1,723

124

2,039

1,873

Stockholders' Equity Attributable to Parent [Abstract]

4,897

4,668

1,309

1,122

Other paid-in capital

1,013

1,118

2,322

2,240

2,322

2,240

7,219

6,908

134

154

301

388

3,222

3,070

297

299

188

202

500

511

4,023

3,969

105

218

204

109

495

564

1,047

1,061

1,016

945

100

111

1,186

1,107

Stockholders' Equity Attributable to Parent [Abstract]

2,728

2,732

725

612

570

625

1,295

1,237

4,023

3,969

570

625

165

$ 4

$ 2

168

156

242

Due from Affiliates

Prepaid utility taxes

520

546

2,456

2,322

Notes, Loans and Financing Receivable, Gross, Noncurrent

412

414

531

519

3,507

3,387

110

338

297

1,129

1,153

908

885

975

937

Stockholders' Equity Attributable to Parent [Abstract]

2,442

2,387

912

773

153

227

1,065

1,000

3,507

3,387

Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities

153

227

139

172

Atlantic City Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]

Mark-to-market derivative liabilities (current liabilities)

124

^[4]

Common Stock, Shares Authorized

$ 139

$ 172

[1]	Exelon’s consolidated assets include $8,514 million and $8,268 million at September 30, 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 $3,438 million and $3,264 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.
[2]	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.
[3]	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.
[4]	Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s balance sheet. See Note 13 - Retirement Benefits for additional details.
[5]	Generation’s consolidated assets include $8,415 million and $8,235 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,196 million and $3,135 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.
[6]	BGE’s consolidated assets include $47 million and $26 million at September 30, 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 $83 million and $122 million at September 30, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

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

Sep. 30, 2016

Dec. 31, 2015

2,000,000,000

Stockholders' Equity Attributable to Parent [Abstract]

Treasury Stock, Shares held

$ 114,535

$ 95,384

35,000,000

Stockholders' Equity Attributable to Parent [Abstract]

$ 47,568

46,529

Stockholders' Equity Attributable to Parent [Abstract]

28,020

26,532

Stockholders' Equity Attributable to Parent [Abstract]

11,041

10,367

Stockholders' Equity Attributable to Parent [Abstract]

^[1]

8,857

8,295

Stockholders' Equity Attributable to Parent [Abstract]

7,219

6,908

Stockholders' Equity Attributable to Parent [Abstract]

4,023

3,969

Noncontrolling Interest in Variable Interest Entity

Stockholders' Equity Attributable to Parent [Abstract]

3,507

$ 3,387

Preferred Stock, Par or Stated Value Per Share

$ 0.01

Common Stock, Shares Authorized

400,000,000

Stockholders' Equity Attributable to Parent [Abstract]

Common Stock, Shares, Outstanding

$ 16,188

254,289,261

Common Stock, Par or Stated Value Per Share

$ 0.01

Stockholders' Equity Attributable to Parent [Abstract]

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

$ 21,063

[1]

BGE’s consolidated assets include $47 million and $26 million at September 30, 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 $83 million and $122 million at September 30, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

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

Total

Common Stock [Member]

Treasury Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

Exelon Generation Co L L C [Member]

Undistributed Earnings [Member]

Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Exelon Generation Co L L C [Member]

Noncontrolling Interest [Member]

Exelon Generation Co L L C [Member]

Membership Interest [Member]

Commonwealth Edison Co [Member]

Common Stock [Member]

Commonwealth Edison Co [Member]

Retained Earnings, Unappropriated [Member]

Commonwealth Edison Co [Member]

Retained Earnings, Appropriated [Member]

Commonwealth Edison Co [Member]

Other Additional Capital [Member]

PECO Energy Co [Member]

Common Stock [Member]

PECO Energy Co [Member]

Retained Earnings [Member]

PECO Energy Co [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Baltimore Gas and Electric Company [Member]

Common Stock [Member]

Baltimore Gas and Electric Company [Member]

Retained Earnings [Member]

Baltimore Gas and Electric Company [Member]

Preferred Stock [Member]

Pepco Holdings LLC [Member]

Additional Paid-in Capital [Member]

Pepco Holdings LLC [Member]

Common Stock [Member]

Pepco Holdings LLC [Member]

Retained Earnings [Member]

Pepco Holdings LLC [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Pepco Holdings LLC [Member]

Common Stock Including Additional Paid in Capital [Member]

Pepco Holdings LLC [Member]

Membership Interest [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]

Pepco Holdings LLC [Member]

Common Stock Including Additional Paid in Capital [Member]

Deferred Compensation, Share-based Payments [Member]

Pepco Holdings LLC [Member]

Other Comprehensive Income (Loss), Net of Tax | Predecessor [Member]

^[1]

$ (2,684)

$ (36)

$ 1

$ 5

Net income | Predecessor [Member]

^[1]

(24)

197

Proceeds from Contributions from Parent | Predecessor [Member]

1,959

1,208

$ 339

299

$ 212

$ 128

$ 55

$ 37

Proceeds from Contributions from Parent

112

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

(28)

4,413

$ 3,832

Ending Balance at Dec. 31, 2015

$ 27,294

$ 18,676

$ (2,327)

$ 12,068

$ (2,624)

$ 1,308

$ 193

2,877

2,240

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

954,668

Ending Balance at Dec. 31, 2015

$ 25,793

8,243

$ 1,588

$ (1,639)

$ 2,617

$ 5,677

3,236

$ 2,455

$ 780

$ 1

2,687

$ 1,367

$ 1,320

$ 190

2,240

$ 1,122

$ 1,118

1,237

$ 612

$ 625

1,000

$ 773

$ 227

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

Other Comprehensive Income (Loss), Net of Tax | Predecessor [Member]

Net income | Predecessor [Member]

(13)

587

332

149

Common Stock, Value, Issued | Predecessor [Member]

^[1]

(2,596)

(60)

$ 3

Common Stock, Value, Issued

18,676

1,588

2,455

1,367

1,122

612

773

Beginning Balance | Predecessor [Member]

3,832

Beginning Balance

8,997

$ 8,997

Retained Earnings (Accumulated Deficit) | Predecessor [Member]

617

$ 617

Accumulated other comprehensive loss, net | Predecessor [Member]

12,068

2,701

$ 2,701

978

780

1,320

625

227

(36)

$ (36)

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

(2,624)

^[1]

(63)

^[1]

$ (63)

$ 1,307

^[1]

12,942

Additional Paid in Capital | Predecessor [Member]

$ 3,829

Additional Paid in Capital

5,677

1,118

Derivative Asset, Noncurrent | Predecessor [Member]

Other Comprehensive Income (Loss), Net of Tax | Predecessor [Member]

$ 758

733

Stock Issued During Period, Value, Employee Stock Purchase Plan | Predecessor [Member]

Net income | Predecessor [Member]

Employee stock purchase plan issuances | Predecessor [Member]

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

4,439

636

(35)

3,838

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

Proceeds from Contributions from Parent | Predecessor [Member]

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

954,668

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

4,413

3,832

Beginning Balance at Dec. 31, 2015

$ 27,294

18,676

(2,327)

12,068

(2,624)

1,308

193

2,877

2,240

Beginning Balance at Dec. 31, 2015

25,793

8,243

1,588

(1,639)

2,617

5,677

3,236

2,455

780

2,687

1,367

1,320

190

2,240

1,122

1,118

1,237

612

625

1,000

773

227

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

Stock Issued During Period, Value, Employee Stock Purchase Plan

101

^[1]

(5)

Net Working Capital

(5)

$ 36

Stock Issued During Period, Shares, Employee Stock Purchase Plans

924

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

$ 956

930

556

538

297

346

191

(16)

(50)

$ (92)

(167)

(7)

Noncontrolling Interest, Increase from Sale of Parent Equity Interest

105

Long-term incentive plan activity (in shares)

2,422

Long-term incentive plan activity

$ 61

Employee stock purchase plan issuances (in shares)

924

Employee stock purchase plan issuances

$ 36

Appropriation of retained earnings for future dividends

(297)

297

Tax benefit on stock compensation

(17)

Common stock dividends

(877)

(8)

(275)

(208)

(134)

(39)

(24)

Contribution from parent

170

188

187

113

139

Dividends

(125)

Allocation of tax benefit from parent

157

Minority Interest Increase From Acquisition

Preferred security dividends

(8)

Temporary Equity, Other Changes

(107)

107

(107)

Allocation Of Tax Benefit From Members

Ending Balance (in shares) at Sep. 30, 2016

$ 27,460

18,756

(2,327)

12,121

(2,523)

1,433

2,757

2,322

958,014

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

$ 26,027

8,610

1,588

(1,639)

2,639

6,022

3,392

2,473

918

2,757

1,388

1,369

2,322

1,309

1,013

1,295

725

570

1,065

912

153

Proceeds from Contributions from Parent

188

187

113

139

Payments to Acquire Businesses, Gross | Successor [Member]

(33)

Common Stock, Value, Issued | Predecessor [Member]

(6,896)

(255)

$ (29)

$ 3

Additional Paid in Capital | Predecessor [Member]

$ 3,835

Payments to Acquire Businesses, Gross | Successor [Member]

(33)

Beginning Balance | Successor [Member]

7,200

Retained Earnings (Accumulated Deficit) | Successor [Member]

Accumulated other comprehensive loss, net | Successor [Member]

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest | Successor [Member]

7,200

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

(301)

235

Business Combination, Contingent Consideration, Liability, Noncurrent | Successor [Member]

Other Comprehensive Income (Loss), Net of Tax | Successor [Member]

Net income | Successor [Member]

(91)

$ 0

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

Contribution from parent | Successor [Member]

1,088

Ending Balance (in shares) at Sep. 30, 2016

$ 27,460

18,756

(2,327)

12,121

(2,523)

1,433

2,757

2,322

958,014

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

$ 26,027

8,610

1,588

(1,639)

2,639

6,022

3,392

2,473

918

2,757

1,388

1,369

2,322

1,309

1,013

1,295

725

570

1,065

912

153

Proceeds from Contributions from Parent | Successor [Member]

1,088

Payments to Acquire Businesses, Gross | Successor [Member]

(62)

$ (62)

$ (29)

Other Comprehensive Income (Loss), Net of Tax | Successor [Member]

Net income | Successor [Member]

166

526

271

122

$ 169

Ending Balance (in shares) at Sep. 30, 2016

$ 27,460

$ 18,756

$ (2,327)

$ 12,121

$ (2,523)

$ 1,433

2,757

2,322

958,014

Common Stock, Value, Issued

$ 26,027

8,610

$ 1,588

$ (1,639)

$ 2,639

$ 6,022

3,392

$ 2,473

$ 918

$ 1

2,757

$ 1,388

$ 1,369

2,322

$ 1,309

$ 1,013

1,295

$ 725

$ 570

1,065

$ 912

$ 153

18,756

1,588

2,473

1,388

1,309

725

912

Preferred Stock, Redemption Amount

193

$ 193

(190)

$ (190)

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

Beginning Balance | Successor [Member]

7,978

Beginning Balance

9,265

$ 9,265

Retained Earnings (Accumulated Deficit) | Successor [Member]

(91)

$ (91)

Accumulated other comprehensive loss, net | Successor [Member]

12,121

3,072

$ 3,072

1,000

918

$ 1,369

$ 570

$ 153

$ 0

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest | Successor [Member]

(2,523)

^[1]

(56)

^[1]

$ (56)

$ 1,432

$ 1

^[1]

7,887

Limited Liability Company (LLC) Members' Equity, Including Portion Attributable to Noncontrolling Interest

13,713

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

$ (301)

Business Combination, Contingent Consideration, Asset

(235)

(163)

Additional Paid in Capital

$ 6,022

$ 1,013

Derivative Asset, Noncurrent | Successor [Member]

$ 0

Organization, Consolidation and Presentation of Financial Statements [Abstract]

$ 669

$ 630

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

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Income taxes	$ 340	$ 115	$ 625	$ 805
Exelon Generation Co L L C [Member]
Income taxes	173	(36)	293	371
Atlantic City Electric Company [Member]
Income taxes	23	14	(8)	23
PECO Energy Co [Member]
Income taxes	54	37	121	122
Commonwealth Edison Co [Member]
Income taxes	75	99	244	226
Baltimore Gas and Electric Company [Member]
Income taxes	36	35	109	141
Potomac Electric Power Company [Member]
Income taxes	$ 35	$ 32	$ 34	$ 62

Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

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

1. Significant Accounting Policies (All Registrants)

Description of Business (All Registrants)

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and transmission businesses. 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, which sells electricity and natural gas to both wholesale and retail customers. 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)

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. When appropriate, Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are named specifically for their related activities and disclosures.

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 for PHI, Pepco, DPL or ACE.

In its December 31, 2015 Form 10-K, Exelon revised the presentation on the Consolidated Statements of Operations and Comprehensive Income for PECO and BGE to reflect separately operating revenues from the sale of electricity and operating revenues from the sale of natural gas, as well as to reflect separately purchased power expense and purchased fuel expense within the operating expenses section of the Consolidated Statement of Operations and Comprehensive Income. Further, Exelon revised the presentation from Total operating revenues to "Rate-regulated utility revenues" and "Competitive businesses revenues" on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. Similarly, Exelon has separately presented Rate-regulated utility purchased power and fuel expense and Competitive businesses purchased power and fuel expense on the face of Exelon’s Consolidated Statement of Operations and Comprehensive Income for all periods presented. The reclassifications described herein were made for presentation purposes and did not affect any of the Registrants’ total operating revenues or net income.

ACE Basic Generation Service Recovery Mechanism

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 $8 million and $9 million for the three and nine months ended September 30, 2015, respectively.

Classification of Interest on Uncertain Tax Positions

In the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting principle 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 nine months ended September 30, 2015 is $1 million for PHI and less than $1 million for Pepco, DPL and ACE. The reclassification amount is more significant for the year ended December 31, 2015.

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

The accompanying consolidated financial statements as of September 30, 2016 and 2015 and for the three and nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2015 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2016. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.

Variable Interest Entities (All Registrants)

9 Months Ended

Sep. 30, 2016

Variable Interest Entity [Abstract]

Variable Interest Entity Disclosure (All Registrants)

3. 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 September 30, 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 collectively had one consolidated VIE (see Consolidated Variable Interest Entities below). As of September 30, 2016 and December 31, 2015, Exelon and Generation collectively had significant interests in nine and eight other VIEs, respectively, 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

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 December 2016 in proportion to their ownership interests, which equates up to approximately $172 million for the tax equity investor and up to $78 million for Generation (see Note 18 — 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. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants, 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. (For additional details related to the new consolidation guidance, see Note 2—New Accounting Pronouncements.) Under VIE guidance, Generation is the primary beneficiary; therefore, the entity continues to be consolidated.

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


•	A retail gas group formed by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier,


•	a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities,


•	several wind project companies designed by Generation to develop, construct and operate wind generation facilities,


•	a group of companies formed by Generation to build, own and operate other generating facilities,


•	certain retail power and gas companies for which Generation is the sole supplier of energy,


•	CENG,


•	2015 ESA Investco, LLC,


•	BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property, and


•	ATF, a special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of transition bonds.

As of September 30, 2016 and December 31, 2015, ComEd, PECO, Pepco and DPL did not have any material consolidated VIEs.

As of September 30, 2016 and December 31, 2015, Exelon, Generation, BGE, PHI and ACE provided the following support to their respective consolidated VIEs:


•	Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance of the solar and wind power facilities and there is limited recourse to Generation related to certain solar and wind entities.


•	Generation and Exelon, where indicated, provide the following support to CENG (see Note 5—Investment in Constellation Energy Nuclear Group, LLC and Note 26—Related Party Transactions of the Exelon 2015 Form 10-K 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 5 — Regulatory Matters for additional details),


•	Generation provided a $400 million loan to CENG. As of September 30, 2016, the remaining obligation is $312 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 18 — Commitments and Contingencies for more details),


•	in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid in 2014 through 2016. As of September 30, 2016, there was no remaining obligation,


•	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 $8 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 18 — Commitments and Contingencies for more details), and


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


•	Generation provides approximately $16 million in credit support for the retail power and gas companies for which Generation is the sole supplier of energy.


•	Generation provides a $75 million parental guarantee to a third-party gas supplier and provides limited recourse to other third-party gas suppliers and customers in support of its retail gas group.


•	Generation provides operating and capital funding to the other generating facilities for ongoing construction, operations and maintenance and provides a parental guarantee of up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract in support of one of its other generating facilities.

•

In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three and nine months ended September 30, 2016, BGE remitted $27 million and $64 million to BondCo, respectively. During the three and nine months ended September 30, 2015, BGE remitted $21 million and $63 million to BondCo, respectively.

•

In the case of ATF, proceeds from the sale of each series of transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on transition bonds and related taxes, expenses and fees. During the three and nine months ended September 30, 2016, ACE transferred $20 million and $47 million to ATF, respectively. During the three and nine months ended September 30, 2015, ACE transferred $18 million and $45 million to ATF, respectively.

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.

The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at September 30, 2016 and December 31, 2015 are as follows:



	September 30, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE
Current assets	$	914	$	849	$	44	$	20	$	15	$	909	$	881	$	23	$	12	$	12
Noncurrent assets	8,235		8,201		3		31		19		8,009		8,004		3		18		18
Total assets	$	9,149	$	9,050	$	47	$	51	$	34	$	8,918	$	8,885	$	26	$	30	$	30
Current liabilities	$	569	$	439	$	84	45		$	40	$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities	3,090		2,979		—		111		99		2,927		2,884		41		124		124
Total liabilities	$	3,659	$	3,418	$	84	$	156	$	139	$	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.

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 September 30, 2016 and December 31, 2015, these assets and liabilities primarily consisted of the following:



	September 30, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents	$	160	$	160	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash	101		43		44		15		15		100		77		23		12		12
Accounts receivable, net
Customer	264		264		—		—		—		219		219		—		—		—
Other	42		42		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets	49		49		—		—		—		140		140		—		—		—
Inventory
Materials and supplies	192		192		—		—		—		181		181		—		—		—
Other current assets	58		51		—		5		—		35		30		—		—		—
Total current assets	866		801		44		20		15		882		854		23		12		12
Property, plant and equipment, net	5,139		5,139		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds	2,173		2,173		—		—		—		2,036		2,036		—		—		—
Goodwill	47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets	32		32		—		—		—		53		53		—		—		—
Other noncurrent assets	257		223		3		31		19		90		85		3		18		18
Total noncurrent assets	7,648		7,614		3		31		19		7,386		7,381		3		18		18
Total assets	$	8,514	$	8,415	$	47	$	51	$	34	$	8,268	$	8,235	$	26	$	30	$	30
Long-term debt due within one year	$	191	$	64	$	81	$	43	$	38	$	111	$	27	$	79	$	46	$	46
Accounts payable	201		201		—		—		—		216		216		—		—		—
Accrued expenses	102		98		2		2		2		115		113		2		2		2
Mark-to-market derivative liabilities	24		24		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities	14		14		—		—		—		12		12		—		—		—
Other current liabilities	34		34		—		—		—		13		13		—		—		—
Total current liabilities	566		435		83		45		40		472		386		81		48		48
Long-term debt	661		550		—		111		99		666		623		41		124		124
Asset retirement obligations	2,070		2,070		—		—		—		1,999		1,999		—		—		—
Pension obligation^(c)	9		9		—		—		—		9		9		—		—		—
Unamortized energy contract liabilities	26		26		—		—		—		39		39		—		—		—
Other noncurrent liabilities	106		106		—		—		—		79		79		—		—		—
Total noncurrent liabilities	2,872		2,761		—		111		99		2,792		2,749		41		124		124
Total liabilities	$	3,438	$	3,196	$	83	$	156	$	139	$	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 13 - 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.

The Registrants’ unconsolidated VIEs consist of:


•	Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.


•	Asset sale agreement with ZionSolutions, LLC and EnergySolutions, Inc. in which Generation has a variable interest but has concluded that consolidation is not required.


•	Equity investments in energy development companies, distributed energy companies, and energy generating facilities for which Generation has concluded that consolidation is not required.

As of September 30, 2016 and December 31, 2015, Exelon and Generation had significant unconsolidated variable interests in nine and eight VIEs, respectively for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity 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 $20 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 $20 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. The risk of a loss was assessed to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.

In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy company. Generation’s total equity commitment in this arrangement was $91 million and was paid incrementally over an approximate two year period (see Note 18 — 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 2—New Accounting Pronouncements.) 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 a distributed energy company, which is an unconsolidated VIE. 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 from inception through December 2016 in proportion of their ownership interests, which equates up to approximately $172 million for the tax equity investor and up to $78 million for Generation (see Note 18 — 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, which is an unconsolidated VIE. 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.

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



September 30, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	586	$	531	$	1,117
Total liabilities^(a)	181		308		489
Exelon's ownership interest in VIE^(a)	—		193		193
Other ownership interests in VIE^(a)	405		34		439
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		225		225
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	11		—		11



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 $135 million and $206 million as of September 30, 2016 and December 31, 2015, respectively; offset by payables to ZionSolutions LLC of $124 million and $189 million as of September 30, 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 of the unconsolidated VIEs, Exelon and Generation has assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

Mergers, Acquisitions, and Dispositions

9 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions

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

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. In the first quarter of 2016, Exelon estimated and recorded total nominal cost commitments of $508 million, excluding renewable generation commitments (approximately $444 million on a net present value basis, excluding renewable generation commitments and charitable contributions).

During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware and New Jersey and continued negotiations in Maryland for amounts and allocations reflecting the application of the most favored nation provision, resulting in total nominal cost of commitments of $513 million, excluding renewable generation commitments(with no change in the $444 million net present value basis amount, excluding renewable generation commitments and charitable contributions). A similar filing will be required in Maryland. These filings, which reflect agreements reached with certain parties to the merger proceedings in the jurisdictions, are subject to regulatory review and approval in each jurisdiction. The Delaware Commission approved the amounts and allocations in September and October 2016 and an order from the New Jersey BPU is expected in the fourth quarter of 2016. No changes in commitment cost levels are required in the District of Columbia.

The proposed settlements included certain changes in the amount and mix of previously reported, expected commitment types, resulting in adjustments to the estimated commitment costs recorded by Exelon Corporate and by the individual PHI utility reporting entities such that more commitments are expected to be obligations of Exelon Corporate for energy efficiency, workforce development and other programs as opposed to obligations of PHI, Pepco, DPL and ACE for additional customer rate credits. Specifically, for the three months ended September 30, 2016, Exelon Corporate recorded an increase of $55 million and PHI, Pepco, DPL and ACE recorded decreases of $50 million, $13 million, $27 million and $10 million, respectively, 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 nine months ended September 30, 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	$	58	$	101	$	250	$	250
Energy efficiency	2016 - 2021	—		—		—		—		120
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	$	77	$	111	$	314	$	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 approximately 37 MWs of new generation in Maryland, District of Columbia, and Delaware, 27 MWs of which are expected to be completed by 2018. These investments are expected to total approximately $137 million, are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. The actual cost of investment in new generation may differ depending on the result of final negotiations and application of the most favored nation provision. 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, the Sierra Club and CCAN filed a notice of appeal. Exelon believes the matters are without merit. These appeals are not expected to be resolved any earlier than the first quarter of 2017.

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. Although the Court has not yet issued a scheduling order, a decision on this matter is not expected until 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; however, Exelon expects to finalize these amounts by the end of 2016. During the second and third quarters, 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 liability resulting in a $16 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	4,000
Total assets	$	21,792

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,442
Pension and OPEB liability	821
Other liabilities	187
Total liabilities	$	14,650
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 expected to be 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.

Exelon’s and PHI’s carrying amount of goodwill for the nine months ended September 30, 2016 was as follows:



	PHI			Exelon^(a)
Beginning balance, December 31, 2015	$	—		$	2,672
Goodwill from business combination	4,016			4,016
Measurement period adjustments	(16		)	(16		)
Ending balance, September 30, 2016	$	4,000		$	6,672

_____________

(a) As of September 30, 2016, there were no changes to the carrying amount of goodwill for ComEd, see Note 11— Intangible Assets of the Exelon 2015 Form 10-K for further information.

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 5 - 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 September 30, 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 $1.4 billion and Net income of $169 million during the three months ended September 30, 2016, and Operating revenues of $2.7 billion and Net loss of $(92) million during the nine months ended September 30, 2016.

For the three and nine months ended September 30, 2016 and 2015, the Registrants have recognized costs to achieve the PHI acquisition as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2016		2015		2016			2015
Exelon^(b)	$	20	$	22	$	123		$	84
Generation	9		10		29			30
ComEd^(c)	—		3		(6		)	9
PECO	1		1		3			4
BGE^(c)	1		2		(3		)	4
Pepco^(c)	3		1		26			3
DPL^(c)	2		—		18			2
ACE	2		—		17			1



	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		March 24 to September 30,		January 1 to March 23,		Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2016		2015		2016		2016		2015
PHI^(c)	$	7	$	3	$	63	$	29	$	16

______________


(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 nine months ended September 30, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $10 million, $3 million and $13 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 5—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.



	Three Months Ended September 30,				Nine Months Ended September 30,				Year Ended December 31,
	2016 (a)		2015 (b)		2016 (a)		2015 (b)		2015 (c)
Total operating revenues	$	9,002	$	8,545	$	24,468	$	26,129	$	33,823
Net income attributable to common shareholders	501		746		1,346		2,169		2,618

Basic earnings per share	$	0.54	$	0.81	$	1.46	$	2.36	$	2.85
Diluted earnings per share	0.54		0.81		1.45		2.35		2.84

______________


(a)	The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.


(b)	The amounts above include adjustments for non-recurring costs directly related to the merger of $25 million and $100 million and intercompany revenue of $192 million and $426 million for the three and nine months ended September 30, 2015, respectively.


(c)	The amounts above include adjustments for 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 September 30, 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 September 30, 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.

It is impracticable to determine the post-close impact of ConEdison Solutions as the operations of ConEdison Solutions have been integrated into Generation's operations and are therefore not distinguishable after the acquisition.

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 838MW 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. Closing of the transaction is currently anticipated to occur in the second quarter of 2017 and is dependent upon 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 has been completed) and other customary closing conditions. The NRC license for FitzPatrick expires in 2034. Entergy had previously announced plans in November 2015 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.

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 proceeding has filed any protests or comments. Generation and Entergy had requested FERC to approve the FitzPatrick transaction by November 18, 2016, however FERC is under no obligation to do so. The timing of FERC’s decision on Generation and Entergy’s application and the outcome of this protest are currently uncertain. Refer to Note 5 - Regulatory Matters for additional information on the New York CES and ZEC program.

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 September 30, 2016, Generation has paid a non-refundable deposit of $10 million and reimbursed Entergy for $9 million in costs all of which have been classified with Other noncurrent assets on Exelon's and Generation's Consolidated Balance Sheets. These amounts are also reflected within Acquisition of businesses on Exelon's and Generation's Consolidated Statements of Cash Flows.

Asset Divestitures (Exelon, Generation, PHI and Pepco)

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 New York Avenue land parcel, located in 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 the Exelon and PHI 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 10 - Debt and Credit Agreements for more information. As of September 30, 2016, $46 million of Property, plant and equipment and $5 million of Asset retirement obligation are classified as held for sale within Other current assets and Other current liabilities, respectively, on Exelon’s and Generation’s Consolidated Balance Sheets. In October 2016, Generation entered into an agreement to sell a portion of the Upstream assets which is expected to close before 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. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in the Exelon and PHI 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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Regulatory Matters (All Registrants)

Regulatory Matters (All Registrants)

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

5. Regulatory Matters (All Registrants)

Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 - Regulatory Matters of the PHI 2015 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.

Illinois Regulatory Matters

Distribution Formula Rate (Exelon and ComEd). On April 13, 2016, ComEd filed its annual distribution formula rate with the ICC pursuant to EIMA. The filing establishes the revenue requirement used to set the rates that will take effect in January 2017 after the ICC’s review and approval, which is due by December 2016. The revenue requirement requested is based on 2015 actual costs plus projected 2016 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2015 to the actual costs incurred that year. ComEd's 2016 filing request includes a total increase to the revenue requirement of $138 million, reflecting an increase of $139 million for the initial revenue requirement for 2017 and a decrease of $1 million related to the annual reconciliation for 2015. The revenue requirement for 2017 provides for a weighted average debt and equity return on distribution rate base of 6.71% inclusive of an allowed ROE of 8.64%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2015 provided for a weighted average debt and equity return on distribution rate base of 6.69% inclusive of an allowed ROE of 8.59%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points. See table below for ComEd's regulatory assets associated with its distribution formula rate. For additional information on ComEd's distribution formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K.

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 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. The order also directs ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, or from competitive electric generation suppliers.

In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers. On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court. However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014.

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. Accordingly, FutureGen requested that the court dismiss the proceeding as moot. 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

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 (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 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. A decision by the PAPUC is expected in December 2016.

For further information on the Pennsylvania procurement proceedings, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

Energy Efficiency Programs (Exelon and PECO). 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.

For further information on energy efficiency programs, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

Maryland Regulatory Matters

2016 Maryland Electric Distribution Rate Case (Exelon, PHI and Pepco). On April 19, 2016, Pepco filed an application with the MDPSC requesting an increase of $127 million to its electric distribution base rates, which was later updated to $103 million, based on a requested ROE of 10.6%. The application is inclusive of a request seeking recovery of Pepco’s regulatory assets associated with its AMI program over a five-year period 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 November 2016. In addition to the proposed rate increase, Pepco is proposing to continue its Grid Resiliency Program initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. Under the Grid Resiliency Program, Pepco 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, Pepco proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse technology by investing $16 million a year for two years for a total of $32 million. Pepco cannot predict how much of the requested rate increase the MDPSC will approve or if it will approve a continuation of Pepco’s Grid Resiliency Program proposal.

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 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 Rate Case (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. BGE cannot predict the outcomes of these appeals. 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.

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. As of September 30, 2016 and December 31, 2015, the balance of BGE's regulatory asset was $235 million and $196 million, respectively, representing incremental program deployment costs. The current quarter balance of $235 million consists of three major components, including $148 million of unamortized incremental deployment costs of the AMI program, $55 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 approval became effective June 2016. The balance as of September 30, 2016 reflects the impact of the cost disallowances and adjustments discussed below. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being recovered through rates and amortized to expense over a 10 year period, while the post-test year incremental program deployment costs have not yet been approved for recovery by the MDPSC. A return on the regulatory asset is currently included in rates, except for the $55 million portion representing the unamortized cost of the retired non-AMI meters and a $32 million portion related to post-test year incremental program deployment costs.

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. 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. 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. BGE cannot predict the outcomes of these appeals.

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 $55 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 September 30, 2016. For further information, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

2013 Maryland Electric and Natural Gas Distribution Rate Case (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 September 30, 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 23, 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.

Delaware Regulatory Matters

2016 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 the rate increase two months after filing the applications which were effective July 16, 2016. It also allows the entire requested rate increase seven months after filing, subject to a cap and a refund obligation based on the final DPSC order. DPL cannot predict how much of the requested increase the DPSC will approve.

District of Columbia Regulatory Matters

2016 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, 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 October 7, 2016, Pepco filed for reconsideration of this order and requested clarification that the order was not final and that the BSA matter would be decided in the base rate case. Pepco also argued that, if the order were considered final, the DCPSC reconsider its ruling that funds collected from the BSA can be retroactively refunded. 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.

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 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 NUGs and (ii) costs related to surcharges for the New Jersey Societal Benefit Program (a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible accounts.

The net impact of adjusting the charges as proposed is an overall annual rate 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. The matter is pending at the NJBPU.

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 Clean Energy Standard (CES), a component of which includes creation of a Tier 3 Zero Emission Credit (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 by the federal government. 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 CES initially identifies the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point nuclear facilities. The program specifically provides that Nine Mile Point Units 1 & 2 qualify jointly as a single facility and if either unit permanently ceases operations then both units will no longer qualify for ZEC payments for the remainder of the program. As issued, the order provides that the duration of the program beyond the first tranche is conditional upon a buyer purchasing the FitzPatrick facility and taking title prior to September 1, 2018; however, Generation and CENG requested clarification, or in the alternative limited rehearing, that this condition is applicable to the FitzPatrick facility only and has no bearing on the 12-year duration of the program for Ginna or Nine Mile Point. To date, several parties have filed with the NYPSC requests for rehearing or reconsideration of the CES and 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. Generation and CENG will seek to intervene in the case and to dismiss the lawsuit. Other legal challenges remain possible and the outcomes of each of these challenges are currently uncertain. Negotiations with NYSERDA regarding contracts for the sale of ZECs from Ginna, Nine Mile Point and FitzPatrick are ongoing, and Generation expects that NYSERDA will enter into final agreements during the fourth quarter of 2016. See Note 7 - Early Nuclear Plant Retirements for additional information relative to Ginna and Nine Mile Point. See 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 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 does not plan to retire shortly after the expiration of the RSSA, Ginna is required to file a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the 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 a result, Ginna has reserved the right to withdraw this notification and cease commercial operations if the ZEC program is terminated, suspended, or stayed prior to commencement of the program on April 1, 2017 or if for any reason a contract with NYSERDA in a form and substance satisfactory to Generation and CENG is not executed for Ginna, Nine Mile Point, or FitzPatrick. Negotiations with NYSERDA are ongoing and contract execution is currently targeted for completion in the fourth quarter of 2016.

There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029. In the event the plant were to be retired before the current license term ends in 2029, Exelon's and Generation's results of operations could be adversely affected by the accelerated future decommissioning costs, severance costs, increased depreciation rates, and impairment charges, among other items. See Note 7-Early Nuclear Plant Retirements for further information regarding the impacts of a decision to early retire one or more nuclear plants.

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.

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



	2016
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	90		$	12		$	2		$	8		$	8
Annual reconciliation (decrease) increase	4			3			(10		)	(10		)	(14		)
Dedicated facilities (decrease) increase ^(b)	—			13			—			—			—
MAPP abandonment recovery decrease ^(c)	—			—			(15		)	(12		)	—
Total revenue requirement increase (decrease)	$	94		$	28		$	(23	)	$	(14	)	$	(6	)

Allowed return on rate base ^(d)	8.47		%	8.09		%	7.88		%	7.21		%	7.83		%
Previously authorized allowed return on rate base ^(d)	8.61		%	8.46		%	8.36		%	7.80		%	8.51		%
Allowed ROE ^(e)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%

_____________

(a) All rates are effective June 2016.

(b) 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.

(c) 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.


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

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

For additional information regarding ComEd and BGE's transmission formula rate filings see Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K. For additional information regarding Pepco, DPL and ACE's transmission formula rate filings see Note 7 - Regulatory Matters of the PHI 2015 Form 10-K.

PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, 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. On July 5, 2016, a number of merchant transmission owners and load servicing entities opposed the Settlement in whole or in part. As of September 30, 2016, the Settlement is awaiting FERC's action. 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.

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

On 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 Unit 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 September 30, 2016, $27 million of direct costs associated with the Conowingo licensing effort have been capitalized. See Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K for additional information on Generation's operating license renewal efforts.

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

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

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 September 30, 2016 and December 31, 2015. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K and Note 7 - Regulatory Matters of the PHI 2015 Form 10-K.



									Successor
September 30, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,096	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes ^(b)	1,973		73		1,555		94		251		162		38		51
AMI programs ^(c)	704		160		53		235		256		171		85		—
Under-recovered distribution service costs ^(d)	232		232		—		—		—		—		—		—
Debt costs ^(e)	126		43		1		7		82		18		9		6
Fair value of long-term debt ^(f)	828		—		—		—		684		—		—		—
Fair value of PHI's unamortized energy contracts ^(g)	1,206		—		—		—		1,206		—		—		—
Severance	6		—		—		6		—		—		—		—
Asset retirement obligations	108		74		22		11		1		1		—		—
MGP remediation costs	295		267		27		1		—		—		—		—
Under-recovered uncollectible accounts	58		58		—		—		—		—		—		—
Renewable energy	246		244		—		—		2		—		—		2
Energy and transmission programs ^{(h)(i)(j)(k)(l)}	74		31		—		25		18		1		8		9
Deferred storm costs	39		—		—		1		38		14		5		19
Electric generation-related regulatory asset	13		—		—		13		—		—		—		—
Rate stabilization deferral	25		—		—		25		—		—		—		—
Energy efficiency and demand response programs	642		—		1		289		352		254		98		—
Merger integration costs ^(m)(n)	23		—		—		10		13		10		3		—
Under-recovered revenue decoupling ^(o)(p)	9		—		—		—		9		7		2		—
COPCO acquisition adjustment	9		—		—		—		9		—		9		—
Recoverable Workers compensation and long-term disability cost	30		—		—		—		30		30		—		—
Vacation accrual	37		—		13		—		24		—		14		10
Securitized stranded costs	153		—		—		—		153		—		—		153
CAP arrearage	7		—		7		—		—		—		—		—
Removal costs	448		—		—		—		448		119		84		246
Other	45		10		9		5		19		11		4		5
Total regulatory assets	11,432		1,192		1,688		722		3,595		798		359		501
Less: current portion	1,410		205		37		214		650		122		62		89
Total non-current regulatory assets	$	10,022	$	987	$	1,651	$	508	$	2,945	$	676	$	297	$	412



									Successor
September 30, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	85	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,704		2,238		466		—		—		—		—		—
Removal costs	1,627		1,333		—		151		143		20		123		—
Deferred rent ^(q)	40		—		—		—		40		—		—		—
Energy efficiency and demand response programs	175		135		40		—		—		—		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	79		—		79		—		—		—		—		—
Gas distribution tax repairs	21		—		21		—		—		—		—		—
Energy and transmission programs ^{(h)(i)(r)(j)(k)(l)}	171		72		59		—		40		17		11		12
Over-recovered revenue decoupling ^(o)	5		—		—		5		—		—		—		—
Other	70		3		6		16		45		7		12		24
Total regulatory liabilities	4,985		3,781		679		172		268		44		146		36
Less: current portion	548		204		128		54		101		20		46		35
Total non-current regulatory liabilities	$	4,437	$	3,577	$	551	$	118	$	167	$	24	$	100	$	1



									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 ^(b)	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(d)	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(f)	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 ^{(h)(i)(r)(j)(k)(l)}	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 ^(o)(p)	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 non-current 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 ^{(h)(i)(r)(j)(k)(l)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling ^(o)	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 non-current regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7

______

(a)

As of September 30, 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 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.

(b)

As of September 30, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $19 million, $32 million, $29 million, $20 million and $18 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, $36 million, $18 million and $15 million for ComEd, BGE, Pepco, DPL and ACE, respectively.

(c)

Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout the service territories for ComEd, PECO, BGE, Pepco and DPL. An AMI program has not been approved by the NJBPU for ACE in New Jersey. DPL and Pepco have received approval for recovery of deferred AMI program costs from the DCPSC and DPSC in the Delaware and DC service territories, and have requested recovery in pending distribution rate cases with the MDPSC for the Maryland service territories. As of September 30, 2016, the portion of deferred AMI program costs pending approval from the MDPSC is $32 million for BGE, $134 million for Pepco and $40 million for DPL, of which $75 million for Pepco and $14 million for DPL relates to retired legacy meters which are not earning a return and $3 million of post-test year costs for Pepco which are not earning a return.

(d)

As of September 30, 2016, ComEd’s regulatory asset of $232 million was comprised of $178 million for the 2014 - 2016 annual reconciliations and $54 million related to significant one-time events including $24 million of deferred storm costs, $11 million of Constellation and PHI merger and integration related costs and $19 million of smart meter related costs. As of December 31, 2015, ComEd’s regulatory asset of $189 million was comprised of $142 million for the 2014 and 2015 annual reconciliations and $47 million related to significant one-time events, including $36 million of deferred storm costs and $11 million of Constellation merger and integration related costs. See Note 4— Merger, Acquisitions, and Dispositions of the Exelon 2015 Form 10-K for further information.


(e)	Includes at Exelon and PHI the regulatory asset recorded at PHI for debt costs that are recoverable through the ratemaking process at Pepco, DPL, and ACE which were eliminated at Exelon and PHI as part of acquisition accounting.


(f)	Includes the unamortized regulatory assets recorded for the difference between carrying value and fair value of long-term debt of BGE as of the Constellation merger date 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.


(g)	Represents 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.

(h)

As of September 30, 2016, ComEd’s regulatory asset of $31 million included $24 million associated with transmission costs recoverable through its FERC approved formula rate and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of September 30, 2016, ComEd’s regulatory liability of $72 million included $43 million related to over-recovered energy costs and $29 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, 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.

(i)

As of September 30, 2016, BGE's regulatory asset of $25 million included $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $19 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $1 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.

(j)

As of September 30, 2016, Pepco's regulatory asset of $1 million related to under-recovered electric energy costs. As of September 30, 2016, Pepco's regulatory liability of $17 million included $9 million of over-recovered transmission costs and $8 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.

(k)

As of September 30, 2016, DPL's regulatory asset of $8 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $7 million of under-recovered electric energy costs. As of September 30, 2016, DPL's regulatory liability of $11 million included $6 million of over-recovered electric energy costs and $5 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.

(l)

As of September 30, 2016, ACE's regulatory asset of $9 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $5 million of under-recovered electric energy costs. As of September 30, 2016, ACE's regulatory liability of $12 million included $7 million of over-recovered transmission costs and $5 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.


(m)	As of September 30, 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.


(n)	Represents previously incurred PHI acquisition costs expected to be recovered in distribution rates in the Maryland service territories of Pepco and DPL.

(o)

Represents the electric and natural gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2016, BGE had a regulatory liability of $5 million related to over-recovered natural gas revenue decoupling and $0 million related to over-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.


(p)	Represents the electric distribution costs recoverable from customers under Pepco's Maryland and District of Columbia decoupling mechanisms and DPL's Maryland decoupling mechanism.


(q)	Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease that is recoverable through the ratemaking process at Pepco, DPL and ACE.

(r)

As of September 30, 2016, PECO's regulatory liability of $59 million included $30 million related to over-recovered costs under the DSP program, $13 million related to the over-recovered natural gas costs under the PGC, $10 million related to over-recovered non-bypassable transmission service charges and $6 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.

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

ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities' consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of September 30, 2016 and December 31, 2015.



													Successor
As of September 30, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(c)	$	396		$	123		$	90		$	66		$	117		$	79		$	12	$	26
Allowance for uncollectible accounts^(a)	(36		)	(17		)	(7		)	(6		)	(6		)	(4		)	—		(2		)
Purchased receivables, net	$	360		$	106		$	83		$	60		$	111		$	75		$	12	$	24



													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.

Impairment of Long-lived Assets (Exelon and Generation)	9 Months Ended
Impairment of Long-lived Assets (Exelon and Generation)	Sep. 30, 2016
Property, Plant and Equipment [Abstract]
Impairment of Long-Lived Assets (Exelon and Generation)	6. Impairment of Long-Lived Assets (Exelon and Generation) Long-Lived Assets (Exelon and Generation) 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 10 - 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 business by executing a forbearance agreement with the lenders of the nonrecourse debt, see Note 10 — Debt and Credit Agreements for additional information. As a result, the Upstream assets and liabilities are classified as held for sale on Exelon's and Generation's Consolidated Balance Sheets at September 30, 2016. See Note 4 — Mergers, Acquisitions and Dispositions 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. Further declines in commodity prices or further developments with Generation’s intended use or disposition of the assets could potentially result in future impairments of the Upstream assets. Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In the second quarter of 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 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. 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). 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 11—Income Taxes for additional information.

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

9 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

Implications Of Potential Early Retirement Disclosure [Text Block]

7. 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 is 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 will 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. Generation is proceeding with the market and regulatory notifications that must be made to shut down the plants, including notification to the NRC on June 20, 2016, and filing of a deactivation notice with PJM for Quad Cities on July 6, 2016. Generation will formally notify MISO of its plans to close Clinton later this year.

In 2016, as a result of the plant 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, there will be ongoing annual incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities primarily related to accelerated depreciation of plant assets (including 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. Through September 30, 2016, Exelon's and Generation's results include an incremental $443 million of pre-tax expense for these items as summarized in the table below. Please refer to Note 12 — Nuclear Decommissioning for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the early retirement of Clinton and Quad Cities.




Income statement expense (pre-tax)	September 30, 2016

Depreciation and Amortization
Accelerated depreciation^(a)	$	459
Accelerated nuclear fuel amortization	37
Operating and Maintenance
Increase ARO accretion, net of contractual offset^(b)	2
Contractual offset for ARC depreciation^(b)	(55		)
Total	$	443

_________


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

(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.

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.

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, NYPSC issued an order adopting the Clean Energy Standard (CES), which would provide payments to Ginna and Nine Mile Point for the environmental attributes of their production. Subject to Ginna and Nine Mile Point entering into a satisfactory contract with the NYSERDA, as required under the CES, and 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 approved RSSA currently requires Ginna to continue operating through the RSSA term expiring in March 2017. If Ginna does not plan to retire shortly after the expiration of the RSSA, notification to that effect was required to be filed with the NYPSC no later than September 30, 2016. 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. Negotiations with NYSERDA are ongoing and contract execution is currently targeted for completion in the fourth quarter of 2016. Refer to Note 5 - Regulatory Matters for additional discussion on the Ginna RSSA and the New York CES.

The following table provides the balance sheet amounts as of September 30, 2016 for significant assets and liabilities associated with the three nuclear plants currently considered by management to be at the greatest risk of early retirement due to current economic valuations and other factors.



(in millions)	TMI			Ginna			NMP
Asset Balances
Materials and supplies inventory	$	39		$	31		$	70
Nuclear fuel inventory, net	93			41			214
Completed plant, net	956			124			1,151
Construction work in progress	38			13			53
Liability Balances
Asset retirement obligation	(492		)	(667		)	(780		)

NRC License Renewal Term	2034			2029			2029 (unit 1)
							2046 (unit 2)

Assuming the successful implementation of the CES and its continued effectiveness, Generation and CENG would no longer consider Ginna and Nine Mile Point to be at heightened risk of early retirement; however, absent the CES for the full expected duration they will remain at heightened risk. The precise timing of an early retirement date for any of these plants, 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 obligations, where applicable, and just prior to its next scheduled nuclear refueling outage.

Fair Value of Financial Assets and Liabilities (All Registrants)

9 Months Ended

Sep. 30, 2016

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities (All Registrants)

8. 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, trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) and preferred stock as of September 30, 2016 and December 31, 2015:

Exelon



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	567	$	—	$	567	$	—	$	567
Long-term debt (including amounts due within one year)^(a)	34,842		1,075		34,272		2,279		37,626
Long-term debt to financing trusts^(b)	642		—		—		692		692
SNF obligation	1,023		—		856		—		856



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	40	$	—	$	40	$	—	$	40
Long-term debt (including amounts due within one year)^(a)	9,255		—		8,015		1,684		9,699
SNF obligation	1,023		—		856		—		856



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	10	$	—	$	10	$	—	$	10
Long-term debt (including amounts due within one year)^(a)	7,031		—		8,081		—		8,081
Long-term debt to financing trusts^(b)	205		—		—		218		218



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,879	$	—	$	3,266	$	—	$	3,266
Long-term debt to financing trusts	184		—		—		207		207



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,662	$	—	$	2,966	$	—	$	2,966
Long-term debt to financing trusts^(b)	252		—		—		267		267



	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



	September 30, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	517	$	—	$	517	$	—	$	517
Long-term debt (including amounts due within one year)	6,044		—		5,698		594		6,292



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,350	$	—	$	3,000	$	2	$	3,002



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	17	$	—	$	17	$	—	$	17
Long-term debt (including amounts due within one year)^(a)	1,265		—		1,277		101		1,378



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,167	$	—	$	1,058	$	299	$	1,357



	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 $204 million, $68 million, $47 million, $16 million, $15 million, $30 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of September 30, 2016. Includes unamortized debt issuance costs 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 September 30, 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 electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. 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 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 estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025.

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

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 16 - 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 nine months ended September 30, 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 2 - New Accounting Pronouncements 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 September 30, 2016 and December 31, 2015:



	Generation										Exelon
As of September 30, 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)	$	94	$	—	$	—	$	—	$	94	$	1,645	$	—	$	—	$	—	$	1,645
NDT fund investments
Cash equivalents^(b)	163		20		—		—		183		163		20		—		—		183
Equities	3,566		335		—		1,992		5,893		3,566		335		—		1,992		5,893
Fixed income
Corporate debt	—		1,629		257		—		1,886		—		1,629		257		—		1,886
U.S. Treasury and agencies	1,363		33		—		—		1,396		1,363		33		—		—		1,396
Foreign governments	—		50		—		—		50		—		50		—		—		50
State and municipal debt	—		268		—		—		268		—		268		—		—		268
Other^(c)	—		56		—		510		566		—		56		—		510		566
Fixed income subtotal	1,363		2,036		257		510		4,166		1,363		2,036		257		510		4,166
Middle market lending	—		—		436		23		459		—		—		436		23		459
Private equity	—		—		—		138		138		—		—		—		138		138
Real estate	—		—		—		306		306		—		—		—		306		306
NDT fund investments subtotal^(d)	5,092		2,391		693		2,969		11,145		5,092		2,391		693		2,969		11,145
Pledged assets for Zion Station decommissioning
Cash equivalents	14		—		—		—		14		14		—		—		—		14
Equities	—		1		—		—		1		—		1		—		—		1
Fixed income
U.S. Treasury and agencies	28		2		—		—		30		28		2		—		—		30
Corporate debt	—		3		—		—		3		—		3		—		—		3



	Generation														Exelon
As of September 30, 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 subtotal	28			5			—			—		33			28			5			—			—		33
Middle market lending	—			—			19			68		87			—			—			19			68		87
Pledged assets for Zion Station decommissioning subtotal^(e)	42			6			19			68		135			42			6			19			68		135
Rabbi trust investments
Cash equivalents	10			—			—			—		10			83			—			—			—		83
Mutual funds	19			—			—			—		19			50			—			—			—		50
Fixed income	—			—			—			—		—			—			14			—			—		14
Life insurance contracts	—			18			—			—		18			—			64			21			—		85
Rabbi trust investments subtotal	29			18			—			—		47			133			78			21			—		232
Commodity derivative assets
Economic hedges	883			2,790			1,948			—		5,621			884			2,790			1,948			—		5,622
Proprietary trading	11			51			36			—		98			11			51			36			—		98
Effect of netting and allocation of collateral^(f)	(927		)	(2,527		)	(896		)	—		(4,350		)	(928		)	(2,527		)	(896		)	—		(4,351		)
Commodity derivative assets subtotal	(33		)	314			1,088			—		1,369			(33		)	314			1,088			—		1,369
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			39			—			—		39
Economic hedges	—			28			—			—		28			—			28			—			—		28
Proprietary trading	7			1			—			—		8			7			1			—			—		8
Effect of netting and allocation of collateral	(4		)	(17		)	—			—		(21		)	(4		)	(17		)	—			—		(21		)
Interest rate and foreign currency derivative assets subtotal	3			12			—			—		15			3			51			—			—		54
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,227			2,741			1,842			3,037		12,847			6,882			2,840			1,863			3,037		14,622
Liabilities
Commodity derivative liabilities
Economic hedges	(1,037		)	(2,917		)	(1,160		)	—		(5,114		)	(1,037		)	(2,917		)	(1,404		)	—		(5,358		)
Proprietary trading	(10		)	(53		)	(39		)	—		(102		)	(10		)	(53		)	(39		)	—		(102		)
Effect of netting and allocation of collateral^(f)	1,012			2,777			1,046			—		4,835			1,012			2,777			1,046			—		4,835
Commodity derivative liabilities subtotal	(35		)	(193		)	(153		)	—		(381		)	(35		)	(193		)	(397		)	—		(625		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(18		)	—			—		(18		)	—			(18		)	—			—		(18		)
Economic hedges	—			(19		)	—			—		(19		)	—			(19		)	—			—		(19		)
Proprietary trading	(6		)	—			—			—		(6		)	(6		)	—			—			—		(6		)
Effect of netting and allocation of collateral	8			16			—			—		24			8			16			—			—		24
Interest rate and foreign currency derivative liabilities subtotal	2			(21		)	—			—		(19		)	2			(21		)	—			—		(19		)
Deferred compensation obligation	—			(32		)	—			—		(32		)	—			(131		)	—			—		(131		)
Total liabilities	(33		)	(246		)	(153		)	—		(432		)	(33		)	(345		)	(397		)	—		(775		)
Total net assets	$	5,194		$	2,495		$	1,689		$	3,037	$	12,415		$	6,849		$	2,495		$	1,466		$	3,037	$	13,847



	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
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
NDT 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		)



	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
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
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 $282 million and $329 million at September 30, 2016 and December 31, 2015 and restricted cash of $161 million and $121 million at September 30, 2016 and December 31, 2015. Exelon excludes cash of $398 million and $763 million at September 30, 2016 and December 31, 2015 and restricted cash of $197 million and $178 million at September 30, 2016 and December 31, 2015 and includes long term restricted cash of $22 million at September 30, 2016, which is reported in other deferred debits on the balance sheet.


(b)	Includes $64 million and $52 million of cash received from outstanding repurchase agreements at September 30, 2016 and December 31, 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 $(10) million and $(8) million, which have a total notional amount of $1,073 million and $1,236 million at September 30, 2016 and December 31, 2015, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of the company's exposure to credit or market loss.

(d)

Excludes net liabilities of $(69) million and $(3) million at September 30, 2016 and December 31, 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 September 30, 2016 and December 31, 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 $85 million, $250 million and $150 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2016. Collateral posted (received) from counterparties, net of collateral paid to 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 September 30, 2016 and December 31, 2015:



	ComEd											PECO										BGE
As of September 30, 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)	$	—	$	—		$	—		$	—		$	521	$	—		$	—	$	521		$	375	$	—		$	—	$	375
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		11			—		18			4		—			—		4
Total assets	—		—			—			—			528		11			—		539			379		—			—		379
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(10		)	—		(10		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities^(b)	—		—			(244		)	(244		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(244		)	(252		)	—		(10		)	—		(10		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	—	$	(8	)	$	(244	)	$	(252	)	$	528	$	1		$	—	$	529		$	379	$	(4	)	$	—	$	375



	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 $44 million and $38 million at September 30, 2016 and December 31, 2015 and restricted cash of $2 million and $2 million at September 30, 2016 and December 31, 2015. PECO excludes cash of $27 million and $27 million at September 30, 2016 and December 31, 2015 and $1 million of restricted cash at September 30, 2016. BGE excludes cash of $13 million and $6 million at September 30, 2016 and December 31, 2015 and restricted cash of $2 million and $2 million at September 30, 2016 and December 31, 2015 and includes long term restricted cash of $3 million at September 30, 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 $225 million, respectively, at September 30, 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 September 30, 2016 and December 31, 2015:



	Successor											Predecessor
	As of September 30, 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)	$	347		$	—		$	—	$	347		$	42		$	—		$	—	$	42
Mark-to-market derivative assets^(b)(c)	1			—			—		1			—			—			18		18
Effect of netting and allocation of collateral	(1		)	—			—		(1		)	—			—			—		—
Mark-to-market derivative assets subtotal	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			14			—		14			—			15			—		15
Life insurance contracts	—			22			21		43			—			27			19		46
Rabbi trust investments subtotal	73			36			21		130			12			42			19		73
Total assets	420			36			21		477			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	$	420		$	8		$	21	$	449		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of September 30, 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)	$	127	$	—		$	—	$	127		$	—		$	—		$	—	$	—		$	194	$	—	$	—	$	194
Mark-to-market derivative assets^(b)	—		—			—		—			1			—			—		1			—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			(1		)	—			—		(1		)	—		—		—		—
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		14			—		14			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			21		43			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		36			21		100			—			—			—		—			—		—		—		—
Total assets	170		36			21		227			—			—			—		—			194		—		—		194
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	170	$	31		$	21	$	222		$	—		$	(1	)	$	—	$	(1	)	$	194	$	—	$	—	$	194



	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	$	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 $20 million and $16 million at September 30, 2016 and December 31, 2015 and includes long term restricted cash of $19 million and $18 million at September 30, 2016 and December 31, 2015 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $8 million and $5 million at September 30, 2016 and December 31, 2015. DPL excludes cash of $4 million and $5 million at September 30, 2016 and December 31, 2015. ACE excludes cash of $5 million and $3 million at September 30, 2016 and December 31, 2015 and includes long term restricted cash of $19 million and $18 million at September 30, 2016 and December 31, 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 16 - 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 three and nine months ended September 30, 2016 and 2015:




																			Successor
	Generation															ComEd			PHI					Exelon
Three Months Ended September 30, 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 June 30, 2016	$	715		$	25		$	609			$	37	$	1,386		$	(221	)	$	20	$	—		$	1,185
Total realized / unrealized gains (losses)
Included in net income	(4		)	—			95			^(b)	1		92			—			1		—			93
Included in noncurrent payables to affiliates	6			—			—				—		6			—			—		(6		)	—
Included in payable for Zion Station decommissioning	—			(1		)	—				—		(1		)	—			—		—			(1		)
Included in regulatory assets	—			—			—				—		—			(23		)	—		6			(17		)
Change in collateral	—			—			31				—		31			—			—		—			31
Purchases, sales, issuances and settlements
Purchases	4			—			207			^(d)	3		214			—			—		—			214
Sales	—			(5		)	(2		)		—		(7		)	—			—		—			(7		)
Issuances	—			—			—				—		—			—			—		—			—
Settlements	(28		)	—			—				—		(28		)	—			—		—			(28		)
Transfers into Level 3	—			—			(1		)		1		—			—			—		—			—
Transfers out of Level 3	—			—			(4		)		—		(4		)	—			—		—			(4		)
Balance at September 30, 2016	$	693		$	19		$	935			$	42	$	1,689		$	(244	)	$	21	$	—		$	1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016	$	3		$	—		$	285			$	—	$	288		$	—		$	—	$	—		$	288



																				Successor
	Generation																ComEd			PHI^(c)						Exelon
Nine Months Ended September 30, 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 December 31, 2015	$	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	2				—			(339		)	^(b)	1		(336		)	—			2			—			(334		)
Included in noncurrent payables to affiliates	18				—			—				—		18			—			—			(18		)	—
Included in payable for Zion Station decommissioning	—				1			—				—		1			—			—			—			1
Included in regulatory assets/liabilities	—				—			—				—		—			3			—			18			21
Change in collateral	—				—			(51		)		—		(51		)	—			—			—			(51		)
Purchases, sales, issuances and settlements
Purchases	123				1			289			^(d)	7		420			—			—			—			420
Sales	(1		)		(5		)	(5		)		—		(11		)	—			—			—			(11		)
Issuances	—				—			—				—		—			—			(1		)	—			(1		)
Settlements	(119		)		—			—				—		(119		)	—			—			—			(119		)
Transfers into Level 3	—				—			1				1		2			—			—			—			2
Transfers out of Level 3	—				—			(11		)		—		(11		)	—			—			—			(11		)
Balance as of September 30, 2016	$	693			$	19		$	935			$	42	$	1,689		$	(244	)	$	21		$	—		$	1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016	$	7			$	—		$	240			$	—	$	247		$	—		$	1		$	—		$	248

___________________

(a)

Includes $25 million of decreases in fair value and realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2016. Includes $10 million of decreases in fair value and realized losses due to settlements of $13 million for the nine months ended September 30, 2016.


(b)	Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016, respectively.


(c)	Successor period represents activity from March 24, 2016 through September 30, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco and DPL for the three and nine months ended September 30, 2016.


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




	Generation															ComEd					Exelon
Three Months Ended September 30, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(a)			Eliminated in Consolidation		Total
Balance as of June 30, 2015	$	667		$	41		$	1,021			$	30	$	1,759		$	(223	)	$	—	$	1,536
Total realized / unrealized gains (losses)													—
Included in net income	—			—			(48		)	^(b)	—		(48		)	—			—		(48		)
Included in noncurrent payables to affiliates	—			—			—				—		—			—			—		—
Included in payable for Zion Station decommissioning	—			1			—				—		1			—			—		1
Included in regulatory assets	—			—			—				—		—			(20		)	—		(20		)
Change in collateral	—			—			90				—		90			—			—		90
Purchases, sales, issuances and settlements
Purchases	15			—			50				2		67			—			—		67
Sales	—			(13		)	(5		)		—		(18		)	—			—		(18		)
Settlements	(13		)	—			—				—		(13		)	—			—		(13		)
Transfers into Level 3	—			—			69				—		69			—			—		69
Transfers out of Level 3	—			—			(3		)		—		(3		)	—			—		(3		)
Balance as of September 30, 2015	$	669		$	29		$	1,174			$	32	$	1,904		$	(243	)	$	—	$	1,661
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2015	$	(1	)	$	—		$	181			$	—	$	180		$	—		$	—	$	180



	Generation															ComEd						Exelon
Nine Months Ended September 30, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(a)			Eliminated in Consolidation			Total
Balance as of December 31, 2014	$	605		$	50		$	1,050			$	3	$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income	4			—			(87		)	^(b)	—		(83		)	—			—			(83		)
Included in noncurrent payables to affiliates	17			—			—				—		17			—			(17		)	—
Included in payable for Zion Station decommissioning	—			2			—				—		2			—			—			2
Included in regulatory assets	—			—			—				—		—			(36		)	17			(19		)
Change in collateral	—			—			72				—		72			—			—			72
Purchases, sales, issuances and settlements
Purchases	122			1			107				29		259			—			—			259
Sales	(8		)	(24		)	(10		)		—		(42		)	—			—			(42		)
Settlements	(75		)	—			—				—		(75		)	—			—			(75		)
Transfers into Level 3	4			—			80				—		84			—			—			84
Transfers out of Level 3	—			—			(38		)		—		(38		)	—			—			(38		)
Balance as of September 30, 2015	$	669		$	29		$	1,174			$	32	$	1,904		$	(243	)	$	—		$	1,661
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2015	$	2		$	—		$	536			$	—	$	538		$	—		$	—		$	538

_________

(a)

Includes $19 million of decreases in fair value and a reduction for realized gains due to settlements of $1 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2015. Includes $44 million of decreases in fair value and an increase for realized losses due to settlements of $8 million for the nine months ended September 30, 2015.


(b)	Includes a reduction for the reclassification of $229 million and $623 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2015, respectively.



	Successor		Predecessor
	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015
PHI	Life Insurance Contracts		Preferred Stock		Life Insurance Contracts
Beginning Balance	$	20	$	3	$	20
Total realized / unrealized gains (losses)
Included in net income	1		15		1
Purchases, sales, issuances and settlements
Issuances	—		—		(2		)
Settlements	—		—		—
Ending Balance	$	21	$	18	$	19
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	—	$	15	$	—



	Successor			Predecessor					Predecessor
	March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016					Nine Months Ended September 30, 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	2			(18		)	1		15		4
Purchases, sales, issuances and settlements
Issuances	(1		)	—			—		—		(3		)
Settlements	—			—			—		—		(1		)
Ending Balance	$	21		$	—		$	20	$	18	$	19
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	1		$	—		$	1	$	15	$	2



	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015
	Pepco		Pepco
	Life Insurance Contracts		Life Insurance Contracts
Beginning Balance	$	20	$	20
Total realized / unrealized gains (losses)
Included in net income	1		1
Purchases, sales, issuances and settlements
Issuances	—		(3		)
Settlements	—		—
Ending Balance	$	21	$	18
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	—	$	—



	Nine Months Ended September 30, 2016			Nine Months Ended September 30, 2015
	Pepco			Pepco			DPL
	Life Insurance Contracts			Life Insurance Contracts			Life Insurance Contracts
Beginning Balance	$	19		$	18		$	1
Total realized / unrealized gains (losses)
Included in net income	3			4			—
Purchases, sales, issuances and settlements
Issuances	(1		)	(4		)	—
Settlements	—			—			(1		)
Ending Balance	$	21		$	18		$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	2		$	2		$	—

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 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 three months ended September 30, 2016	$	180		$	(85	)	$	(4	)	$	180		$	(85	)	$	(3	)
Total gains (losses) included in net income for the nine months ended September 30, 2016	(232		)	(107		)	2			(232		)	(107		)	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016	323			(38		)	3			323			(38		)	3
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016	303			(63		)	7			303			(63		)	8



	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 three months ended September 30, 2015	$	(4	)	$	(44	)	$	—		$	(4	)	$	(44	)	$	—
Total gains (losses) included in net income for the nine months ended September 30, 2015	(31		)	(56		)	4			(31		)	(56		)	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2015	198			(17		)	(1		)	198			(17		)	(1		)
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2015	538			(2		)	2			538			(2		)	2



	Successor		Predecessor
	PHI		PHI		Pepco
	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		Three Months Ended September 30, 2016		Three Months Ended September 30, 2015
	Other, net		Other, net		Other, net
Total gains (losses) included in net income	$	1	$	16	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held	—		15		—		—



	Successor		Predecessor
	PHI		PHI					Pepco
	March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016			Nine Months Ended September 30, 2015		Nine Months Ended September 30, 2016		Nine Months Ended September 30, 2015
	Other, net		Other, net					Other, net
Total gains (losses) included in net income	$	2	$	(17	)	$	19	$	3	$	4
Change in the unrealized gains (losses) relating to assets and liabilities held	1		1			17		2		2

_________


(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 16 - 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 interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized

as Level 2.

Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models and income models. Investments in 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 September 30, 2016, Generation has outstanding commitments to invest in middle market lending, private equity investments and real estate investments of approximately $170 million, $73 million, and $220 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 September 30, 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 September 30, 2016, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.

See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.

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

Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

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

Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, 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 $2.81 and $0.36 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrants' mark-to-market derivative assets and liabilities.

On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 9 —Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.

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



Type of trade	Fair Value at September 30, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	788		Discounted Cash Flow	Forward power price	$6	-	$130
					Forward gas price	$1.24	-	$9.53
				Option Model	Volatility percentage	5%	-	115%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(3	)	Discounted Cash Flow	Forward power price	$15	-	$68

Mark-to-market derivatives (Exelon and ComEd)	$	(244	)	Discounted Cash Flow	Forward heat rate^(b)	8x	-	9x
					Marketability reserve	3%	-	8%
					Renewable factor	86%	-	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 $150 million as of September 30, 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 valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.

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

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.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

+ References + Details

Derivative Financial Instruments (All Registrants)

9 Months Ended

Sep. 30, 2016

Derivative Instruments (All Registrants)

9. 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 September 30, 2016, the proportion of expected generation hedged for the major reportable segments is 98%-101%, 85%-88% and 54%-57% for 2016, 2017 and 2018, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to the Utility Registrants 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 of the Exelon 2015 Form 10-K for additional information.

PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts. 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 1,506 GWhs and 4,015 GWhs for the three and nine months ended September 30, 2016, respectively, and 1,913 GWhs and 5,378 GWhs for the three and nine months ended September 30, 2015, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO, 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 September 30, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $672 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 $5 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 2016. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of September 30, 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)	$	—		$	15		$	4		$	(10	)	$	9		$	—	$	9
Mark-to-market derivative assets (noncurrent assets)	—			13			4			(11		)	6			39		45
Total mark-to-market derivative assets	—			28			8			(21		)	15			39		54
Mark-to-market derivative liabilities (current liabilities)	(8		)	(10		)	(3		)	12			(9		)	—		(9		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(10		)	(9		)	(3		)	12			(10		)	—		(10		)
Total mark-to-market derivative liabilities	(18		)	(19		)	(6		)	24			(19		)	—		(19		)
Total mark-to-market derivative net assets (liabilities)	$	(18	)	$	9		$	2		$	3		$	(4	)	$	39	$	35

_________

(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															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)	$	—		$	10		$	10		$	(5	)	$	15		$	—	$	15
Mark-to-market derivative assets (noncurrent assets)	—			10			5			(1		)	14			25		39
Total mark-to-market derivative assets	—			20			15			(6		)	29			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	$	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:



		Three Months Ended September 30,
	Income Statement Location	2016			2015			2016			2015
	Income Statement Location	Gain (loss) on Swaps						Gain (loss) on Borrowings
Exelon	Interest expense	$	(8	)	$	16		$	14		$	(13	)

		Nine Months Ended September 30,
	Income Statement Location	2016			2015			2016			2015
	Income Statement Location	Gain (loss) on Swaps						Gain (loss) on Borrowings
Generation	Interest expense^(a)	$	—		$	(1	)	$	—		$	—
Exelon	Interest expense	15			15			(3		)	(4		)

__________


(a)	For the nine months ended September 30, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

At September 30, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $39 million. At December 31, 2015, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $25 million. During the three and nine months ended September 30, 2016, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $6 million and a $12 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 the anticipated issuance of debt. 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 10 — Debt and Credit Agreements for additional information.

During the first quarter of 2016, Exelon entered into $100 million of floating-to-fixed forward starting interest rate swap 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, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 14 —Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $496 million as of September 30, 2016 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At September 30, 2016, the subsidiary had a $15 million derivative liability related to the swap.

During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14 — Debt and Credit Agreements of the Exelon 2015 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $176 million as of September 30, 2016 and expire in 2020. The swaps are designated as cash flow hedges. At September 30, 2016, the subsidiary had a $3 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 three and nine months ended September 30, 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 of the Exelon 2015 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the issuance 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 of the Exelon 2015 Form 10-K for additional information regarding the financing. During the first quarter of 2016, upon the issuance 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 September 30, 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 commodity transactions 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 September 30, 2016 and December 31, 2015, $5 million and $3 million of cash collateral held and 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 September 30, 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)	$	3,482		$	67		$	(2,804	)	$	745		$	—		$	1	$	(1	)	$	—	$	—	$	745
Mark-to-market derivative assets (noncurrent assets)	2,139			31			(1,546		)	624			—			—		—			—		—		624
Total mark-to-market derivative assets	5,621			98			(4,350		)	1,369			—			1		(1		)	—		—		1,369
Mark-to-market derivative liabilities (current liabilities)	(3,229		)	(61		)	3,096			(194		)	(19		)	—		—			—		—		(213		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,885		)	(41		)	1,739			(187		)	(225		)	—		—			—		—		(412		)
Total mark-to-market derivative liabilities	(5,114		)	(102		)	4,835			(381		)	(244		)	—		—			—		—		(625		)
Total mark-to-market derivative net assets (liabilities)	$	507		$	(4	)	$	485		$	988		$	(244	)	$	1	$	(1	)	$	—	$	—	$	744

______

(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 $135 million and $84 million, respectively, and current and noncurrent liabilities are shown net of collateral of $156 million and $110 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $485 million at September 30, 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
Description	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 16 - 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 AOCI related to cash flow hedges for the nine months ended September 30, 2016 and 2015, containing information about the changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.




		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended September 30, 2016	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
AOCI derivative loss at June 30, 2016		$	(25	)	$	(26	)
Effective portion of changes in fair value		1			3
AOCI derivative loss at September 30, 2016		$	(24	)	$	(23	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Nine Months Ended September 30, 2016	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2015		$	(21	)		$	(19	)
Effective portion of changes in fair value		—				(1		)
Reclassifications from AOCI to net income	Interest Expense	(3		)	^(a)	(3		)	^(a)
Accumulated OCI derivative loss at September 30, 2016		$	(24	)		$	(23	)




		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended September 30, 2015	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
AOCI derivative loss at June 30, 2015		(21		)	$	(19	)
Effective portion of changes in fair value		(7		)	(8		)
Reclassifications from AOCI to net income	Interest Expense	3			3
AOCI derivative loss at September 30, 2015		$	(25	)	$	(24	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Nine Months Ended September 30, 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		(13		)	(18		)
Reclassifications from AOCI to net income	Other, net	—			16			^(b)
Reclassifications from AOCI to net income	Interest Expense	8			8
Reclassifications from AOCI to net income	Operating Revenues	(2		)	(2		)
Accumulated OCI derivative loss at September 30, 2015		$	(25	)	$	(24	)

______


(a)	Amount is net of related income tax expense of $2 million for the nine months ended September 30, 2016.


(b)	Amount is net of related income tax expense of $10 million for the nine months ended September 30, 2015.

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 AOCI to earnings was a $2 million pre-tax gain for the nine months ended September 30, 2015. There were no gains recognized for the three months ended September 30, 2015. 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 three and nine months ended September 30, 2016 and 2015, 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
Three Months Ended September 30, 2016	Operating Revenues			Purchased Power and Fuel			Total			Total
Change in fair value of commodity positions	$	280		$	(73	)	$	207		$	207
Reclassification to realized at settlement of commodity positions	(92		)	(26		)	(118		)	(118		)
Net commodity mark-to-market gains (losses)	188			(99		)	89			89
Change in fair value of treasury positions	1			—			1			1
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	(2		)
Net treasury mark-to-market gains (losses)	(1		)	—			(1		)	(1		)
Net mark-to-market gains (losses)	$	187		$	(99	)	$	88		$	88



	Generation								Exelon
Nine Months Ended September 30, 2016	Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	127		$	36	$	163		$	163
Reclassification to realized at settlement of commodity positions	(484		)	217		(267		)	(267		)
Net commodity mark-to-market gains (losses)	(357		)	253		(104		)	(104		)
Change in fair value of treasury positions	(3		)	—		(3		)	(3		)
Reclassification to realized at settlement of treasury positions	(6		)	—		(6		)	(6		)
Net treasury mark-to-market gains (losses)	(9		)	—		(9		)	(9		)
Net mark-to-market gains (losses)	$	(366	)	$	253	$	(113	)	$	(113	)




	Generation									Exelon Corporate		Exelon
Three Months Ended September 30, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense		Total
Change in fair value of commodity positions	$	136		$	(178	)	$	(42	)	$	—	$	(42	)
Reclassification to realized at settlement of commodity positions	(143		)	46			(97		)			(97		)
Net commodity mark-to-market gains (losses)	(7		)	(132		)	(139		)	—		(139		)
Change in fair value of treasury positions	2			—			2			—		2
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	—		(2		)
Net treasury mark-to-market gains (losses)	—			—			—			—		—
Net mark-to-market gains (losses)	$	(7	)	$	(132	)	$	(139	)	$	—	$	(139	)



	Generation									Exelon Corporate		Exelon
Nine Months Ended September 30, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense		Total
Change in fair value of commodity positions	$	513		$	(163	)	$	350		$	—	$	350
Reclassification to realized at settlement of commodity positions	(347		)	249			(98		)	—		(98		)
Net commodity mark-to-market gains (losses)	166			86			252			—		252
Change in fair value of treasury positions	12			—			12			36		48
Reclassification to realized at settlement of treasury positions	(6		)	—			(6		)	64		58
Net treasury mark-to-market gains (losses)	6			—			6			100		106
Net mark-to-market gains (losses)	$	172		$	86		$	258		$	100	$	358

Proprietary Trading Activities (Exelon and Generation). For the three and nine months ended September 30, 2016 and 2015, 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 revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Change in fair value of commodity positions	$	4		$	(4	)	$	18		$	5
Reclassification to realized at settlement of commodity positions	(6		)	(2		)	(17		)	(8		)
Net commodity mark-to-market gains (losses)	(2		)	(6		)	1			(3		)
Change in fair value of treasury positions	—			3			(2		)	7
Reclassification to realized at settlement of treasury positions	1			(3		)	2			(9		)
Net treasury mark-to-market gains (losses)	1			—			—			(2		)
Total net mark-to-market gains (losses)	$	(1	)	$	(6	)	$	1		$	(5	)

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 September 30, 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, further discussed in ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $24 million, $45 million,$22 million, $47 million, $12 million, and $10 million as of September 30, 2016, respectively.



Rating as of September 30, 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	$	1,017	$	4	$	1,013	1	$	355
Non-investment grade	175		22		153		—	—
No external ratings
Internally rated — investment grade	423		3		420		—	—
Internally rated — non-investment grade	61		3		58		—	—
Total	$	1,676	$	32	$	1,644	1	$	355



Net Credit Exposure by Type of Counterparty	As of September 30, 2016
Financial institutions	$	117
Investor-owned utilities, marketers, power producers	757
Energy cooperatives and municipalities	712
Other	58
Total	$	1,644

_____


(a)	As of September 30, 2016, credit collateral held from counterparties where Generation had credit exposure included $10 million of cash and $22 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 September 30, 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 of the Exelon 2015 Form 10-K for additional information.

PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of September 30, 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 5 — Regulatory Matters for additional information.

PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of September 30, 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 of the Exelon 2015 Form 10-K for additional information.

BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. 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 September 30, 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 September 30, 2016, BGE had credit exposure of less than $1 million related to off-system sales which is mitigated by parental guarantees, letters of credit or right to offset clauses within other contracts with those third-party suppliers.

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 September 30, 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 6 — Regulatory Matters of the PHI 2015 Form 10-K for additional information.

DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder. As of September 30, 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:



Credit-Risk Related Contingent Feature	September 30, 2016			December 31, 2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(975	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	664			684
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(311	)	$	(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 $501 million and letters of credit posted of $420 million and cash collateral held of $18 million and letters of credit held of $22 million as of September 30, 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 September 30, 2016 and December 31, 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 September 30, 2016, Generation's swaps were in a liability position with a fair value of $4 million and Exelon's swaps were in an asset position, with a fair value of $35 million.

See Note 25 — Segment Information of the Exelon 2015 Form 10-K for further information regarding the letters of credit supporting the cash collateral.

Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of September 30, 2016, ComEd held $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 September 30, 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 September 30, 2016, it would have been required to post approximately $17 million of collateral to its counterparties. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information.

PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2016, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2016, PECO could have been required to post approximately $25 million of collateral to its counterparties.

PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.

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

BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2016, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2016, BGE could have been required to post approximately $29 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 September 30, 2016, DPL could have been required to post an additional amount of approximately $9 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)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]

10. Debt and Credit Agreements (All Registrants)

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.

Commercial Paper

The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2016 and December 31, 2015:



Commercial Paper Borrowings	September 30, 2016		December 31, 2015
ComEd	$	10	$	294
BGE	—		210
PHI Corporate	—		484
Pepco	—		64
DPL	17		105
ACE	—		5

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 letters 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.

Variable Rate Demand Bonds

As of September 30, 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 Sheets. See Note 10 - Debt of the PHI 2015 Form 10-K for additional information.

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2016, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon Corporate	Senior Unsecured Notes	2.45	%	April 15, 2021	$	300	Repay commercial paper issued by PHI and for general corporate purposes
Exelon Corporate	Senior Unsecured Notes	3.40	%	April 15, 2026	$	750	Repay commercial paper issued by PHI and for general corporate purposes
Exelon Corporate	Senior Unsecured Notes	4.45	%	April 15, 2046	$	750	Repay commercial paper issued by PHI and for general corporate purposes
Generation	Renewable Power Generation Nonrecourse Debt	4.11	%	March 31, 2035	$	150	Paydown long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes
Generation	Albany Green Energy Project Financing	LIBOR + 1.25%		November 17, 2017	$	86	Albany Green Energy biomass generation development
Generation	Energy Efficiency Project Financing	3.17	%	December 31, 2017	$	16	Funding to install energy conservation measures in Brooklyn, NY
Generation	Energy Efficiency Project Financing	3.42	%	January 31, 2018	$	13	Funding to install energy conservation measures for the Naval Station Great Lakes project
ComEd	First Mortgage Bonds, Series 120	2.55	%	June 15, 2026	$	500	Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes
ComEd	First Mortgage Bonds, Series 121	3.65	%	June 15, 2046	$	700	Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes
Generation	Energy Efficiency Project Financing	3.52	%	April 30, 2018	$	11	Funding to install energy conservation measures for the Smithsonian Zoo project
Pepco	Energy Efficiency Project Financing	3.30	%	December 15, 2017	$	2	Funding to install energy conservation measures for the DOE Germantown project
BGE	Notes	2.40	%	August 15, 2026	$	350	Redeem the $190M of outstanding preference shares and for general corporate purposes
BGE	Notes	3.50	%	August 15, 2046	$	500	Redeem the $190M of outstanding preference shares and for general corporate purposes
PECO^(a)	First Mortgage Bonds	1.70	%	September 15, 2021	$	300	Refinance maturing mortgage bonds
Generation	SolGen Nonrecourse Debt	3.93	%	September 30, 2036	$	150	General corporate purposes
Generation	ExGen Texas Power Nonrecourse Debt	LIBOR + 4.25%		September 18, 2019	$	4	General corporate purposes for EGTP

________________

(a)

Includes restricted proceeds of $30 million shown in the Restricted proceeds from issuance of long-term debt on Exelon’s and PECO’s Cash Flow Statements and Restricted cash and cash equivalents on Exelon’s and PECO’s Consolidated Balance Sheets. The restricted proceeds were used as a portion of the payment on the maturing mortgage bonds due October 15, 2016, and as of that date, the restriction is no longer in place.

CEU Upstream Nonrecourse Debt

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 that it owns. 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 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 have sent CEU Holdings a notice of event of default and demand for cure. On March 31, 2016, $7 million of the debt was repaid using CEU Holding's cash, resulting in an outstanding debt balance of $61 million with interest payable monthly at a variable rate equal to LIBOR plus 2.75% and a borrowing base deficiency under the RBL of $16 million. At March 31, 2016, the outstanding debt balance of $61 million was classified within Long-term debt due within one year on Exelon's and Generation's Consolidated Balance Sheets.

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, with ultimate execution of the sales agreement expected to occur by December 31, 2016. Upon disposition 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. See Note 14 - Debt and Credit Agreements of the Exelon 2015 Form 10-K, Note 5 - Mergers, Acquisitions and Dispositions and Note 6 - Impairment of Long-Lived Assets for additional information.

Income Taxes (All Registrants)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Income Taxes (All Registrants)

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



	Three Months Ended September 30, 2016
						Successor
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.8	2.6	7.3	2.4	5.2	5.6	5.6	5.2	6.1
Qualified nuclear decommissioning trust fund income	4.0	7.8	—	—	—	—	—	—	—
Domestic production activities deduction	—	—	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	—	—	—	—	—
Amortization of investment tax credit, net deferred taxes	(0.9)	(1.6)	(0.6)	(0.1)	(0.2)	(0.1)	—	(0.2)	(0.1)
Plant basis differences	(3.0)	—	(1.9)	(6.7)	(0.5)	(5.0)	(6.7)	(1.3)	(4.6)
Production tax credits and other credits	(2.9)	(5.7)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	0.2	0.5	—	—	—	—	—	—	—
Statute of limitations expiration	(0.1)	0.3	—	—	—	—	—	—	—
Penalties	4.3	—	27.2	—	—	—	—	—	—
Merger expenses	(0.6)	—	—	—	—	(5.7)	(2.3)	(8.6)	(2.9)
Other	(0.8)	(0.5)	0.1	0.1	(0.4)	(0.7)	(0.9)	0.1	(0.6)
Effective income tax rate	39.0%	38.4%	67.0%	30.7%	39.1%	29.1%	30.7%	30.2%	32.9%



	Three Months Ended September 30, 2015
						Predecessor
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	2.7	2.1	5.0	1.2	5.3	6.2	4.8	7.4	5.4
Qualified nuclear decommissioning trust fund income	(5.4)	(12.5)	—	—	—	—	—	—	—
Domestic production activities deduction	(4.9)	(11.6)	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	0.2	—	—	—	—
Amortization of investment tax credit, net deferred taxes	(2.3)	(5.2)	(0.3)	(0.1)	(0.2)	(0.2)	(0.1)	(0.6)	(0.3)
Plant basis differences	(1.4)	—	(0.1)	(7.0)	(0.6)	(3.7)	(3.5)	(3.5)	(3.1)
Production tax credits and other credits	(3.8)	(9.0)	—	—	—	(1.2)	—	—	—
Noncontrolling interests	1.7	3.9	—	—	—	—	—	—	—
Statute of limitations expiration	(6.4)	(15.2)	—	—	—	—	—	—	—
Other	1.2	0.4	0.3	—	(0.4)	(1.1)	(1.4)	(0.8)	1.9
Effective income tax rate	16.4%	(12.1)%	39.9%	29.1%	39.3%	35.0%	34.8%	37.5%	38.9%



									Successor	Predecessor
	Nine Months Ended September 30, 2016								March 24, 2016 to September 30, 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)	2.5	2.6	5.4	1.3	4.8	23.0	310.5	5.5	4.4	11.9
Qualified nuclear decommissioning trust fund income	4.8	8.8	—	—	—	—	—	—	—	—
Domestic production activities deduction	—	—	—	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.3)	(2.0)	(0.3)	(0.1)	(0.2)	(0.2)	(17.9)	0.5	0.5	(0.9)
Plant basis differences	(4.5)	—	(0.6)	(8.8)	(3.3)	(29.0)	(98.6)	7.8	17.5	(13.5)
Production tax credits and other credits	(4.1)	(7.6)	—	—	—	—	—	—	—	—
Noncontrolling interests	0.5	0.9	—	—	—	—	—	—	—	—
Statute of limitations expiration	(0.5)	(1.7)	—	—	—	—	—	—	—
Penalties	2.3	—	5.6	—	—	—	—	—	—
Merger expenses	6.2	—	—	—	—	36.7	635.9	(35.4)	(49.8)	11.1
Other^(c)	(1.8)	(2.1)	—	(1.5)	—	(2.5)	35.1	0.4	1.4	3.6
Effective income tax rate	39.1%	33.9%	45.1%	25.9%	36.3%	63.0%	900.0%	13.8%	9.0%	47.2%



	Nine Months Ended September 30, 2015
						Predecessor
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.1	2.8	5.2	1.2	5.3	7.1	4.6	6.1	5.5
Qualified nuclear decommissioning trust fund income	(0.9)	(1.6)	—	—	—	—	—	—	—
Domestic production activities deduction	(2.8)	(4.9)	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	0.2	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(1.9)	(0.3)	(0.1)	(0.1)	(0.3)	(0.1)	(0.4)	(0.5)
Plant basis differences	(1.2)	—	(0.1)	(7.3)	(0.4)	(5.0)	(6.2)	(2.0)	(2.5)
Production tax credits and other credits	(2.2)	(3.8)	—	—	—	(1.9)	—	—	—
Noncontrolling interests	—	0.1	—	—	—	—	—	—	—
Statute of limitations expiration	(1.6)	(2.9)	—	—	—	—	—	—	—
Other	0.9	0.6	0.2	0.2	(0.1)	(0.1)	(0.7)	(0.5)	0.8
Effective income tax rate	29.1%	23.4%	40.0%	29.0%	39.9%	34.8%	32.6%	38.2%	38.3%


(a)	DPL and ACE recognized a loss before income taxes for the nine months ended September 30, 2016, and PHI recognized a loss before income taxes for the period of March 24, 2016, through September 30, 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.

Accounting for Uncertainty in Income Taxes

The Registrants have the following unrecognized tax benefits as of September 30, 2016 and December 31, 2015:



												Successor
	Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE
September 30, 2016	$	937	$	516	$	(12	)	$	—	$	120	$	157	$	79	$	34	$	22



											Predecessor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
December 31, 2015	$	1,101	$	534	$	142	$	—	$	120	$	22	$	8	$	3	$	—

Exelon and ComEd’s unrecognized tax benefits changed by $328 million and $154 million, respectively, as of September 30, 2016 as a result of the lease termination on the like-kind exchange position discussed below. In addition, as a result of the merger, an assessment and remeasurement of certain federal and state uncertain income tax positions resulted in an increase in unrecognized tax benefits at Exelon, PHI, Pepco, DPL and ACE of $164 million, $135 million, $71 million, $31 million and $22 million, respectively.

Reasonably possible the 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 September 30, 2016, Exelon, Generation, BGE, PHI, Pepco, and DPL have approximately $251 million, $52 million, $120 million, $79 million, $59 million, and $20 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits and potential settlements. Of the above unrecognized tax benefits, Exelon and Generation have $52 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, DPL, and a portion of Pepco, if recognized, may be included in future regulated base rates and that portion would have no impact to the effective tax rate.

Other Income Tax Matters

Like-Kind Exchange (Exelon and ComEd)

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

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 early 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 recorded a charge to earnings for the penalty and the after-tax interest due on the asserted penalty of approximately $200 million, of which approximately $150 million was recorded at ComEd. Exelon and ComEd recorded the penalty and 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 sheet 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, penalties and interest at the time Exelon files its appeal (expected early 2017). While the final calculation of tax, penalties 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 first quarter of 2017. While Exelon will receive a tax benefit of $400 million associated with the deduction for the interest, Exelon currently has 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.

As of September 30, 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 first quarter 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.

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 a state tax expense of $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.

Nuclear Decommissioning (Exelon and Generation)

9 Months Ended

Sep. 30, 2016

Environmental Remediation Obligations [Abstract]

Nuclear Decommissioning (Exelon and Generation)

Nuclear Decommissioning Asset Retirement Obligations

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

The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2015 to September 30, 2016:



Nuclear decommissioning ARO at December 31, 2015^(a)	$	8,246
Accretion expense	325
Net increase due to changes in, and timing of, estimated cash flows	444
Costs incurred to decommission retired plants	(6		)
Nuclear decommissioning ARO at September 30, 2016^(a)	$	9,009

_________


(a)	Includes $44 million and $7 million for the current portion of the ARO at September 30, 2016 and December 31, 2015, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the nine months ended September 30, 2016, Generation’s nuclear ARO increased by approximately $763 million, reflecting impacts of ARO updates completed during the first and second quarters of 2016 to reflect changes in amounts and timing of estimated decommissioning cash flows and impacts of year-to-date accretion of the ARO liability due to the passage of time.

In 2016, the ARO liability increased by $444 million primarily driven by an increase of $384 million associated with the June 2, 2016 announcement to early retire the Clinton and Quad Cities nuclear units on June 1, 2017 and June 1, 2018, respectively, as well as an increase of $60 million primarily due to an increase in the estimated costs to decommission the Oyster Creek nuclear unit as a result of the completion of an updated decommissioning cost study. Refer to Note 7 - Early Nuclear Plant Retirements for additional information regarding the announced early retirements of Clinton and Quad Cities. The increase in the ARO liability for Clinton and Quad Cities incorporates the early shutdown dates (including fleet-wide impacts of spent nuclear fuel removal and storage costs), increases in the assumed probabilities of longer term decommissioning scenarios, and reflects an increase in the estimated costs to decommission based on updated decommissioning cost studies reflecting the early retirement of these units.

The financial statement impact related to the increase in the ARO liability due to the changes in, and timing of, estimated cash flows resulted in a corresponding increase in Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. The majority of the increase in cost will be amortized over the remaining useful lives of the Clinton, Quad Cities and Oyster Creek nuclear plants, which are set to retire in 2017, 2018 and 2019, respectively.

Nuclear Decommissioning Trust Fund Investments

At September 30, 2016 and December 31, 2015, Exelon and Generation had NDT fund investments totaling $11,076 million and $10,342 million, respectively.

The following table provides unrealized gains on NDT funds for the three and nine months ended September 30, 2016 and 2015:



	Exelon and Generation					Exelon and Generation
	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units^(a)	$	155	$	(301	)	$	286	$	(385	)
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	116		(218		)	216		(274		)

_________


(a)	Net unrealized gains 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 $(5) million of net unrealized gain related to the Zion Station pledged assets for the three months ended September 30, 2016. Excludes $(2) million and $9 million of net unrealized gain related to the Zion Station pledged assets for the nine months ended September 30, 2016 and 2015, 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 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.

Refer to Note 3 — Regulatory Matters and Note 26 — Related Party Transactions of the Exelon 2015 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.

Zion Station Decommissioning

On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for completing certain decommissioning activities at Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.

ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, are recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $87 million which is included within the nuclear decommissioning ARO at September 30, 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 September 30, 2016 and December 31, 2015:



	Exelon and Generation
	September 30, 2016		December 31, 2015
Carrying value of Zion Station pledged assets	$	135	$	206
Payable to Zion Solutions^(a)	124		189
Current portion of payable to Zion Solutions^(b)	91		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)	855		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.

NRC Minimum Funding Requirements

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

Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status of decommissioning funding assurance as of December 31, 2014. Due to increased cost estimates received in the second half of 2014, Braidwood Units 1 and 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 to the NRC an updated decommissioning funding status report for Braidwood Units 1 and 2, and Byron Unit 2. This updated report reflected the recently approved license renewals for these units, and showed that the shortfall identified in the March 31, 2015 report has now been resolved and that Generation has provided adequate decommissioning funding assurance for each unit.

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 except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). As of December 31, 2015, Generation provided adequate decommissioning funding assurance for all of its reactors that have been shut down or are within five years of shut down 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 in Note 16 - Asset Retirement Obligations of Exelon's 2015 Form 10-K, 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 and will reflect the impacts of the announced early retirements of Clinton and Quad Cities. A shortfall could require Exelon to post parental guarantees for Generation's share of the funding assurance. However, the amount of any required guarantees will ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust fund investment performance going forward.

Retirement Benefits (All Registrants)

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

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

Retirement Benefits (All Registrants)

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all 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. The legacy PHI pension and other postretirement benefit plans were initially remeasured on February 29, 2016 as a result of the short time between the merger close and the end of the first quarter of 2016, using current assumptions, including the discount rate. Exelon updated these amounts in June 2016 to reflect assumptions at March 31, 2016. The updated valuation resulted in a $25 million reduction in the net obligation.

Defined Benefit Pension and Other Postretirement Benefits

During the first quarter of 2016, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2016. This valuation resulted in an increase to the pension obligation of $35 million and a decrease to the other postretirement benefit obligation of $8 million. Additionally, accumulated other comprehensive loss increased by approximately $2 million (after tax), regulatory assets increased by approximately $27 million, and regulatory liabilities increased by approximately $3 million.

The majority of the 2016 pension benefit cost for legacy Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 4.29%. The majority of the 2016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.71% for funded plans and a discount rate of 4.29%.

The 2016 pension benefit costs for the legacy PHI plans are calculated using an expected long-term rate of return on plan assets of 6.50% and a discount rate of 3.96% for the majority of the pension plans. The 2016 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.75% and a discount rate of 3.80%.

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and nine months ended September 30, 2016 and 2015.



	Pension Benefits Three Months Ended September 30,						Other Postretirement Benefits Three Months Ended September 30,
Components of net periodic benefit cost:	2016			2015			2016			2015
Service cost	$	92		$	82		$	27		$	30
Interest cost	215			178			47			42
Expected return on assets	(293		)	(257		)	(42		)	(38		)
Amortization of:
Prior service cost (benefit)	3			3			(48		)	(43		)
Actuarial loss	142			142			18			20
Net periodic benefit cost	$	159		$	148		$	2		$	11



	Pension Benefits Nine Months Ended September 30,						Other Postretirement Benefits Nine Months Ended September 30,
	2016^(a)			2015			2016^(a)			2015
Components of net periodic benefit cost:
Service cost	$	262		$	245		$	80		$	89
Interest cost	616			533			138			125
Expected return on assets	(847		)	(770		)	(121		)	(113		)
Amortization of:
Prior service cost (benefit)	10			10			(138		)	(130		)
Actuarial loss	411			427			47			60
Net periodic benefit cost	$	452		$	445		$	6		$	31

_______


(a)	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.



	Predecessor
	PHI
	Pension Benefits									Other Postretirement Benefits
Components of net periodic benefit cost:	January 1, 2016 to March 23, 2016			Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015			January 1, 2016 to March 23, 2016			Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Service cost	$	12		$	15		$	43		$	1		$	2		$	5
Interest cost	26			28			82			6			6			18
Expected return on assets	(30		)	(35		)	(105		)	(5		)	(6		)	(17		)
Amortization of:
Prior service cost (benefit)	—			—			1			(3		)	(3		)	(9		)
Actuarial loss	14			16			49			2			2			6
Net periodic benefit cost	$	22		$	24		$	70		$	1		$	1		$	3

The amounts below represent Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, DPL's, ACE's, BSC's and PHISCO's allocated portion of the pension and postretirement benefit plan costs, which were included in Property, plant and equipment within the respective Consolidated Balance Sheets and Operating and maintenance expense within the Consolidated Statement of Operations and Comprehensive Income during the three and nine months ended September 30, 2016 and 2015.



	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs	2016		2015		2016		2015
Exelon	$	161	$	159	$	458	$	476
Generation	54		67		163		200
ComEd	41		52		124		155
PECO	8		10		25		29
BGE	17		16		51		49
BSC^(a)	13		14		37		43
Pepco^(b)	8		7		24		22
DPL^(b)	4		3		13		11
ACE^(b)	4		3		11		11
PHISCO^(a)(b)	12		12		33		29



	Successor		Predecessor		Successor		Predecessor
Pension and Other Postretirement Benefit Costs	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016		Nine Months Ended September 30, 2015
PHI	$	28	$	25	$	58	$	23	$	73

_________


(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, PHI, Pepco, DPL or ACE amounts above.


(b)	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2016 and 2015:



	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2016		2015		2016		2015
Exelon	$	51	$	51	$	107	$	111
Generation	31		27		56		60
ComEd	10		10		23		23
PECO	3		3		7		7
BGE	2		5		5		10
BSC^(a)	2		6		9		11
Pepco^(b)	—		—		2		2
DPL^(b)	1		1		2		2
ACE^(b)	—		—		1		1
PHISCO^(a)(b)	2		2		5		5



	Successor		Predecessor		Successor		Predecessor
Savings Plan Matching Contributions	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016		Nine Months Ended September 30, 2015
PHI	$	3	$	3	$	7	$	3	$	10

_________


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


(b)	Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million,and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016.

Severance (All Registrants)

9 Months Ended

Sep. 30, 2016

Restructuring Charges [Abstract]

Severance (All Registrants)

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

Ongoing Severance Plans

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

For the three and nine months ended September 30, 2016 and 2015, Exelon, Generation, ComEd and PHI recorded the following severance costs (benefits) associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income.



									Successor
	Exelon			Generation^(a)			ComEd^(a)		PHI
Three Months Ended
September 30, 2016	$	8		$	7		$	—	$	1
September 30, 2015	(3		)	(3		)	—		—

Nine Months Ended
September 30, 2016	$	12		$	10		$	1	$	1
September 30, 2015	18			17			1		—

_______

(a) The amounts above for Generation include less than $1 million for amounts billed by BSC through intercompany allocations for both the three months ended September 30, 2016 and 2015, and $2 million for both the nine months ended September 30, 2016 and 2015. The amounts above for ComEd include $1 million billed by BSC through intercompany allocations for both the nine months ended September 30, 2016 and 2015. The amounts above for PHI include $1 million billed by BSC through intercompany allocations for the three and nine months ended September 30, 2016.

Early Plant Retirement-Related Severance

As a result of the Clinton and Quad Cities plant retirement decision, Exelon and Generation will incur certain employee-related costs, including severance benefit costs. Severance benefits will be provided to impacted union and non-union employees, to the extent that those employees are not redeployed to other locations. The final amount of severance cost will ultimately depend on the specific employees severed.

For the three and nine months ended September 30, 2016, the Registrants recorded the following severance costs (benefits) related to the early plant retirements 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^(a)
Three Months Ended
September 30, 2016	$	(2	)	$	(2	)

Nine Months Ended
September 30, 2016	$	44		$	44

(a) The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended

September 30, 2016.

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.

Upon Senior Management approval of the cost management targets and initiatives in the first quarter of 2016, Exelon recorded severance benefit costs of $17 million associated with the anticipated position reductions. Additional severance benefit costs recorded in the third quarter were $1 million for Generation and Exelon. The final amount of the charge will ultimately depend on the specific employees severed.

For the nine months ended September 30, 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
Nine Months Ended September 30, 2016
Severance benefits^(a)	$	18	$	13	$	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 nine months ended September 30, 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 three months ended September 30, 2016, the PHI merger severance costs were immaterial. For the nine months ended September 30, 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
Nine Months Ended September 30, 2016
Severance benefits^(a)	$	55	$	9	$	2	$	1	$	1	$	42	$	20	$	12	$	10

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include amounts billed by BSC and/or PHISCO through intercompany allocations of $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million for the nine months ended September 30, 2016.


(b)	Pepco established a regulatory asset of $10 million as of September 30, 2016, primarily for severance benefit costs related to the PHI merger.


(c)	DPL established a regulatory asset of $3 million as of September 30, 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 the severance plans above 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			Pepco			DPL			ACE
Balance at December 31, 2015	$	35		$	23		$	3		$	—	$	1		$	—		$	—		$	—		$	—
Severance charges^(a)(b)	136			63			1			—		—			53			1			1			—
Payments	(39		)	(7		)	(1		)	—		(1		)	(25		)	(1		)	(1		)	—
Balance at September 30, 2016	$	132		$	79		$	3		$	—	$	—		$	28		$	—		$	—		$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration, the Clinton and Quad Cities early plant retirements and the cost management program.


(b)	Represents activity from March 24, 2016 to September 30, 2016 for PHI, Pepco, DPL and ACE.

Mezzanine Equity Mezzanine Equity (Exelon, Generation and PHI)

9 Months Ended

Sep. 30, 2016

Noncontrolling Interest [Abstract]

Noncontrolling Interest Disclosure (Exelon, Generation and PHI)

16. 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 nine months ended September 30, 2016:



Balance at December 31, 2015	$	28
Cash received from noncontrolling interests	105
Release of contingency	(107		)
Balance at September 30, 2016	$	26

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 PHI's Consolidated Balance Sheets. 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, Consolidated 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.

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

9 Months Ended

Sep. 30, 2016

Changes in Accumulated Other Comprehensive Income [Abstract]

Comprehensive Income (Loss) Note [Text Block]

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 nine months ended September 30, 2016 and 2015:



Nine Months Ended September 30, 2016	Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments			Total
Exelon^(a)
Beginning balance	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)
OCI before reclassifications	(1		)	—		(2		)	3			(5		)	(5		)
Amounts reclassified from AOCI^(b)	(3		)	—		104			5			—			106
Net current-period OCI	(4		)	—		102			8			(5		)	101
Ending balance	$	(23	)	$	3	$	(2,463	)	$	(32	)	$	(8	)	$	(2,523	)
Generation^(a)
Beginning balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	—			1		—			3			1			5
Amounts reclassified from AOCI^(b)	(3		)	—		—			5			—			2
Net current-period OCI	(3		)	1		—			8			1			7
Ending balance	$	(24	)	$	2	$	—		$	(32	)	$	(2	)	$	(56	)
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	)



Nine Months Ended September 30, 2015	Gains and (losses) on Hedging Activity			Unrealized Gains and (losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments		Total
Exelon^(a)
Beginning balance	$	(28	)	$	3	$	(2,640	)	$	(19	)	$	—	$	(2,684	)
OCI before reclassifications	(18		)	—		(29		)	(17		)	—		(64		)
Amounts reclassified from AOCI^(b)	22			—		130			—			—		152
Net current-period OCI	4			—		101			(17		)	—		88
Ending balance	$	(24	)	$	3	$	(2,539	)	$	(36	)	$	—	$	(2,596	)
Generation^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—	$	(36	)
OCI before reclassifications	(13		)	—		—			(17		)	—		(30		)
Amounts reclassified from AOCI^(b)	6			—		—			—			—		6
Net current-period OCI	(7		)	—		—			(17		)	—		(24		)
Ending balance	$	(25	)	$	1	$	—		$	(36	)	$	—	$	(60	)
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	—			—		—			—			—		—
Amounts reclassified from AOCI^(b)	1			—		4			—			—		5
Net current-period OCI	1			—		4			—			—		5
Ending balance	$	(8	)	$	—	$	(33	)	$	—		$	—	$	(41	)

________


(a)	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.


(b)	See next tables for details about these reclassifications.


(c)	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 three and nine months ended September 30, 2016 and 2015. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three and nine months ended September 30, 2016 and 2015.

Three Months Ended September 30, 2016




Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	19		$	—
Actuarial losses^(b)	(76		)	—
Total before tax	(57		)	—
Tax benefit	22			—
Net of tax	$	(35	)	$	—

Gains (losses) on foreign currency translation
Other	$	(5	)	$	(5	)	Other income and (deductions)
Total before tax	(5		)	(5		)
Tax expense	—			—
Net of tax	$	(5	)	$	(5	)

Total Reclassifications for the period	$	(40	)	$	(5	)	Comprehensive income

Nine Months Ended September 30, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement 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	$	5		$	5		$	—		Interest expense
Total before tax	5			5			—
Tax expense	(2		)	(2		)	—
Net of tax	$	3		$	3		$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	57		$	—		$	—
Actuarial losses^(b)	(227		)	—			(1		)
Total before tax	(170		)	—			(1		)
Tax benefit	66			—			—
Net of tax	$	(104	)	$	—		$	(1	)


Gains (losses) on foreign currency translation
Other	$	(5	)	$	(5	)	$	—		Other income and (deductions)
Total before tax	(5		)	(5		)	—
Tax expense	—			—			—
Net of tax	$	(5	)	$	(5	)	$	—

Total Reclassifications	$	(106	)	$	(2	)	$	(1	)	Comprehensive income

Three Months Ended September 30, 2015




Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement of Operations and Comprehensive Income
							Predecessor
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(4	)	$	(4	)	$	(1	)	Interest expense
Total before tax	(4		)	(4		)	(1		)
Tax expense	1			1			—
Net of tax	$	(3	)	$	(3	)	$	(1	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	19		$	—		$	—
Actuarial losses^(b)	(90		)	—			(2		)
Total before tax	(71		)	—			(2		)
Tax expense	28			—			2
Net of tax	$	(43	)	$	—		$	—

Total Reclassifications for the period	$	(46	)	$	(3	)	$	(1	)	Comprehensive income

Nine Months Ended September 30, 2015



Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement 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	13			3			—
Net of tax	$	(22	)	$	(6	)	$	(1	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	57		$	—		$	—
Actuarial losses^(b)	(270		)	—			(7		)
Total before tax	(213		)	—			(7		)
Tax benefit	83			—			3
Net of tax	$	(130	)	$	—		$	(4	)

Total Reclassifications	$	(152	)	$	(6	)	$	(5	)	Comprehensive income

_______


(a)	Amounts in parenthesis represent a decrease in net income.


(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 13 — Retirement Benefits for additional details).

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 2016 and 2015:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	7		$	8		$	22		$	22
Actuarial loss reclassified to periodic cost	(29		)	(35		)	(88		)	(105		)
Pension and non-pension postretirement benefit plans valuation adjustment	1			—			1			17
Change in unrealized gain/(loss) on cash flow hedges	(1		)	3			3			(3		)
Change in unrealized loss on equity investments	—			—			3			—
Change in unrealized gain on marketable securities	(1		)	—			(1		)	—
Total	$	(23	)	$	(24	)	$	(60	)	$	(69	)

Generation
Change in unrealized gain/(loss) on cash flow hedges	$	(2	)	$	3		$	1		$	4
Change in unrealized loss on equity investments	—			—			3			—
Change in unrealized gain on marketable securities	—			—			—			—
Total	$	(2	)	$	3		$	4		$	4



	Predecessor
PHI	Three Months Ended September 30, 2015			January 1, 2016 to March 23, 2016		Nine Months Ended September 30, 2015
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	(2	)	$	—	$	(3	)

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=66004124&loc=d3e689-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=66004124&loc=SL7669619-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
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Earnings Per Share and Equity (Exelon)

Earnings Per Share and Equity (Exelon)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Earnings Per Share and Equity (Exelon and BGE)

Earnings per Share (Exelon)

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, 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 these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:



	Three Months Ended September 30,				Nine Months Ended September 30,
Exelon	2016		2015		2016		2015
Net income attributable to common shareholders	$	490	$	629	$	930	$	1,959
Weighted average common shares outstanding — basic	925		913		924		879
Assumed exercise and/or distributions of stock-based awards	2		2		2		4
Weighted average common shares outstanding — diluted	927		915		926		883

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 11 million and 12 million for the three and nine months ended September 30, 2016, respectively and 14 million for three and nine months ended September 30, 2015. The number of equity units related to the PHI Merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the three and nine months ended September 30, 2016, respectively, and 4 million and 2 million for the three and nine months ended September 30, 2015, respectively. Refer to Note 19 — Shareholder's Equity of the Exelon 2015 Form 10-K for further information regarding the equity 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 September 30, 2016. In 2008, Exelon management decided to defer indefinitely any share repurchases.

Preference Stock Redemption (BGE)

BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.99% 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 6.70% Cumulative Preference Stock, 1993 Series for $90 million, plus accrued and unpaid dividends.

Commitments and Contingencies (All Registrants)

9 Months Ended

Sep. 30, 2016

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies (All Registrants)

18. Commitments and Contingencies (All Registrants)

The following is an update to the current status of commitments and contingencies set forth in Note 23 of the Exelon 2015 Form 10-K and Note 16 of the PHI 2015 Form 10-K. See Note 4 - Mergers, Acquisitions and Dispositions for further discussion on the PHI Merger commitments.

Commitments

Constellation Merger Commitments (Exelon and Generation)

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion. The direct investment 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 $550 million relating to Exelon and Generation’s development or assistance in the development of 275 — 300 MWs of new generation in Maryland, which is expected to be completed over a period of 10 years. As of September 30, 2016, Exelon and Generation have incurred $404 million towards satisfying the commitment for new generation development in the state of Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date. The MDPSC Order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment. While this $44 million loss contingency represents Generation's best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant.

Equity Investment Commitments (Exelon and Generation)

Generation has entered 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 commitments include 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 3 - Variable Interest Entities for additional details). As of September 30, 2016, Generation’s estimated commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



	Total
2016^(a)	$	79
2017	25
2018	4
Total	$	108

________


(a)	The noncontrolling interests holder of 2015 ESA Investco, LLC will contribute up to $31 million in support of a portion of the remaining equity commitment.

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of September 30, 2016, representing commitments potentially triggered by future events were as follows:



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit (non-debt)^(a)	$	1,720	$	1,650	$	16	$	23	$	2	$	1	$	—	$	—	$	1
Surety bonds^(b)	1,084		984		10		9		11		16		9		4		3
Financing trust guarantees	628		—		200		178		250		—		—		—		—
Nuclear insurance premiums^(c)	3,045		3,045		—		—		—		—		—		—		—
Guaranteed lease residual values^(d)	20		—		—		—		—		20		6		7		5
Total commercial commitments	$	6,497	$	5,679	$	226	$	210	$	263	$	37	$	15	$	11	$	9

________


(a)	Letters of credit (non-debt) - Exelon and certain 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)

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

(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, $13 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.

Nuclear Insurance (Exelon and Generation)

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has 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 September 30, 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. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of September 30, 2016, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 102 reactors) resulting in an additional $13.0 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG's related liability.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.4 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 of the Exelon 2015 Form 10-K for additional information on Generation’s operations relating to CENG.

Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.

NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.

Environmental Issues (All Registrants)

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, 17 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 25 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2021.


•	PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 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 two sites are not considered material. One former gas purification site is currently under investigation 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. ComEd and PECO have recorded regulatory assets for the recovery of these costs. See Note 5 — 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 September 30, 2016 and December 31, 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:



September 30, 2016	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)
Exelon	$	427	$	318
Generation	76		—
ComEd	283		281
PECO	36		34
BGE	2		2
PHI (Successor)	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^(a)
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		—

_____________________________


(a)	For BGE, includes reserve for Riverside, a gas purification site. See discussion below for additional information.

The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.

During the third quarter of 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

Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. Generation's remaining groundwater contamination reserve was approximately $13 million at September 30, 2016 and $12 million at December 31, 2015.

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 site, including the Pepco Energy Services generating facility previously located on the site that was deactivated in 2012 and subsequently demolished. 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 as determined by EPA to be necessary to meet the applicable District of Columbia surface water quality standards. The permit contemplated that Pepco would meet these limits over time through the use of best management practices (BMPs). As of December 2012, Pepco completed the implementation of the first two phases of BMPs identified in a plan approved by EPA (consisting principally of installing metal absorbing filters to capture contaminants at storm water inlets, removing stored equipment from areas exposed to the weather, covering and painting exposed metal pipes, and covering and cleaning dumpsters). These measures were effective in reducing metal concentrations in storm water discharges, but were not sufficient to meet all of the numerical limits for metals. Most of the quarterly monitoring results since the issuance of the permit have shown exceedances of the limits for copper and zinc, as well as occasional exceedances for iron and lead.

The NPDES permit was due to expire on June 19, 2014. Pepco submitted a permit renewal application on December 17, 2013. In November 2014, EPA advised Pepco that it will not renew the permit until the Benning Road site has come into compliance with the existing permit limits. The current permit remains in effect pending EPA’s action on the renewal application. In December 2014, Pepco submitted a plan to EPA to implement the third phase of BMPs recommended in the original permit compliance plan with the objective of achieving full compliance with the permit limits for metals by the end of 2015 and Pepco immediately began to implement the additional BMPs in accordance with the plan. On September 1, 2015, Pepco submitted a report to EPA on the status of implementation of the third phase of BMPs. As of that date, Pepco had fully implemented most of the elements of the Phase 3 plan, including installation of upgraded storm water inlet controls (filters and booms), enhanced inspection and maintenance of inlets, removal of materials and equipment from exposure to storm water, and removal of accumulated sediments from the underground storm drains. The sampling results from the third quarter of 2015 showed compliance with all of the permit limits. However, more recent sampling results continued to show modest exceedances for copper and zinc. As confirmed by this latest sampling, because the permit limits are low and site conditions are subject to variation, Pepco has concluded that some form of storm water treatment prior to discharge will be necessary to ensure ongoing compliance with all permit limits and has begun the process of evaluating treatment options. The nature and scope of the necessary treatment system, and the amount of the associated capital expenditures, will not be known until Pepco has completed the evaluation and design process.

Pepco has been engaged in discussions with representatives from EPA and the DOJ regarding permit compliance. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court. Pepco expects that this enforcement action will be resolved through a consent decree that will (i) establish further requirements to achieve compliance with the permit limits, including the design and installation of an appropriate storm water treatment system as noted above, and (ii) include civil penalties for past noncompliance. Pepco has established what it believes is an appropriate reserve for potential penalties which is included in the table above. Pepco does not expect the amount of such penalties above the financial reserve to have a material adverse effect on Exelon’s, PHI’s and Pepco’s consolidated financial condition, results of operations or cash flows.

Pepco and EPA are currently in discussions regarding the terms of the contemplated consent decree, and it is anticipated that the parties will finalize the consent decree before the end of 2016. In response to a joint motion by the parties, the court has extended the deadline for Pepco to answer the complaint to November 15, 2016, to give the parties time to work towards agreement on the terms of a consent decree. The parties contemplate seeking a further extension if necessary to complete their negotiations. Once executed by the parties, the consent decree will be filed with the court for review and approval following a period for public comment.

On March 14, 2016, the court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. As an intervenor, the Anacostia Riverkeeper will be entitled to file a brief commenting on the proposed consent decree and to appeal any decision by the court to approve the consent decree over the Anacostia Riverkeeper’s objection, but its participation is not expected to materially affect the progress or outcome of the consent decree negotiations.

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. On February 18, 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the 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, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the 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, that are now scheduled to be completed in the fall of 2016 to enable the EPA to propose a remedy for public comment by the end of 2016. While the EPA has not yet formally announced a change in the schedule, the PRPs believe that the final supplemental feasibility study will not be completed until year-end 2016 and the EPA announcement of the proposed remedy will take place in the third quarter of 2017. 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, but does not currently have a basis to establish a reasonable estimate of the range of costs. 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. 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.

Commencing in February 2012, 63 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, and Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. The court has dismissed the lawsuits filed by 30 of the plaintiffs. Pre-trial motions and discovery are proceeding in the remaining cases and a 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.

68^th Street Dump. In 1999, the EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the EPA are still subject to 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, EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by EPA is consistent with the PRPs estimated range of costs noted above. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site. Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual which are included in the table above 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). 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. Generation currently estimates the remaining cost to close the site to be approximately $6 million which has been fully reserved and included in the table above as of September 30, 2016.

Sauer Dump. On May 30, 2012, BGE was notified by the EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP’s signed an Administrative Settlement Agreement and Order on Consent with the EPA which requires the PRP’s to conduct a remedial investigation (RI) and feasibility study (FS) 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 EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, BGE cannot estimate the range of loss.

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 additional reserves could be established, in amounts that could be material to BGE.

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. The principal contaminants allegedly of concern are polychlorinated biphenyls and polycyclic aromatic hydrocarbons. 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 addition, in conjunction with the power plant demolition activities, Pepco and Pepco Energy Services collected soil samples adjacent to and beneath the concrete basins for the dismantled cooling towers for the generating facility. This sampling showed localized areas of soil contamination associated with the cooling tower basins, and, beginning in the third quarter of 2016, Pepco and Pepco Energy Services expect to implement a plan approved by DOEE to remove contaminated soil in conjunction with the demolition and removal of the concrete basins. On April 30, 2015, Pepco and Pepco Energy Services submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis is required to complete the RI process (much of which is 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 on February 29, 2016. The additional field investigation and data analysis will proceed later in 2016 according to a schedule to be developed by Pepco and Pepco Energy Services and approved by DOEE. 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 with an FS to evaluate possible remedial alternatives. This effort also may include a treatability study to evaluate the effectiveness of potential remedial options. Once the FS evaluation has been completed, Pepco and Pepco Energy Services will prepare and submit a draft FS Report for review and comment by DOEE and the public. Thereafter, Pepco and Pepco Energy Services will revise the draft FS Report as appropriate to address comments received and will submit a final FS Report 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 based on the results of the remedial investigation and feasibility study. 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. On March 18, 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. On September 13, 2016 PHI attended the first Consultative Working Group meeting along with several other possible private and governmental PRP’s. At the meeting it was disclosed that the federal and DOEE authorities were 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 raised a number of issues with the proposed clean-up process and schedule. Several follow up meetings have been scheduled. At this time, it is not possible to predict the extent of Pepco’s participation in the river-wide RI/FS process, or its potential exposure for response costs beyond those associated with the Benning RI/FS component of the river-wide initiative.

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 9 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.

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.

Peck Iron and Metal Site. EPA informed Pepco in a May 2009 letter that Pepco may be a PRP under CERCLA with respect to the cleanup of the Peck Iron and Metal site in Portsmouth, Virginia, and for costs EPA has incurred in cleaning up the site. The EPA letter states that Peck Iron and Metal purchased, processed, stored and shipped metal scrap from military bases, governmental agencies and businesses and that the Peck Iron and Metal scrap operations resulted in the improper storage and disposal of hazardous substances. EPA bases its allegation on its belief that Pepco was a customer at the site. Pepco has advised EPA by letter that its records show no evidence of any sale of scrap metal by Pepco to the site. Even if EPA has such records and such sales did occur, Pepco believes that any such scrap metal sales may be entitled to the recyclable material exemption from CERCLA liability. In September 2011, EPA initiated a RI/FS for the site using Federal funds. Pepco cannot at this time estimate an amount or range of reasonably possible loss associated with this RI/FS, any remediation activities to be performed at the site or any other costs that EPA might seek to impose on Pepco.

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. 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, Generation and PECO. 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 September 30, 2016 and December 31, 2015, Generation had reserved approximately $83 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2016, approximately $22 million of this amount related to 237 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. During the nine months ended September 30, 2016, Generation decreased its reserve by approximately $8 million, primarily attributable to a continued decline in expected claims activity.

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 for on a claim by claim basis. Those additional claims are taken into account in projecting estimates of 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. Since the Illinois Supreme Court’s ruling in November 2015, Exelon, Generation, and ComEd have not experienced a significant increase in asbestos-related personal injury claims brought by former ComEd employees.

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, ComEd's, PECO and BGE's future results of operations and cash flows.

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

Approximately 456 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

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


•	the identity of the facilities at which the plaintiffs allegedly worked as contractors;


•	the names of the plaintiffs’ employers;


•	the dates on which and the places where the exposure allegedly occurred; and


•	the facts and circumstances relating to the alleged exposure.

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

Continuous Power Interruption (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 September 30, 2016 and December 31, 2015, ComEd did not have any material liabilities recorded for these storm events.

Baltimore City Franchise Taxes (Exelon and 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.

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. Generation is reviewing the decision and determining whether to appeal to the Delaware Supreme Court. 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 11 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

Supplemental Financial Information (All Registrants)

9 Months Ended

Sep. 30, 2016

Supplemental Financial Information [Abstract]

Supplemental Financial Information (All Registrants)

19. Supplemental Financial Information (All Registrants)

Supplemental Statement of Operations Information

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2016 and 2015:



	Three Months Ended September 30, 2016
															Successor
	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	$	57		$	57		$	—		$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	35			35			—			—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	155			155			—			—			—		—		—		—		—
Non-regulatory agreement units	116			116			—			—			—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(5		)	(5		)	—			—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(168		)	(168		)	—			—			—		—		—		—		—
Total decommissioning-related activities	190			190			—			—			—		—		—		—		—
Investment income	2			1			—			(1		)	—		—		—		—		—
Interest income related to uncertain income tax positions	8			—			—			—			—		—		—		—		—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—		—		—		—		—
AFUDC — Equity	19			—			5			2			5		7		5		1		1
Other	7			(6		)	1			1			—		12		7		2		1
Other, net	$	120		$	185		$	(80	)	$	2		$	5	$	19	$	12	$	3	$	2



																						Successor		Predecessor
	Nine Months Ended September 30, 2016																					March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE			Pepco		DPL		ACE		PHI		PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	181		$	181		$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	95			95			—			—			—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	286			286			—			—			—			—		—		—		—		—
Non-regulatory agreement units	216			216			—			—			—			—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(2		)	(2		)	—			—			—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(380		)	(380		)	—			—			—			—		—		—		—		—
Total decommissioning-related activities	396			396			—			—			—			—		—		—		—		—
Investment income (expense)	14			6			—			(1		)	2		^(d)	—		—		—		1		—
Long-term lease income	4			—			—			—			—			—		—		—		—		—
Interest income related to uncertain income tax positions	13			—			—			—			—			1		—		1		—		—
Penalty income related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—			—		—		—		—		—
AFUDC — Equity	43			—			8			6			14			14		3		5		15		7
Loss on debt extinguishment	(3		)	(2		)	—			—			—			—		—		—		—		—
Other	16			(5		)	6			1			—			13		6		2		15		(11		)
Other, net	$	377		$	395		$	(72	)	$	6		$	16		$	28	$	9	$	8	$	31	$	(4	)



	Three Months Ended September 30, 2015
																Predecessor
	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	$	39		$	39		$	—	$	—		$	—			$	—	$	—	$	—	$	—
Non-regulatory agreement units	18			18			—		—			—				—		—		—		—
Net unrealized losses on decommissioning trust funds
Regulatory agreement units	(301		)	(301		)	—		—			—				—		—		—		—
Non-regulatory agreement units	(218		)	(218		)	—		—			—				—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	207			207			—		—			—				—		—		—		—
Total decommissioning-related activities	(255		)	(255		)	—		—			—				—		—		—		—
Investment income (expense)	4			1			—		(1		)	1			^(d)	—		—		—		—
Long-term lease income	4			—			—		—			—				—		—		—		—
AFUDC — Equity	6			—			1		1			4				2		3		—		—
Other	(3		)	(3		)	3		1			(1		)		25		5		4		1
Other, net	$	(244	)	$	(257	)	$	4	$	1		$	4			$	27	$	8	$	4	$	1



	Nine Months Ended September 30, 2015
															Predecessor
	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	$	203		$	203		$	—	$	—		$	—		$	—	$	—	$	—	$	—
Non-regulatory agreement units	122			122			—		—			—			—		—		—		—
Net unrealized losses on decommissioning trust funds
Regulatory agreement units	(385		)	(385		)	—		—			—			—		—		—		—
Non-regulatory agreement units	(274		)	(274		)	—		—			—			—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning	9			9					—			—			—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	129			129			—		—			—			—		—		—		—
Total decommissioning-related activities	(196		)	(196		)	—		—			—			—		—		—		—
Investment income (expense)	6			1			—		(1		)	3		^(d)	—		—		—		—
Long-term lease income	12			—			—		—			—			—		—		—		—
Interest income related to uncertain income tax positions	—			1			—		—			—			—		—		—		1
AFUDC — Equity	16			—			2		4			10			11		9		1		1
Terminated interest rate swaps^(e)	(26		)	—			—		—			—			—		—		—		—
Other	9			1			12		—			—			37		12		7		2
Other, net	$	(179	)	$	(193	)	$	14	$	3		$	13		$	48	$	21	$	8	$	4

____


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


(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


(c)	See Note 11— Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.


(d)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information regarding the rate stabilization deferral.

(e)

The following utility taxes are included in revenues and expenses for the three and nine months ended September 30, 2016 and 2015. Generation’s utility tax expense represents gross receipts tax related to its retail operations and the utility registrants' utility tax expense represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.



	Three Months Ended September 30, 2016
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	255	$	35	$	67	$	40	$	21	$	92	$	87	$	5	$	—



																	Successor		Predecessor
	Nine Months Ended September 30, 2016																March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Utility taxes	$	624	$	90	$	186	$	106	$	66	$	240	$	14	$	—	$	176	$	78



	Three Months Ended September 30, 2015
											Predecessor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	151	$	28	$	63	$	37	$	23	$	86	$	82	$	4	$	—



	Nine Months Ended September 30, 2015
											Predecessor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	430	$	79	$	180	$	104	$	67	$	253	$	239	$	14	$	—

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the nine months ended September 30, 2016 and 2015:



																			Successor		Predecessor
	Nine Months Ended September 30, 2016																		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization, accretion and depletion
Property, plant and equipment^(a)	$	2,490		$	1,297		$	524	$	181	$	223	$	128	$	82	$	61	$	215	$	94
Amortization of regulatory assets^(a)	293			—			49		20		84		93		38		69		140		58
Amortization of intangible assets, net^(a)	38			32			—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	(7		)	(7		)	—		—		—		—		—		—		—		—
Nuclear fuel^(c)	862			862			—		—		—		—		—		—		—		—
ARO accretion^(d)	333			332			1		—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	4,009		$	2,516		$	574	$	201	$	307	$	221	$	120	$	130	$	355	$	152



	Nine Months Ended September 30, 2015
													Predecessor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization, accretion and depletion
Property, plant and equipment^(a)	$	1,648		$	739		$	471	$	179	$	216	$	292	$	122	$	76	$	57
Amortization of regulatory assets^(a)	131			—			57		19		55		182		69		37		78
Amortization of intangible assets, net^(a)	39			35			—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	(20		)	(19		)	—		—		—		—		—		—		—
Nuclear fuel^(c)	841			841			—		—		—		—		—		—		—
ARO accretion^(d)	291			291			—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	2,930		$	1,887		$	528	$	198	$	271	$	474	$	191	$	113	$	135

________


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


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


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


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



																									Successor			Predecessor
	Nine Months Ended September 30, 2016																								March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI			PHI
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	458		$	163		$	124		$	25		$	50		$	24		$	13		$	11		$	58		$	23
Loss from equity method investments	15			16			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	107			14			31			24			12			15			12			18			27			16
Stock-based compensation costs	88			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(237		)	(237		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(20		)	(20		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	7			—			3			1			—			2			—			1			2			1
Amortization of rate stabilization deferral	62			—			—			—			62			3			3			—			—			5
Amortization of debt fair value adjustment	(9		)	(9		)	—			—			—			—			—			—			—			—
Discrete impacts from EIMA^(c)	(36		)	—			(36		)	—			—			—			—			—			—			—
Amortization of debt costs	26			12			(3		)	2			3			—			—			—			—			—
Provision for excess and obsolete inventory	74			70			4			—			—			1			1			1			—			1
Merger-related commitments^(d)(e)	508			3			—			—			—			125			73			110			308			—
Severance costs	130			57			—			—			—			—			—			—			53			—
Asset retirement costs	—			—			—			—			—			—			5			2			—			—
Lower of cost or market inventory adjustment	36			36			—			—			—			—			—			—			—			—
Other	15			24			(1		)	(3		)	(18		)	(2		)	(8		)	(5		)	(7		)	(3		)
Total other non-cash operating activities	$	1,224		$	129		$	122		$	49		$	109		$	168		$	99		$	138		$	441		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(338	)	$	(289	)	$	(42	)	$	(4	)	$	17		$	15		$	(10	)	$	2		$	(5	)	$	11
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash^(d)(f)	—			119			—			—			—			—			—			—			—			—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash ^(d)(f)	—			—			—			—			—			—			—			—			129			—
Fair value of pension obligation transferred in connection with the PHI Merger	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—
Change in PPE related to ARO update	476			476			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			157			—			—			—			—			—			—			—
Non-cash financing of capital projects	84			84			—			—			—			—			—			—			—			—



	Nine Months Ended September 30, 2015
															Predecessor
	Exelon			Generation			ComEd		PECO			BGE			PHI			Pepco			DPL		ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	476		$	200		$	155	$	29		$	49		$	73		$	22		$	11	$	11
Loss from equity method investments	3			4			—		—			—			—			—			—		—
Provision for uncollectible accounts	114			15			46		37			15			49			15			18		15
Stock-based compensation costs	102			—			—		—			—			9			—			—		—
Other decommissioning-related activity^(a)	(31		)	(31		)	—		—			—			—			—			—		—
Energy-related options^(b)	18			18			—		—			—			—			—			—		—
Amortization of regulatory asset related to debt costs	—			—			—		—			—			4			2			—		—
Amortization of rate stabilization deferral	60			—			—		—			60			3			3			1		—
Amortization of debt fair value adjustment	(34		)	(9		)	—		—			—			—			—			—		—
Discrete impacts from EIMA^(c)	101			—			101		—			—			—			—			—		—
Amortization of debt costs	43			12			3		2			2			1			—			—		—
Provision for excess and obsolete inventory	7			8			—		—			—			1			—			—		—
Lower of cost or market inventory adjustment	15			15			—		—			—			—			—			—		—
Other	(18		)	(5		)	7		1			(15		)	3			—			1		1
Total other non-cash operating activities	$	856		$	227		$	312	$	69		$	111		$	143		$	42		$	31	$	27
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	59		$	48		$	62	$	(23	)	$	(14	)	$	(3	)	$	(1	)	$	2	$	—
Nuclear fuel procurement^(d)	—			—			—		—			—			—			—			—		—
Change in PPE related to ARO update	811			811			—		—			—			—			—			—		—
Indemnification of like-kind exchange position^(g)	—			—			5		—			—			—			—			—		—
Non-cash financing of capital projects	52			52			—		—			—			—			—			—		—
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 of the Exelon 2015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


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


(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.


(d)	See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.


(e)	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.


(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


(g)	See Note 11— Income Taxes for discussion of the like-kind exchange tax position.

Supplemental Balance Sheet Information

The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2016 and December 31, 2015:



													Successor
September 30, 2016	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	18,354	^(a)	$	10,004	^(a)	$	3,841	$	3,213	$	3,198	$	146	$	3,026	$	1,171	$	1,008
Accounts receivable:
Allowance for uncollectible accounts	$	330		$	85		$	82	$	78	$	39	$	46	$	15	$	14	$	17



													Predecessor
December 31, 2015	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	16,375	^(b)	$	8,639	^(b)	$	3,710	$	3,101	$	3,016	$	5,341	$	2,929	$	1,139	$	968
Accounts receivable:
Allowance for uncollectible accounts	$	284		$	77		$	75	$	83	$	49	$	56	$	17	$	17	$	17

_______


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,198 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million.

PECO Installment Plan Receivables (Exelon and PECO)

PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $16 million and $15 million as of September 30, 2016 and December 31, 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 of the Exelon 2015 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2016 of $14 million consists of $0 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance 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 September 30, 2016 and December 31, 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 of the Exelon 2015 Form 10-K.

Segment Information (All Registrants)

9 Months Ended

Sep. 30, 2016

Segment Reporting [Abstract]

Segment Information (All Registrants)

20. 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 power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as “Other Power Regions”, which includes activities in the South, West and Canada. ComEd, PECO, 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 power marketing activities and allocate resources based on revenue net of purchased power and fuel expense (RNF). Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and affiliated sales to 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 not included in the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.

An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and nine months ended September 30, 2016 and 2015 is as follows:

Three Months Ended September 30, 2016 and 2015



									Successor
	Generation^(a)		ComEd		PECO		BGE		PHI^(b)		Other^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2016
Competitive businesses electric revenues	$	4,322	$	—	$	—	$	—	$	—	$	—		$	(499	)	$	3,823
Competitive businesses natural gas revenues	326		—		—		—		—		—			—			326
Competitive businesses other revenues	387		—		—		—		—		—			(1		)	386
Rate-regulated electric revenues	—		1,497		740		735		1,366		—			(8		)	4,330
Rate-regulated natural gas revenues	—		—		48		77		17		—			(5		)	137
Shared service and other revenues	—		—		—		—		11		362			(373		)	—
2015
Competitive businesses electric revenues	$	4,299	$	—	$	—	$	—	$	—	$	—		$	(204	)	$	4,095
Competitive businesses natural gas revenues	347		—		—		—		—		—			—			347
Competitive businesses other revenues	122		—		—		—		—		—			—			122
Rate-regulated electric revenues	—		1,376		691		655		—		—			(1		)	2,721
Rate-regulated natural gas revenues	—		—		49		70		—		—			(3		)	116
Shared service and other revenues	—		—		—		—		—		348			(348		)	—
Intersegment revenues^(e):
2016	$	500	$	4	$	2	$	7	$	11	$	362		$	(885	)	$	1
2015	205		1		1		3		—		347			(555		)	2
Net income (loss):
2016	$	271	$	37	$	122	$	56	$	166	$	(125	)	$	(1	)	$	526
2015	332		149		90		54		—		(36		)	(2		)	587
Total assets:
September 30, 2016	$	47,568	$	28,020	$	11,041	$	8,857	$	21,063	$	9,883		$	(11,897	)	$	114,535
December 31, 2015	46,529		26,532		10,367		8,295		—		15,389			(11,728		)	95,384

__________

(a)

Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the three months ended September 30, 2016 include revenue from sales to PECO of $91 million and sales to BGE of $183 million in the Mid-Atlantic region, and sales to ComEd of $20 million in the Midwest region. For the three months ended September 30, 2015, intersegment revenues for Generation include revenue from sales to PECO of $61 million and sales to BGE of $141 million in the Mid-Atlantic region, and sales to ComEd of $2 million in the Midwest region. For the Successor period of three months ended September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $128 million, sales to DPL of $63 million, and sales to ACE of $15 million in the Mid-Atlantic region.


(b)	Amounts included represent activity for PHI's successor period, three months ended September 30, 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 nine months ended September 30, 2015.


(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.


(d)	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 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 2016 and 2015.

(e)

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.

Generation total revenues:




	Three Months Ended September 30, 2016							Three Months Ended September 30, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	1,813	$	(13	)	$	1,800	$	1,640	$	(8	)	$	1,632
Midwest	1,163		1			1,164		1,152		(1		)	1,151
New England	455		(4		)	451		520		—			520
New York	331		(8		)	323		254		(4		)	250
ERCOT	289		6			295		317		(1		)	316
Other Power Regions	271		(33		)	238		416		(40		)	376
Total Revenues for Reportable Segments	4,322		(51		)	4,271		4,299		(54		)	4,245
Other^(b)	713		51			764		469		54			523
Total Generation Consolidated Operating Revenues	$	5,035	$	—		$	5,035	$	4,768	$	—		$	4,768

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $21 million decrease and $3 million decrease to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the three months ended September 30, 2016 and 2015, respectively, unrealized mark-to-market gains of $187 million and losses of $7 million for the three months ended September 30, 2016 and 2015, respectively, and elimination of intersegment revenues.

(c)

Exelon corrected an error in the September 30, 2015 balances within Intersegment Revenue and Revenue from external customers for an overstatement of $54 million of Intersegment Revenue for Reportable Segments for the three months ended September 30, 2015, an understatement of Revenue from external customers for Reportable Segments of $54 million for the three months ended September 30, 2015, an understatement of $54 million of Intersegment Revenue for Other for the three months ended September 30, 2015, and an overstatement of Revenue from external customers for Other of $54 million for the three months ended September 30, 2015. This error is not considered material to any prior period, and there is no impact to Total Revenues.

Generation total revenues net of purchased power and fuel expense:




	Three Months Ended September 30, 2016							Three Months Ended September 30, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)			Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	881	$	6		$	887	$	979		$	18		$	997
Midwest	782		(1		)	781		760			(4		)	756
New England	170		(10		)	160		148			(15		)	133
New York	195		(1		)	194		157			13			170
ERCOT	144		(51		)	93		166			(55		)	111
Other Power Regions	143		(66		)	77		154			(71		)	83
Total Revenues net of purchased power and fuel for Reportable Segments	2,315		(123		)	2,192		2,364			(114		)	2,250
Other^(b)	131		123			254		(115		)	114			(1		)
Total Generation Revenues net of purchased power and fuel expense	$	2,446	$	—		$	2,446	$	2,249		$	—		$	2,249

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $22 million decrease and a $4 million decrease to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the three months ended September 30, 2016 and 2015, respectively, unrealized mark-to-market gains of $88 million and losses of $139 million for the three months ended September 30, 2016 and 2015, respectively, accelerated nuclear fuel amortization associated with nuclear decommissioning as discussed in Note 7 — Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $28 million for the three months ended September 30, 2016, and the elimination of intersegment revenue net of purchased power and fuel expense.

(c)

Exelon corrected an error in the September 30, 2015 balances within Intersegment RNF and RNF from external customers for an understatement of $12 million of Intersegment RNF for Reportable Segments for the three months ended September 30, 2015, and an overstatement of $12 million of Intersegment RNF for Other for the three months ended September 30, 2015. This also included an understatement of total RNF for Reportable Segments and an overstatement of total RNF for Other of $13 million for the three months ended September 30, 2015. The error is not considered material to any prior period, and there is no net impact to Generation Total RNF for 2015.

Successor and Predecessor PHI:



	Pepco		DPL		ACE		Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
Three months ended September 30, 2016 - Successor
Rate-regulated electric revenues	$	635	$	314	$	421	$	—		$	(4	)	$	1,366
Rate-regulated natural gas revenues	—		17		—		—						17
Shared service and other revenues	—		—		—		11			—			11
Three months ended September 30, 2015 - Predecessor
Rate-regulated electric revenues	$	592	$	295	$	386	$	44		$	—		$	1,317
Rate-regulated natural gas revenues	—		19		—		—			—			19
Shared service and other revenues	—		—		—		—			—			—
Intersegment revenues^(e):
Three months ended September 30, 2016 - Successor	$	1	$	2	$	1	$	11		$	(4	)	$	11
Three months ended September 30, 2015 - Predecessor	1		1		1		—			(3		)	—
Net income (loss):
Three months ended September 30, 2016 - Successor	$	79	$	44	$	47	$	(15	)	$	11		$	166
Three months ended September 30, 2015 - Predecessor	60		15		22		(6		)	—			91
Total assets:
September 30, 2016 - Successor	$	7,219	$	4,023	$	3,507	$	11,057		$	(4,743	)	$	21,063
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 19 — Supplemental Financial Information for total utility taxes for the three months ended September 30, 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.

Nine Months Ended September 30, 2016 and 2015



									Successor
	Generation^(a)		ComEd		PECO		BGE		PHI^(b)			Other^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2016
Competitive businesses electric revenues	$	11,677	$	—	$	—	$	—	$	—		$	—		$	(1,118	)	$	10,559
Competitive businesses natural gas revenues	1,515		—		—		—		—			—			—			1,515
Competitive businesses other revenues	171		—		—		—		—			—			(2		)	169
Rate-regulated electric revenues	—		4,031		1,971		1,998		2,485			—			(24		)	10,461
Rate-regulated natural gas revenues	—		—		322		423		46			—			(10		)	781
Shared service and other revenues	—		—		—		—		34			1,166			(1,199		)	1
2015
Competitive businesses electric revenues	$	12,360	$	—	$	—	$	—	$	—		$	—		$	(564	)	$	11,796
Competitive businesses natural gas revenues	1,901		—		—		—		—			—			—			1,901
Competitive businesses other revenues	580		—		—		—		—			—			1			581
Rate-regulated electric revenues	—		3,709		1,950		1,908		—			—			(3		)	7,564
Rate-regulated natural gas revenues	—		—		436		480		—			—			(12		)	904
Shared service and other revenues	—		—		—		—		—			1,007			(1,007		)	—
Intersegment revenues^(e):
2016	$	1,121	$	12	$	5	$	16	$	34		$	1,166		$	(2,351	)	$	3
2015	567		3		1		10		—			1,003			(1,581		)	3
Net income (loss):
2016	$	556	$	297	$	346	$	191	$	(91	)	$	(340	)	$	(3	)	$	956
2015	1,208		339		299		212		—			(96		)	(3		)	1,959

_________

(a)

Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2016 include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the nine months ended September 30, 2015, intersegment revenues for Generation include revenue from sales to PECO of $173 million and sales to BGE of $376 million in the Mid-Atlantic region, and sales to ComEd of $17 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region.


(b)	Amounts included represent activity for PHI's successor period, March 24, 2016 through September 30, 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 nine months ended September 30, 2015.


(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.


(d)	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 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2016 and 2015.

(e)

Generation total revenues:



	Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	4,776	$	(40	)	$	4,736	$	4,560	$	(69	)	$	4,491
Midwest	3,330		13			3,343		3,634		(1		)	3,633
New England	1,278		(6		)	1,272		1,752		(6		)	1,746
New York	906		(33		)	873		783		(5		)	778
ERCOT	659		6			665		691		(4		)	687
Other Power Regions	728		(42		)	686		940		(60		)	880
Total Revenues for Reportable Segments	11,677		(102		)	11,575		12,360		(145		)	12,215
Other^(b)	1,686		102			1,788		2,481		145			2,626
Total Generation Consolidated Operating Revenues	$	13,363	$	—		$	13,363	$	14,841	$	—		$	14,841

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $10 million decrease to revenues and a $19 million increase to revenues for the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value for the nine months ended September 30, 2016 and 2015, respectively, unrealized mark-to-market losses of $366 million and gains of $171 million for the nine months ended September 30, 2016 and 2015, respectively, and elimination of intersegment revenues.

(c)

Exelon corrected an error in the September 30, 2015 balances within Intersegment Revenue and Revenue from external customers for an overstatement of $144 million of Intersegment Revenue for Reportable Segments for the nine months ended September 30, 2015, an understatement of Revenue from external customers for Reportable Segments of $144 million for the nine months ended September 30, 2015, an understatement of $144 million of Intersegment Revenue for Other for the nine months ended September 30, 2015, and an overstatement of Revenue from external customers for Other of $144 million for the nine months ended September 30, 2015. This error is not considered material to any prior period, and there is no impact to Total Revenues.

Generation total revenues net of purchased power and fuel expense:



	Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)		Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	2,541	$	15		$	2,556	$	2,679	$	(2	)	$	2,677
Midwest	2,225		4			2,229		2,220		(15		)	2,205
New England	373		(23		)	350		425		(46		)	379
New York	607		(15		)	592		462		40			502
ERCOT	335		(104		)	231		344		(109		)	235
Other Power Regions	357		(104		)	253		341		(148		)	193
Total Revenues net of purchased power and fuel expense for Reportable Segments	6,438		(227		)	6,211		6,471		(280		)	6,191
Other^(b)	316		227			543		570		280			850
Total Generation Revenues net of purchased power and fuel expense	$	6,754	$	—		$	6,754	$	7,041	$	—		$	7,041

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $15 million decrease to RNF and a $20 million increase to RNF for the amortization of intangible assets and liabilities related to commodity contracts for the nine months ended September 30, 2016 and 2015, respectively, unrealized mark-to-market losses of $113 million and gains of $258 million for the nine months ended September 30, 2016 and 2015, respectively, accelerated nuclear fuel amortization associated with nuclear decommissioning as discussed in Note 7 - Early Nuclear Plant Retirements of the Combined Notes to Consolidated Financial Statements of $38 million for the nine months ended September 30, 2016, and the elimination of intersegment revenue net of purchased power and fuel expense.

(c)

Exelon corrected an error in the September 30, 2015 balances within Intersegment RNF and RNF from external customers for an understatement of $22 million of Intersegment RNF for Reportable Segments for the nine months ended September 30, 2015, an understatement of RNF from external customers for Reportable Segments of $6 million for the nine months ended September 30, 2015, an overstatement of $22 million of Intersegment RNF for Other for the nine months ended September 30, 2015, and an overstatement of RNF from external customers for Other of $6 million for the nine months ended September 30, 2015. This also included an understatement of total RNF for Reportable Segments and an overstatement of total RNF for Other of $28 million for the nine months ended September 30, 2015. The error is not considered material to any prior period, and there is no net impact to Generation Total RNF for 2015.

Successor and Predecessor PHI:



	Pepco			DPL			ACE			Other^(b)			Intersegment Eliminations			PHI
Operating revenues^(a):
March 24, 2016 to September 30, 2016 - Successor
Rate-regulated electric revenues	$	1,184		$	593		$	714		$	3		$	(9	)	$	2,485
Rate-regulated natural gas revenues	—			46			—			—			—			46
Shared service and other revenues	—			—			—			34			—			34
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	—			—			—			—			—			—
Nine months ended September 30, 2015 - Predecessor
Rate-regulated electric revenues	$	1,641		$	875		$	1,003		$	161		$	—		$	3,680
Rate-regulated natural gas revenues	—			129			—			—			—			129
Shared service and other revenues	—			—			—			—			—			—
Intersegment revenues:
March 24, 2016 to September 30, 2016 - Successor	$	2		$	4		$	2		$	35		$	(9	)	$	34
January 1, 2016 to March 23, 2016 - Predecessor	1			2			1			—			(4		)	—
Nine months ended September 30, 2015 - Predecessor	4			4			2			—			(10		)	—
Net income (loss):
March 24, 2016 to September 30, 2016 - Successor	$	(12	)	$	(42	)	$	(55	)	$	(16	)	$	34		$	(91	)
January 1, 2016 to March 23, 2016 - Predecessor	32			26			5			(44		)	—			19
Nine months ended September 30, 2015 - Predecessor	128			55			37			(23		)	—			197

_________


(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 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 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.

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

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Organization, Consolidation and Presentation of Financial Statements [Abstract]

Significant Accounting Policies Significant Accounting Policies

9 Months Ended

Sep. 30, 2016

New Accounting Pronouncements, Policy [Policy Text Block]

New Accounting Pronouncements (All Registrants)

Exelon has identified the following new accounting standards that have been recently adopted.

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

In May 2015, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. The Registrants adopted the standard in the first quarter of 2016, and applied the guidance retrospectively to all prior periods presented. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. See Note 8 - Fair Value of Financial Assets and Liabilities for the disclosure impacts.

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

In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either 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. The Registrants prospectively adopted the standard in the first quarter of 2016. The adoption of this guidance had no impact on the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Amendments to the Consolidation Analysis

In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the 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 guidance became effective for the Registrants January 1, 2016. The Registrants adopted the standard in the first quarter of 2016. The Registrants have evaluated the standard and have not identified any changes to consolidation conclusions as a result of the new guidance, but have identified additional entities that are now considered VIEs. See Note 3 - Variable Interest Entities for the disclosure impacts.

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

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts where collectability is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. The guidance 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. In March 2016, the FASB issued a final amendment to clarify the implementation guidance for principal versus agent considerations and in April 2016 issued a final amendment to clarify the guidance related to identifying performance obligations and the accounting for licenses of intellectual property. The Registrants do not expect significant impacts based on these updates. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of this update.

Leases

In February 2016, the FASB issued authoritative guidance to increase 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 with early adoption permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

Intra-Entity Transfers of Assets Other Than Inventory

In October 2016, the FASB issued authoritative guidance which instructs 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. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance.

Classification of Certain Cash Receipts and Cash Payments

In August 2016, the FASB issued authoritative guidance intended to add or clarify guidance on the classification of certain cash receipts and payments on the statement of cash flows. The new guidance addresses cash flows related to the following: 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 standard is effective January 1, 2018, with early adoption permitted. The guidance must be applied on a retrospective basis. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Statements of Cash Flows.

Impairment of Financial Instruments

In June 2016, the FASB issued authoritative guidance that adds an impairment model to U.S. GAAP called the Current Expected Credit Loss (CECL) model for financial instruments within the scope of the guidance, which includes loans, trade receivables, debt securities classified as held-to-maturity and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity would be 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. An entity must consider all available relevant information when estimating expected credit losses. Historical charge-off rates may be used as a starting point for determining expected credit losses; however, the entity must also evaluate how conditions that existed during the historical charge-off period may differ from its current expectations and accordingly revise its estimate of expected credit losses. 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. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures.

Improvements to Employee Share-Based Payment Accounting

In March 2016, the FASB issued authoritative guidance intended to simplify various aspects to 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. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted if all provisions are adopted within the same period. The guidance is required to be applied on either a prospective, modified retrospective, or retrospective basis depending on the provisions applied. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Simplifying the Transition to the Equity Method of Accounting

In March 2016, the FASB issued authoritative guidance eliminating 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. The guidance now requires an investor to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for the equity method of accounting. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

In March 2016, the FASB issued authoritative guidance which 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. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. Entities have the option to adopt this standard on a prospective basis to new derivative contract novations or on a modified retrospective basis. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the transition method and the potential to early adopt the guidance.

Contingent Put and Call Options in Debt Instruments

In March 2016, the FASB issued authoritative guidance which 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 standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments. The Registrants do not expect that this guidance will have a significant impact on Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures and are currently assessing the potential to early adopt the guidance.

Recognition and Measurement of Financial Assets and Financial Liabilities

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

Simplifying the Measurement of Inventory

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

Exelon has identified the following new accounting standards that have been recently adopted.

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

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

Amendments to the Consolidation Analysis

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

Revenue from Contracts with Customers

Leases

Intra-Entity Transfers of Assets Other Than Inventory

Classification of Certain Cash Receipts and Cash Payments

Impairment of Financial Instruments

Improvements to Employee Share-Based Payment Accounting

Simplifying the Transition to the Equity Method of Accounting

Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships

Contingent Put and Call Options in Debt Instruments

Recognition and Measurement of Financial Assets and Financial Liabilities

Simplifying the Measurement of Inventory

Fair Value Assets Measured On Recurring Basis Investments Valuation Techniques

Fair Value Assets Measured On Recurring Basis Cash And Cash Equivalents Valuation Techniques



	Successor		Predecessor
	PHI		PHI		Pepco
	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		Three Months Ended September 30, 2016		Three Months Ended September 30, 2015
	Other, net		Other, net		Other, net
Total gains (losses) included in net income	$	1	$	16	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held	—		15		—		—



	Nine Months Ended September 30, 2016			Nine Months Ended September 30, 2015
	Pepco			Pepco			DPL
	Life Insurance Contracts			Life Insurance Contracts			Life Insurance Contracts
Beginning Balance	$	19		$	18		$	1
Total realized / unrealized gains (losses)
Included in net income	3			4			—
Purchases, sales, issuances and settlements
Issuances	(1		)	(4		)	—
Settlements	—			—			(1		)
Ending Balance	$	21		$	18		$	—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities for the period	$	2		$	2		$	—




	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 three months ended September 30, 2016	$	180		$	(85	)	$	(4	)	$	180		$	(85	)	$	(3	)
Total gains (losses) included in net income for the nine months ended September 30, 2016	(232		)	(107		)	2			(232		)	(107		)	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2016	323			(38		)	3			323			(38		)	3
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2016	303			(63		)	7			303			(63		)	8



	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 three months ended September 30, 2015	$	(4	)	$	(44	)	$	—		$	(4	)	$	(44	)	$	—
Total gains (losses) included in net income for the nine months ended September 30, 2015	(31		)	(56		)	4			(31		)	(56		)	4
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2015	198			(17		)	(1		)	198			(17		)	(1		)
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2015	538			(2		)	2			538			(2		)	2



	Successor		Predecessor
	PHI		PHI		Pepco
	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		Three Months Ended September 30, 2016		Three Months Ended September 30, 2015
	Other, net		Other, net		Other, net
Total gains (losses) included in net income	$	1	$	16	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held	—		15		—		—



	Successor		Predecessor
	PHI		PHI					Pepco
	March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016			Nine Months Ended September 30, 2015		Nine Months Ended September 30, 2016		Nine Months Ended September 30, 2015
	Other, net		Other, net					Other, net
Total gains (losses) included in net income	$	2	$	(17	)	$	19	$	3	$	4
Change in the unrealized gains (losses) relating to assets and liabilities held	1		1			17		2		2

_________


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

Fair Value Assets Measured On Recurring Basis Nuclear Decommissioning Trust Fund Investments Valuation Techniques

le.

Fair Value Assets And Liabilities Measured On Recurring Basis Derivative Financial Instruments Assets And Liabilities Valuation Techniques

Fair Value Liabilities Measured On Recurring Basis Obligations Valuation Techniques

Earnings Per Share, Policy [Policy Text Block]

New Accounting Pronouncements (Policies)	9 Months Ended
New Accounting Pronouncements (Policies)	Sep. 30, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements, Policy [Policy Text Block]	New Accounting Pronouncements (All Registrants) Exelon has identified the following new accounting standards that have been recently adopted. Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share In May 2015, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. The Registrants adopted the standard in the first quarter of 2016, and applied the guidance retrospectively to all prior periods presented. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. See Note 8 - Fair Value of Financial Assets and Liabilities for the disclosure impacts. Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either 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. The Registrants prospectively adopted the standard in the first quarter of 2016. The adoption of this guidance had no impact on the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. Amendments to the Consolidation Analysis In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the 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 guidance became effective for the Registrants January 1, 2016. The Registrants adopted the standard in the first quarter of 2016. The Registrants have evaluated the standard and have not identified any changes to consolidation conclusions as a result of the new guidance, but have identified additional entities that are now considered VIEs. See Note 3 - Variable Interest Entities for the disclosure impacts. The following issued accounting standards are not yet required to be reflected in the consolidated financial statements of the Registrants. Revenue from Contracts with Customers In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts where collectability is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. The guidance 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. In March 2016, the FASB issued a final amendment to clarify the implementation guidance for principal versus agent considerations and in April 2016 issued a final amendment to clarify the guidance related to identifying performance obligations and the accounting for licenses of intellectual property. The Registrants do not expect significant impacts based on these updates. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of this update. Leases In February 2016, the FASB issued authoritative guidance to increase 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 with early adoption permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance. Intra-Entity Transfers of Assets Other Than Inventory In October 2016, the FASB issued authoritative guidance which instructs 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. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance. Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued authoritative guidance intended to add or clarify guidance on the classification of certain cash receipts and payments on the statement of cash flows. The new guidance addresses cash flows related to the following: 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 standard is effective January 1, 2018, with early adoption permitted. The guidance must be applied on a retrospective basis. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Statements of Cash Flows. Impairment of Financial Instruments In June 2016, the FASB issued authoritative guidance that adds an impairment model to U.S. GAAP called the Current Expected Credit Loss (CECL) model for financial instruments within the scope of the guidance, which includes loans, trade receivables, debt securities classified as held-to-maturity and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity would be 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. An entity must consider all available relevant information when estimating expected credit losses. Historical charge-off rates may be used as a starting point for determining expected credit losses; however, the entity must also evaluate how conditions that existed during the historical charge-off period may differ from its current expectations and accordingly revise its estimate of expected credit losses. 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. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. Improvements to Employee Share-Based Payment Accounting In March 2016, the FASB issued authoritative guidance intended to simplify various aspects to 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. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted if all provisions are adopted within the same period. The guidance is required to be applied on either a prospective, modified retrospective, or retrospective basis depending on the provisions applied. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance. Simplifying the Transition to the Equity Method of Accounting In March 2016, the FASB issued authoritative guidance eliminating 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. The guidance now requires an investor to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for the equity method of accounting. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance. Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships In March 2016, the FASB issued authoritative guidance which 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. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. Entities have the option to adopt this standard on a prospective basis to new derivative contract novations or on a modified retrospective basis. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the transition method and the potential to early adopt the guidance. Contingent Put and Call Options in Debt Instruments In March 2016, the FASB issued authoritative guidance which 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 standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments. The Registrants do not expect that this guidance will have a significant impact on Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures and are currently assessing the potential to early adopt the guidance. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued authoritative guidance which (i) requires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance. Simplifying the Measurement of Inventory In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance. Exelon has identified the following new accounting standards that have been recently adopted. Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share In May 2015, the FASB issued authoritative guidance that removes the requirement to categorize within the fair value hierarchy all investments for which fair value is measured using the net asset value per share practical expedient. Investments measured at net asset value per share using the practical expedient will be presented as a reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the disclosure requirements for investments valued using the practical expedient. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. The Registrants adopted the standard in the first quarter of 2016, and applied the guidance retrospectively to all prior periods presented. The adoption of this guidance had no impact on the Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income and Consolidated Statements of Cash Flows. See Note 8 - Fair Value of Financial Assets and Liabilities for the disclosure impacts. Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either 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. The Registrants prospectively adopted the standard in the first quarter of 2016. The adoption of this guidance had no impact on the Registrants' Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. Amendments to the Consolidation Analysis In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the 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 guidance became effective for the Registrants January 1, 2016. The Registrants adopted the standard in the first quarter of 2016. The Registrants have evaluated the standard and have not identified any changes to consolidation conclusions as a result of the new guidance, but have identified additional entities that are now considered VIEs. See Note 3 - Variable Interest Entities for the disclosure impacts. The following issued accounting standards are not yet required to be reflected in the consolidated financial statements of the Registrants. Revenue from Contracts with Customers In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific guidance, with a five step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single, comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries and across capital markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing and uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the transition method that they will use to adopt the guidance. Exelon is considering the impacts of the new guidance on its ability to recognize revenue for certain contracts where collectability is in question, its accounting for contributions in aid of construction, bundled sales contracts and contracts with pricing provisions that may require it to recognize revenue at prices other than the contract price (e.g., straight line or estimated future market prices). In addition, the Registrants will be required to capitalize costs to acquire new contracts, whereas Exelon currently expenses those costs as incurred. The guidance 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. In March 2016, the FASB issued a final amendment to clarify the implementation guidance for principal versus agent considerations and in April 2016 issued a final amendment to clarify the guidance related to identifying performance obligations and the accounting for licenses of intellectual property. The Registrants do not expect significant impacts based on these updates. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of this update. Leases In February 2016, the FASB issued authoritative guidance to increase 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 with early adoption permitted. Lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance. Intra-Entity Transfers of Assets Other Than Inventory In October 2016, the FASB issued authoritative guidance which instructs 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. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance. Classification of Certain Cash Receipts and Cash Payments In August 2016, the FASB issued authoritative guidance intended to add or clarify guidance on the classification of certain cash receipts and payments on the statement of cash flows. The new guidance addresses cash flows related to the following: 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 standard is effective January 1, 2018, with early adoption permitted. The guidance must be applied on a retrospective basis. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Statements of Cash Flows. Impairment of Financial Instruments In June 2016, the FASB issued authoritative guidance that adds an impairment model to U.S. GAAP called the Current Expected Credit Loss (CECL) model for financial instruments within the scope of the guidance, which includes loans, trade receivables, debt securities classified as held-to-maturity and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity would be 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. An entity must consider all available relevant information when estimating expected credit losses. Historical charge-off rates may be used as a starting point for determining expected credit losses; however, the entity must also evaluate how conditions that existed during the historical charge-off period may differ from its current expectations and accordingly revise its estimate of expected credit losses. 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. The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. Improvements to Employee Share-Based Payment Accounting In March 2016, the FASB issued authoritative guidance intended to simplify various aspects to 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. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted if all provisions are adopted within the same period. The guidance is required to be applied on either a prospective, modified retrospective, or retrospective basis depending on the provisions applied. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance. Simplifying the Transition to the Equity Method of Accounting In March 2016, the FASB issued authoritative guidance eliminating 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. The guidance now requires an investor to add the cost of acquiring the additional interest in the investee to the current basis of the investor's previously held interest and adopt the equity method of accounting as of the date the investment becomes qualified for the equity method of accounting. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance. Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships In March 2016, the FASB issued authoritative guidance which 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. The standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. Entities have the option to adopt this standard on a prospective basis to new derivative contract novations or on a modified retrospective basis. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the transition method and the potential to early adopt the guidance. Contingent Put and Call Options in Debt Instruments In March 2016, the FASB issued authoritative guidance which 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 standard is effective for fiscal years beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments. The Registrants do not expect that this guidance will have a significant impact on Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures and are currently assessing the potential to early adopt the guidance. Recognition and Measurement of Financial Assets and Financial Liabilities In January 2016, the FASB issued authoritative guidance which (i) requires all investments in equity securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and assumptions used to estimate fair value, and (iv) requires disclosure of the fair value of financial assets and liabilities measured at amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures as well as the potential to early adopt the guidance. Simplifying the Measurement of Inventory In July 2015, the FASB issued authoritative guidance that requires inventory to be measured at the lower of cost or net realizable value. The new guidance defines net realizable value as the estimated selling price in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable value or net realizable value less an approximately normal profit margin. The guidance is effective for periods beginning after December 15, 2016 with early adoption permitted. The guidance is required to be applied prospectively. The Registrants do not expect that this guidance will have a significant impact on their Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. The Registrants are currently assessing the potential to early adopt the guidance.

Variable Interest Entities (Tables)

9 Months Ended

Sep. 30, 2016

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities



	September 30, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE
Current assets	$	914	$	849	$	44	$	20	$	15	$	909	$	881	$	23	$	12	$	12
Noncurrent assets	8,235		8,201		3		31		19		8,009		8,004		3		18		18
Total assets	$	9,149	$	9,050	$	47	$	51	$	34	$	8,918	$	8,885	$	26	$	30	$	30
Current liabilities	$	569	$	439	$	84	45		$	40	$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities	3,090		2,979		—		111		99		2,927		2,884		41		124		124
Total liabilities	$	3,659	$	3,418	$	84	$	156	$	139	$	3,400	$	3,271	$	122	$	172	$	172

_______


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



September 30, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	586	$	531	$	1,117
Total liabilities^(a)	181		308		489
Exelon's ownership interest in VIE^(a)	—		193		193
Other ownership interests in VIE^(a)	405		34		439
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		225		225
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	11		—		11



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)



	September 30, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents	$	160	$	160	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash	101		43		44		15		15		100		77		23		12		12
Accounts receivable, net
Customer	264		264		—		—		—		219		219		—		—		—
Other	42		42		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets	49		49		—		—		—		140		140		—		—		—
Inventory
Materials and supplies	192		192		—		—		—		181		181		—		—		—
Other current assets	58		51		—		5		—		35		30		—		—		—
Total current assets	866		801		44		20		15		882		854		23		12		12
Property, plant and equipment, net	5,139		5,139		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds	2,173		2,173		—		—		—		2,036		2,036		—		—		—
Goodwill	47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets	32		32		—		—		—		53		53		—		—		—
Other noncurrent assets	257		223		3		31		19		90		85		3		18		18
Total noncurrent assets	7,648		7,614		3		31		19		7,386		7,381		3		18		18
Total assets	$	8,514	$	8,415	$	47	$	51	$	34	$	8,268	$	8,235	$	26	$	30	$	30
Long-term debt due within one year	$	191	$	64	$	81	$	43	$	38	$	111	$	27	$	79	$	46	$	46
Accounts payable	201		201		—		—		—		216		216		—		—		—
Accrued expenses	102		98		2		2		2		115		113		2		2		2
Mark-to-market derivative liabilities	24		24		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities	14		14		—		—		—		12		12		—		—		—
Other current liabilities	34		34		—		—		—		13		13		—		—		—
Total current liabilities	566		435		83		45		40		472		386		81		48		48
Long-term debt	661		550		—		111		99		666		623		41		124		124
Asset retirement obligations	2,070		2,070		—		—		—		1,999		1,999		—		—		—
Pension obligation^(c)	9		9		—		—		—		9		9		—		—		—
Unamortized energy contract liabilities	26		26		—		—		—		39		39		—		—		—
Other noncurrent liabilities	106		106		—		—		—		79		79		—		—		—
Total noncurrent liabilities	2,872		2,761		—		111		99		2,792		2,749		41		124		124
Total liabilities	$	3,438	$	3,196	$	83	$	156	$	139	$	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.

Business Acquisition, Pro Forma Information, Nonrecurring Adjustments [Table Text Block]

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

Mergers, Acquisitions and Dispositions (Tables)

9 Months Ended

Sep. 30, 2016

Business Combinations [Abstract]



	Three Months Ended September 30,				Nine Months Ended September 30,				Year Ended December 31,
	2016 (a)		2015 (b)		2016 (a)		2015 (b)		2015 (c)
Total operating revenues	$	9,002	$	8,545	$	24,468	$	26,129	$	33,823
Net income attributable to common shareholders	501		746		1,346		2,169		2,618

Basic earnings per share	$	0.54	$	0.81	$	1.46	$	2.36	$	2.85
Diluted earnings per share	0.54		0.81		1.45		2.35		2.84

______________


(a)	The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.


(b)	The amounts above include adjustments for non-recurring costs directly related to the merger of $25 million and $100 million and intercompany revenue of $192 million and $426 million for the three and nine months ended September 30, 2015, respectively.


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

Business Combination, Separately Recognized Transactions [Table Text Block]



	Expected Payment Period							Successor
Description	Expected Payment Period	Pepco ^(a)		DPL ^(a)		ACE ^(a)		PHI ^(a)		Exelon ^(a)
Rate credits	2016 - 2017	$	91	$	58	$	101	$	250	$	250
Energy efficiency	2016 - 2021	—		—		—		—		120
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	$	77	$	111	$	314	$	513

_______



(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)

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	4,000
Total assets	$	21,792

Current liabilities	$	2,752
Unamortized energy contracts	1,515
Regulatory liabilities	297
Long-term debt, including current maturities	5,636
Deferred income taxes	3,442
Pension and OPEB liability	821
Other liabilities	187
Total liabilities	$	14,650
Total purchase price	$	7,142

Restructuring and Related Costs



	Three Months Ended September 30,				Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2016		2015		2016			2015
Exelon^(b)	$	20	$	22	$	123		$	84
Generation	9		10		29			30
ComEd^(c)	—		3		(6		)	9
PECO	1		1		3			4
BGE^(c)	1		2		(3		)	4
Pepco^(c)	3		1		26			3
DPL^(c)	2		—		18			2
ACE	2		—		17			1



	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		March 24 to September 30,		January 1 to March 23,		Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2016		2015		2016		2016		2015
PHI^(c)	$	7	$	3	$	63	$	29	$	16

______________


(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.



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco^(b)		DPL^(c)		ACE
Nine Months Ended September 30, 2016
Severance benefits^(a)	$	55	$	9	$	2	$	1	$	1	$	42	$	20	$	12	$	10

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include amounts billed by BSC and/or PHISCO through intercompany allocations of $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million for the nine months ended September 30, 2016.




	Exelon			Generation^(a)
Three Months Ended
September 30, 2016	$	(2	)	$	(2	)

Nine Months Ended
September 30, 2016	$	44		$	44

(a) The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended

September 30, 2016.



									Successor
	Exelon			Generation^(a)			ComEd^(a)		PHI
Three Months Ended
September 30, 2016	$	8		$	7		$	—	$	1
September 30, 2015	(3		)	(3		)	—		—

Nine Months Ended
September 30, 2016	$	12		$	10		$	1	$	1
September 30, 2015	18			17			1		—

Schedule of Goodwill [Table Text Block]

Exelon’s and PHI’s carrying amount of goodwill for the nine months ended September 30, 2016 was as follows:



	PHI			Exelon^(a)
Beginning balance, December 31, 2015	$	—		$	2,672
Goodwill from business combination	4,016			4,016
Measurement period adjustments	(16		)	(16		)
Ending balance, September 30, 2016	$	4,000		$	6,672

_____________

(a) As of September 30, 2016, there were no changes to the carrying amount of goodwill for ComEd, see Note 11— Intangible Assets of the Exelon 2015 Form 10-K for further information.

Regulatory Matters (Tables)

9 Months Ended

Sep. 30, 2016

Regulated Operations [Abstract]

Schedule of Regulatory Assets



									Successor
September 30, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	85	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,704		2,238		466		—		—		—		—		—
Removal costs	1,627		1,333		—		151		143		20		123		—
Deferred rent ^(q)	40		—		—		—		40		—		—		—
Energy efficiency and demand response programs	175		135		40		—		—		—		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	79		—		79		—		—		—		—		—
Gas distribution tax repairs	21		—		21		—		—		—		—		—
Energy and transmission programs ^{(h)(i)(r)(j)(k)(l)}	171		72		59		—		40		17		11		12
Over-recovered revenue decoupling ^(o)	5		—		—		5		—		—		—		—
Other	70		3		6		16		45		7		12		24
Total regulatory liabilities	4,985		3,781		679		172		268		44		146		36
Less: current portion	548		204		128		54		101		20		46		35
Total non-current regulatory liabilities	$	4,437	$	3,577	$	551	$	118	$	167	$	24	$	100	$	1



									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 ^(b)	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(d)	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(f)	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 ^{(h)(i)(r)(j)(k)(l)}	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 ^(o)(p)	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 non-current 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 ^{(h)(i)(r)(j)(k)(l)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling ^(o)	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 non-current regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7

______

(a)

(b)

(c)

(d)


(e)	Includes at Exelon and PHI the regulatory asset recorded at PHI for debt costs that are recoverable through the ratemaking process at Pepco, DPL, and ACE which were eliminated at Exelon and PHI as part of acquisition accounting.


(f)	Includes the unamortized regulatory assets recorded for the difference between carrying value and fair value of long-term debt of BGE as of the Constellation merger date 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.


(g)	Represents 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.

(h)

(i)

(j)

(k)

(l)


(m)	As of September 30, 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.


(n)	Represents previously incurred PHI acquisition costs expected to be recovered in distribution rates in the Maryland service territories of Pepco and DPL.

(o)


(p)	Represents the electric distribution costs recoverable from customers under Pepco's Maryland and District of Columbia decoupling mechanisms and DPL's Maryland decoupling mechanism.


(q)	Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease that is recoverable through the ratemaking process at Pepco, DPL and ACE.

(r)

Schedule of Regulatory Liabilities



									Successor
September 30, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	85	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,704		2,238		466		—		—		—		—		—
Removal costs	1,627		1,333		—		151		143		20		123		—
Deferred rent ^(q)	40		—		—		—		40		—		—		—
Energy efficiency and demand response programs	175		135		40		—		—		—		—		—
DLC program costs	8		—		8		—		—		—		—		—
Electric distribution tax repairs	79		—		79		—		—		—		—		—
Gas distribution tax repairs	21		—		21		—		—		—		—		—
Energy and transmission programs ^{(h)(i)(r)(j)(k)(l)}	171		72		59		—		40		17		11		12
Over-recovered revenue decoupling ^(o)	5		—		—		5		—		—		—		—
Other	70		3		6		16		45		7		12		24
Total regulatory liabilities	4,985		3,781		679		172		268		44		146		36
Less: current portion	548		204		128		54		101		20		46		35
Total non-current regulatory liabilities	$	4,437	$	3,577	$	551	$	118	$	167	$	24	$	100	$	1



									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 ^(b)	1,616		64		1,473		79		214		137		36		41
AMI programs	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(d)	189		189		—		—		—		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(f)	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 ^{(h)(i)(r)(j)(k)(l)}	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 ^(o)(p)	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 non-current 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 ^{(h)(i)(r)(j)(k)(l)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling ^(o)	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 non-current regulatory liabilities	$	4,201	$	3,459	$	527	$	184	$	147	$	29	$	111	$	7

______

(a)

(b)

(c)

(d)


(e)	Includes at Exelon and PHI the regulatory asset recorded at PHI for debt costs that are recoverable through the ratemaking process at Pepco, DPL, and ACE which were eliminated at Exelon and PHI as part of acquisition accounting.


(f)	Includes the unamortized regulatory assets recorded for the difference between carrying value and fair value of long-term debt of BGE as of the Constellation merger date 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.


(g)	Represents 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.

(h)

(i)

(j)

(k)

(l)


(m)	As of September 30, 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.


(n)	Represents previously incurred PHI acquisition costs expected to be recovered in distribution rates in the Maryland service territories of Pepco and DPL.

(o)


(p)	Represents the electric distribution costs recoverable from customers under Pepco's Maryland and District of Columbia decoupling mechanisms and DPL's Maryland decoupling mechanism.


(q)	Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease that is recoverable through the ratemaking process at Pepco, DPL and ACE.

(r)

Purchase Of Receivables



													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)

Public Utilities General Disclosures [Table Text Block]

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



	2016
Annual Transmission Filings^(a)	ComEd			BGE			Pepco			DPL			ACE
Initial revenue requirement increase	$	90		$	12		$	2		$	8		$	8
Annual reconciliation (decrease) increase	4			3			(10		)	(10		)	(14		)
Dedicated facilities (decrease) increase ^(b)	—			13			—			—			—
MAPP abandonment recovery decrease ^(c)	—			—			(15		)	(12		)	—
Total revenue requirement increase (decrease)	$	94		$	28		$	(23	)	$	(14	)	$	(6	)

Allowed return on rate base ^(d)	8.47		%	8.09		%	7.88		%	7.21		%	7.83		%
Previously authorized allowed return on rate base ^(d)	8.61		%	8.46		%	8.36		%	7.80		%	8.51		%
Allowed ROE ^(e)	11.50		%	10.50		%	10.50		%	10.50		%	10.50		%

_____________

(a) All rates are effective June 2016.

(b) 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.


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

Early Nuclear Plant Retirements Early Nuclear Plant Retirements (Tables)

9 Months Ended

Sep. 30, 2016

Property, Plant and Equipment [Abstract]

ImplicationsofPotentialEarlyPlantRetirement [Table Text Block]



(in millions)	TMI			Ginna			NMP
Asset Balances
Materials and supplies inventory	$	39		$	31		$	70
Nuclear fuel inventory, net	93			41			214
Completed plant, net	956			124			1,151
Construction work in progress	38			13			53
Liability Balances
Asset retirement obligation	(492		)	(667		)	(780		)

NRC License Renewal Term	2034			2029			2029 (unit 1)
							2046 (unit 2)

Incremental Expense Plant Retirement [Table Text Block]

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

Through September 30, 2016, Exelon's and Generation's results include an incremental $443 million of pre-tax expense for these items as summarized in the table below. Please refer to Note 12 — Nuclear Decommissioning for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the early retirement of Clinton and Quad Cities.




Income statement expense (pre-tax)	September 30, 2016

Depreciation and Amortization
Accelerated depreciation^(a)	$	459
Accelerated nuclear fuel amortization	37
Operating and Maintenance
Increase ARO accretion, net of contractual offset^(b)	2
Contractual offset for ARC depreciation^(b)	(55		)
Total	$	443

_________


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

(b)

Fair Value of Financial Assets and Liabilities (Tables)

9 Months Ended

Sep. 30, 2016

Fair value of financial liabilities recorded at the carrying amount

Exelon



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	567	$	—	$	567	$	—	$	567
Long-term debt (including amounts due within one year)^(a)	34,842		1,075		34,272		2,279		37,626
Long-term debt to financing trusts^(b)	642		—		—		692		692
SNF obligation	1,023		—		856		—		856



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	40	$	—	$	40	$	—	$	40
Long-term debt (including amounts due within one year)^(a)	9,255		—		8,015		1,684		9,699
SNF obligation	1,023		—		856		—		856



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	10	$	—	$	10	$	—	$	10
Long-term debt (including amounts due within one year)^(a)	7,031		—		8,081		—		8,081
Long-term debt to financing trusts^(b)	205		—		—		218		218



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,879	$	—	$	3,266	$	—	$	3,266
Long-term debt to financing trusts	184		—		—		207		207



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,662	$	—	$	2,966	$	—	$	2,966
Long-term debt to financing trusts^(b)	252		—		—		267		267



	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



	September 30, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	517	$	—	$	517	$	—	$	517
Long-term debt (including amounts due within one year)	6,044		—		5,698		594		6,292



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,350	$	—	$	3,000	$	2	$	3,002



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	17	$	—	$	17	$	—	$	17
Long-term debt (including amounts due within one year)^(a)	1,265		—		1,277		101		1,378



	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



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,167	$	—	$	1,058	$	299	$	1,357



	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 September 30, 2016 and December 31, 2015.

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

PHI, Pepco, DPL and ACE



	Successor											Predecessor
	As of September 30, 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)	$	347		$	—		$	—	$	347		$	42		$	—		$	—	$	42
Mark-to-market derivative assets^(b)(c)	1			—			—		1			—			—			18		18
Effect of netting and allocation of collateral	(1		)	—			—		(1		)	—			—			—		—
Mark-to-market derivative assets subtotal	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			14			—		14			—			15			—		15
Life insurance contracts	—			22			21		43			—			27			19		46
Rabbi trust investments subtotal	73			36			21		130			12			42			19		73
Total assets	420			36			21		477			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	$	420		$	8		$	21	$	449		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of September 30, 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)	$	127	$	—		$	—	$	127		$	—		$	—		$	—	$	—		$	194	$	—	$	—	$	194
Mark-to-market derivative assets^(b)	—		—			—		—			1			—			—		1			—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			(1		)	—			—		(1		)	—		—		—		—
Mark-to-market derivative assets subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		14			—		14			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			21		43			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		36			21		100			—			—			—		—			—		—		—		—
Total assets	170		36			21		227			—			—			—		—			194		—		—		194
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	170	$	31		$	21	$	222		$	—		$	(1	)	$	—	$	(1	)	$	194	$	—	$	—	$	194



	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	$	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 16 - 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.



	Generation										Exelon
As of September 30, 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)	$	94	$	—	$	—	$	—	$	94	$	1,645	$	—	$	—	$	—	$	1,645
NDT fund investments
Cash equivalents^(b)	163		20		—		—		183		163		20		—		—		183
Equities	3,566		335		—		1,992		5,893		3,566		335		—		1,992		5,893
Fixed income
Corporate debt	—		1,629		257		—		1,886		—		1,629		257		—		1,886
U.S. Treasury and agencies	1,363		33		—		—		1,396		1,363		33		—		—		1,396
Foreign governments	—		50		—		—		50		—		50		—		—		50
State and municipal debt	—		268		—		—		268		—		268		—		—		268
Other^(c)	—		56		—		510		566		—		56		—		510		566
Fixed income subtotal	1,363		2,036		257		510		4,166		1,363		2,036		257		510		4,166
Middle market lending	—		—		436		23		459		—		—		436		23		459
Private equity	—		—		—		138		138		—		—		—		138		138
Real estate	—		—		—		306		306		—		—		—		306		306
NDT fund investments subtotal^(d)	5,092		2,391		693		2,969		11,145		5,092		2,391		693		2,969		11,145
Pledged assets for Zion Station decommissioning
Cash equivalents	14		—		—		—		14		14		—		—		—		14
Equities	—		1		—		—		1		—		1		—		—		1
Fixed income
U.S. Treasury and agencies	28		2		—		—		30		28		2		—		—		30
Corporate debt	—		3		—		—		3		—		3		—		—		3



	Generation														Exelon
As of September 30, 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 subtotal	28			5			—			—		33			28			5			—			—		33
Middle market lending	—			—			19			68		87			—			—			19			68		87
Pledged assets for Zion Station decommissioning subtotal^(e)	42			6			19			68		135			42			6			19			68		135
Rabbi trust investments
Cash equivalents	10			—			—			—		10			83			—			—			—		83
Mutual funds	19			—			—			—		19			50			—			—			—		50
Fixed income	—			—			—			—		—			—			14			—			—		14
Life insurance contracts	—			18			—			—		18			—			64			21			—		85
Rabbi trust investments subtotal	29			18			—			—		47			133			78			21			—		232
Commodity derivative assets
Economic hedges	883			2,790			1,948			—		5,621			884			2,790			1,948			—		5,622
Proprietary trading	11			51			36			—		98			11			51			36			—		98
Effect of netting and allocation of collateral^(f)	(927		)	(2,527		)	(896		)	—		(4,350		)	(928		)	(2,527		)	(896		)	—		(4,351		)
Commodity derivative assets subtotal	(33		)	314			1,088			—		1,369			(33		)	314			1,088			—		1,369
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			39			—			—		39
Economic hedges	—			28			—			—		28			—			28			—			—		28
Proprietary trading	7			1			—			—		8			7			1			—			—		8
Effect of netting and allocation of collateral	(4		)	(17		)	—			—		(21		)	(4		)	(17		)	—			—		(21		)
Interest rate and foreign currency derivative assets subtotal	3			12			—			—		15			3			51			—			—		54
Other investments	—			—			42			—		42			—			—			42			—		42
Total assets	5,227			2,741			1,842			3,037		12,847			6,882			2,840			1,863			3,037		14,622
Liabilities
Commodity derivative liabilities
Economic hedges	(1,037		)	(2,917		)	(1,160		)	—		(5,114		)	(1,037		)	(2,917		)	(1,404		)	—		(5,358		)
Proprietary trading	(10		)	(53		)	(39		)	—		(102		)	(10		)	(53		)	(39		)	—		(102		)
Effect of netting and allocation of collateral^(f)	1,012			2,777			1,046			—		4,835			1,012			2,777			1,046			—		4,835
Commodity derivative liabilities subtotal	(35		)	(193		)	(153		)	—		(381		)	(35		)	(193		)	(397		)	—		(625		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(18		)	—			—		(18		)	—			(18		)	—			—		(18		)
Economic hedges	—			(19		)	—			—		(19		)	—			(19		)	—			—		(19		)
Proprietary trading	(6		)	—			—			—		(6		)	(6		)	—			—			—		(6		)
Effect of netting and allocation of collateral	8			16			—			—		24			8			16			—			—		24
Interest rate and foreign currency derivative liabilities subtotal	2			(21		)	—			—		(19		)	2			(21		)	—			—		(19		)
Deferred compensation obligation	—			(32		)	—			—		(32		)	—			(131		)	—			—		(131		)
Total liabilities	(33		)	(246		)	(153		)	—		(432		)	(33		)	(345		)	(397		)	—		(775		)
Total net assets	$	5,194		$	2,495		$	1,689		$	3,037	$	12,415		$	6,849		$	2,495		$	1,466		$	3,037	$	13,847



	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
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
NDT 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		)



	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
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
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 $64 million and $52 million of cash received from outstanding repurchase agreements at September 30, 2016 and December 31, 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 September 30, 2016 and December 31, 2015, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(f)

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of September 30, 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)	$	—	$	—		$	—		$	—		$	521	$	—		$	—	$	521		$	375	$	—		$	—	$	375
Rabbi trust investments
Mutual funds	—		—			—			—			7		—			—		7			4		—			—		4
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			7		11			—		18			4		—			—		4
Total assets	—		—			—			—			528		11			—		539			379		—			—		379
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(10		)	—		(10		)	—		(4		)	—		(4		)
Mark-to-market derivative liabilities^(b)	—		—			(244		)	(244		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(244		)	(252		)	—		(10		)	—		(10		)	—		(4		)	—		(4		)
Total net assets (liabilities)	$	—	$	(8	)	$	(244	)	$	(252	)	$	528	$	1		$	—	$	529		$	379	$	(4	)	$	—	$	375



	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 $225 million, respectively, at September 30, 2016, and $23 million and $224 million, respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

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

March 23, 2016.




																			Successor
	Generation															ComEd			PHI					Exelon
Three Months Ended September 30, 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 June 30, 2016	$	715		$	25		$	609			$	37	$	1,386		$	(221	)	$	20	$	—		$	1,185
Total realized / unrealized gains (losses)
Included in net income	(4		)	—			95			^(b)	1		92			—			1		—			93
Included in noncurrent payables to affiliates	6			—			—				—		6			—			—		(6		)	—
Included in payable for Zion Station decommissioning	—			(1		)	—				—		(1		)	—			—		—			(1		)
Included in regulatory assets	—			—			—				—		—			(23		)	—		6			(17		)
Change in collateral	—			—			31				—		31			—			—		—			31
Purchases, sales, issuances and settlements
Purchases	4			—			207			^(d)	3		214			—			—		—			214
Sales	—			(5		)	(2		)		—		(7		)	—			—		—			(7		)
Issuances	—			—			—				—		—			—			—		—			—
Settlements	(28		)	—			—				—		(28		)	—			—		—			(28		)
Transfers into Level 3	—			—			(1		)		1		—			—			—		—			—
Transfers out of Level 3	—			—			(4		)		—		(4		)	—			—		—			(4		)
Balance at September 30, 2016	$	693		$	19		$	935			$	42	$	1,689		$	(244	)	$	21	$	—		$	1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016	$	3		$	—		$	285			$	—	$	288		$	—		$	—	$	—		$	288



																				Successor
	Generation																ComEd			PHI^(c)						Exelon
Nine Months Ended September 30, 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 December 31, 2015	$	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	2				—			(339		)	^(b)	1		(336		)	—			2			—			(334		)
Included in noncurrent payables to affiliates	18				—			—				—		18			—			—			(18		)	—
Included in payable for Zion Station decommissioning	—				1			—				—		1			—			—			—			1
Included in regulatory assets/liabilities	—				—			—				—		—			3			—			18			21
Change in collateral	—				—			(51		)		—		(51		)	—			—			—			(51		)
Purchases, sales, issuances and settlements
Purchases	123				1			289			^(d)	7		420			—			—			—			420
Sales	(1		)		(5		)	(5		)		—		(11		)	—			—			—			(11		)
Issuances	—				—			—				—		—			—			(1		)	—			(1		)
Settlements	(119		)		—			—				—		(119		)	—			—			—			(119		)
Transfers into Level 3	—				—			1				1		2			—			—			—			2
Transfers out of Level 3	—				—			(11		)		—		(11		)	—			—			—			(11		)
Balance as of September 30, 2016	$	693			$	19		$	935			$	42	$	1,689		$	(244	)	$	21		$	—		$	1,466
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2016	$	7			$	—		$	240			$	—	$	247		$	—		$	1		$	—		$	248

___________________

(a)


(b)	Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016, respectively.


(c)	Successor period represents activity from March 24, 2016 through September 30, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco and DPL for the three and nine months ended September 30, 2016.


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




	Generation															ComEd					Exelon
Three Months Ended September 30, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(a)			Eliminated in Consolidation		Total
Balance as of June 30, 2015	$	667		$	41		$	1,021			$	30	$	1,759		$	(223	)	$	—	$	1,536
Total realized / unrealized gains (losses)													—
Included in net income	—			—			(48		)	^(b)	—		(48		)	—			—		(48		)
Included in noncurrent payables to affiliates	—			—			—				—		—			—			—		—
Included in payable for Zion Station decommissioning	—			1			—				—		1			—			—		1
Included in regulatory assets	—			—			—				—		—			(20		)	—		(20		)
Change in collateral	—			—			90				—		90			—			—		90
Purchases, sales, issuances and settlements
Purchases	15			—			50				2		67			—			—		67
Sales	—			(13		)	(5		)		—		(18		)	—			—		(18		)
Settlements	(13		)	—			—				—		(13		)	—			—		(13		)
Transfers into Level 3	—			—			69				—		69			—			—		69
Transfers out of Level 3	—			—			(3		)		—		(3		)	—			—		(3		)
Balance as of September 30, 2015	$	669		$	29		$	1,174			$	32	$	1,904		$	(243	)	$	—	$	1,661
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2015	$	(1	)	$	—		$	181			$	—	$	180		$	—		$	—	$	180



	Generation															ComEd						Exelon
Nine Months Ended September 30, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(a)			Eliminated in Consolidation			Total
Balance as of December 31, 2014	$	605		$	50		$	1,050			$	3	$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income	4			—			(87		)	^(b)	—		(83		)	—			—			(83		)
Included in noncurrent payables to affiliates	17			—			—				—		17			—			(17		)	—
Included in payable for Zion Station decommissioning	—			2			—				—		2			—			—			2
Included in regulatory assets	—			—			—				—		—			(36		)	17			(19		)
Change in collateral	—			—			72				—		72			—			—			72
Purchases, sales, issuances and settlements
Purchases	122			1			107				29		259			—			—			259
Sales	(8		)	(24		)	(10		)		—		(42		)	—			—			(42		)
Settlements	(75		)	—			—				—		(75		)	—			—			(75		)
Transfers into Level 3	4			—			80				—		84			—			—			84
Transfers out of Level 3	—			—			(38		)		—		(38		)	—			—			(38		)
Balance as of September 30, 2015	$	669		$	29		$	1,174			$	32	$	1,904		$	(243	)	$	—		$	1,661
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of September 30, 2015	$	2		$	—		$	536			$	—	$	538		$	—		$	—		$	538

_________

(a)


(b)	Includes a reduction for the reclassification of $229 million and $623 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2015, respectiv

Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis

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

isk.

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



Type of trade	Fair Value at September 30, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	788		Discounted Cash Flow	Forward power price	$6	-	$130
					Forward gas price	$1.24	-	$9.53
				Option Model	Volatility percentage	5%	-	115%

Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(3	)	Discounted Cash Flow	Forward power price	$15	-	$68

Mark-to-market derivatives (Exelon and ComEd)	$	(244	)	Discounted Cash Flow	Forward heat rate^(b)	8x	-	9x
					Marketability reserve	3%	-	8%
					Renewable factor	86%	-	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 $150 million as of September 30, 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

Fair value of financial liabilities recorded at the carrying amount

Generation



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	40	$	—	$	40	$	—	$	40
Long-term debt (including amounts due within one year)^(a)	9,255		—		8,015		1,684		9,699
SNF obligation	1,023		—		856		—		856



	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

Fair value of financial liabilities recorded at the carrying amount

ComEd



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	10	$	—	$	10	$	—	$	10
Long-term debt (including amounts due within one year)^(a)	7,031		—		8,081		—		8,081
Long-term debt to financing trusts^(b)	205		—		—		218		218



	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

Fair value of financial liabilities recorded at the carrying amount

PECO



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,879	$	—	$	3,266	$	—	$	3,266
Long-term debt to financing trusts	184		—		—		207		207



	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

Fair value of financial liabilities recorded at the carrying amount

BGE



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,662	$	—	$	2,966	$	—	$	2,966
Long-term debt to financing trusts^(b)	252		—		—		267		267



	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

PEPCO Holdings Inc [Member]

Fair value of financial liabilities recorded at the carrying amount

PHI



	September 30, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	517	$	—	$	517	$	—	$	517
Long-term debt (including amounts due within one year)	6,044		—		5,698		594		6,292



	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

Fair value of financial liabilities recorded at the carrying amount

Pepco



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,350	$	—	$	3,000	$	2	$	3,002



	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

Fair value of financial liabilities recorded at the carrying amount

DPL



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	17	$	—	$	17	$	—	$	17
Long-term debt (including amounts due within one year)^(a)	1,265		—		1,277		101		1,378



	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

Fair value of financial liabilities recorded at the carrying amount

ACE



	September 30, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,167	$	—	$	1,058	$	299	$	1,357



	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

Derivative Financial Instruments (Tables)

9 Months Ended

Sep. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

September 30, 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)	$	—		$	15		$	4		$	(10	)	$	9		$	—	$	9
Mark-to-market derivative assets (noncurrent assets)	—			13			4			(11		)	6			39		45
Total mark-to-market derivative assets	—			28			8			(21		)	15			39		54
Mark-to-market derivative liabilities (current liabilities)	(8		)	(10		)	(3		)	12			(9		)	—		(9		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(10		)	(9		)	(3		)	12			(10		)	—		(10		)
Total mark-to-market derivative liabilities	(18		)	(19		)	(6		)	24			(19		)	—		(19		)
Total mark-to-market derivative net assets (liabilities)	$	(18	)	$	9		$	2		$	3		$	(4	)	$	39	$	35

_________

(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															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)	$	—		$	10		$	10		$	(5	)	$	15		$	—	$	15
Mark-to-market derivative assets (noncurrent assets)	—			10			5			(1		)	14			25		39
Total mark-to-market derivative assets	—			20			15			(6		)	29			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	$	38

__________

(a)


(b)

The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 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)	$	3,482		$	67		$	(2,804	)	$	745		$	—		$	1	$	(1	)	$	—	$	—	$	745
Mark-to-market derivative assets (noncurrent assets)	2,139			31			(1,546		)	624			—			—		—			—		—		624
Total mark-to-market derivative assets	5,621			98			(4,350		)	1,369			—			1		(1		)	—		—		1,369
Mark-to-market derivative liabilities (current liabilities)	(3,229		)	(61		)	3,096			(194		)	(19		)	—		—			—		—		(213		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(1,885		)	(41		)	1,739			(187		)	(225		)	—		—			—		—		(412		)
Total mark-to-market derivative liabilities	(5,114		)	(102		)	4,835			(381		)	(244		)	—		—			—		—		(625		)
Total mark-to-market derivative net assets (liabilities)	$	507		$	(4	)	$	485		$	988		$	(244	)	$	1	$	(1	)	$	—	$	—	$	744

______

(a)


(b)	Current and noncurrent assets are shown net of collateral of $135 million and $84 million, respectively, and current and noncurrent liabilities are shown net of collateral of $156 million and $110 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $485 million at September 30, 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
Description	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.

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:



		Three Months Ended September 30,
	Income Statement Location	2016			2015			2016			2015
	Income Statement Location	Gain (loss) on Swaps						Gain (loss) on Borrowings
Exelon	Interest expense	$	(8	)	$	16		$	14		$	(13	)

		Nine Months Ended September 30,
	Income Statement Location	2016			2015			2016			2015
	Income Statement Location	Gain (loss) on Swaps						Gain (loss) on Borrowings
Generation	Interest expense^(a)	$	—		$	(1	)	$	—		$	—
Exelon	Interest expense	15			15			(3		)	(4		)

__________


(a)	For the nine months ended September 30, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

The activity of accumulated OCI related to cash flow hedges

amounts reclassified from AOCI, when combined with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.




		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended September 30, 2016	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
AOCI derivative loss at June 30, 2016		$	(25	)	$	(26	)
Effective portion of changes in fair value		1			3
AOCI derivative loss at September 30, 2016		$	(24	)	$	(23	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation				Exelon
Nine Months Ended September 30, 2016	Income Statement Location	Total Cash Flow Hedges				Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2015		$	(21	)		$	(19	)
Effective portion of changes in fair value		—				(1		)
Reclassifications from AOCI to net income	Interest Expense	(3		)	^(a)	(3		)	^(a)
Accumulated OCI derivative loss at September 30, 2016		$	(24	)		$	(23	)




		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended September 30, 2015	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
AOCI derivative loss at June 30, 2015		(21		)	$	(19	)
Effective portion of changes in fair value		(7		)	(8		)
Reclassifications from AOCI to net income	Interest Expense	3			3
AOCI derivative loss at September 30, 2015		$	(25	)	$	(24	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Nine Months Ended September 30, 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		(13		)	(18		)
Reclassifications from AOCI to net income	Other, net	—			16			^(b)
Reclassifications from AOCI to net income	Interest Expense	8			8
Reclassifications from AOCI to net income	Operating Revenues	(2		)	(2		)
Accumulated OCI derivative loss at September 30, 2015		$	(25	)	$	(24	)

Other Derivatives - Gain (loss) and reclassification



	Generation								Exelon
Nine Months Ended September 30, 2016	Operating Revenues			Purchased Power and Fuel		Total			Total
Change in fair value of commodity positions	$	127		$	36	$	163		$	163
Reclassification to realized at settlement of commodity positions	(484		)	217		(267		)	(267		)
Net commodity mark-to-market gains (losses)	(357		)	253		(104		)	(104		)
Change in fair value of treasury positions	(3		)	—		(3		)	(3		)
Reclassification to realized at settlement of treasury positions	(6		)	—		(6		)	(6		)
Net treasury mark-to-market gains (losses)	(9		)	—		(9		)	(9		)
Net mark-to-market gains (losses)	$	(366	)	$	253	$	(113	)	$	(113	)




	Generation									Exelon Corporate		Exelon
Three Months Ended September 30, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense		Total
Change in fair value of commodity positions	$	136		$	(178	)	$	(42	)	$	—	$	(42	)
Reclassification to realized at settlement of commodity positions	(143		)	46			(97		)			(97		)
Net commodity mark-to-market gains (losses)	(7		)	(132		)	(139		)	—		(139		)
Change in fair value of treasury positions	2			—			2			—		2
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	—		(2		)
Net treasury mark-to-market gains (losses)	—			—			—			—		—
Net mark-to-market gains (losses)	$	(7	)	$	(132	)	$	(139	)	$	—	$	(139	)



	Generation									Exelon Corporate		Exelon
Nine Months Ended September 30, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense		Total
Change in fair value of commodity positions	$	513		$	(163	)	$	350		$	—	$	350
Reclassification to realized at settlement of commodity positions	(347		)	249			(98		)	—		(98		)
Net commodity mark-to-market gains (losses)	166			86			252			—		252
Change in fair value of treasury positions	12			—			12			36		48
Reclassification to realized at settlement of treasury positions	(6		)	—			(6		)	64		58
Net treasury mark-to-market gains (losses)	6			—			6			100		106
Net mark-to-market gains (losses)	$	172		$	86		$	258		$	100	$	358

Prop

the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Change in fair value of commodity positions	$	4		$	(4	)	$	18		$	5
Reclassification to realized at settlement of commodity positions	(6		)	(2		)	(17		)	(8		)
Net commodity mark-to-market gains (losses)	(2		)	(6		)	1			(3		)
Change in fair value of treasury positions	—			3			(2		)	7
Reclassification to realized at settlement of treasury positions	1			(3		)	2			(9		)
Net treasury mark-to-market gains (losses)	1			—			—			(2		)
Total net mark-to-market gains (losses)	$	(1	)	$	(6	)	$	1		$	(5	)

Schedule of Derivative Instruments [Table Text Block]

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

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 September 30, 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, further discussed in ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $24 million, $45 million,$22 million, $47 million, $12 million, and $10 million as of September 30, 2016, respectively.



Rating as of September 30, 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	$	1,017	$	4	$	1,013	1	$	355
Non-investment grade	175		22		153		—	—
No external ratings
Internally rated — investment grade	423		3		420		—	—
Internally rated — non-investment grade	61		3		58		—	—
Total	$	1,676	$	32	$	1,644	1	$	355



Net Credit Exposure by Type of Counterparty	As of September 30, 2016
Financial institutions	$	117
Investor-owned utilities, marketers, power producers	757
Energy cooperatives and municipalities	712
Other	58
Total	$	1,644

_____


(a)	As of September 30, 2016, credit collateral held from counterparties where Generation had credit exposure included $10 million of cash and $22 million of letters of credit. The credit collateral does not include non-liquid collateral.

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



Credit-Risk Related Contingent Feature	September 30, 2016			December 31, 2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(975	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	664			684
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(311	)	$	(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.

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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-Section 50
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Reference 2: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 815
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Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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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
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Schedule of Short-term Debt

Debt and Credit Agreements (Tables)

9 Months Ended

Sep. 30, 2016

Debt Disclosure [Abstract]



Commercial Paper Borrowings	September 30, 2016		December 31, 2015
ComEd	$	10	$	294
BGE	—		210
PHI Corporate	—		484
Pepco	—		64
DPL	17		105
ACE	—		5

Schedule Of Issuance Of Long Term Debt

During the nine months ended September 30, 2016, the following long-term debt was issued:



Company	Type	Interest Rate		Maturity	Amount		Use of Proceeds
Exelon Corporate	Senior Unsecured Notes	2.45	%	April 15, 2021	$	300	Repay commercial paper issued by PHI and for general corporate purposes
Exelon Corporate	Senior Unsecured Notes	3.40	%	April 15, 2026	$	750	Repay commercial paper issued by PHI and for general corporate purposes
Exelon Corporate	Senior Unsecured Notes	4.45	%	April 15, 2046	$	750	Repay commercial paper issued by PHI and for general corporate purposes
Generation	Renewable Power Generation Nonrecourse Debt	4.11	%	March 31, 2035	$	150	Paydown long term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general corporate purposes
Generation	Albany Green Energy Project Financing	LIBOR + 1.25%		November 17, 2017	$	86	Albany Green Energy biomass generation development
Generation	Energy Efficiency Project Financing	3.17	%	December 31, 2017	$	16	Funding to install energy conservation measures in Brooklyn, NY
Generation	Energy Efficiency Project Financing	3.42	%	January 31, 2018	$	13	Funding to install energy conservation measures for the Naval Station Great Lakes project
ComEd	First Mortgage Bonds, Series 120	2.55	%	June 15, 2026	$	500	Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes
ComEd	First Mortgage Bonds, Series 121	3.65	%	June 15, 2046	$	700	Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes
Generation	Energy Efficiency Project Financing	3.52	%	April 30, 2018	$	11	Funding to install energy conservation measures for the Smithsonian Zoo project
Pepco	Energy Efficiency Project Financing	3.30	%	December 15, 2017	$	2	Funding to install energy conservation measures for the DOE Germantown project
BGE	Notes	2.40	%	August 15, 2026	$	350	Redeem the $190M of outstanding preference shares and for general corporate purposes
BGE	Notes	3.50	%	August 15, 2046	$	500	Redeem the $190M of outstanding preference shares and for general corporate purposes
PECO^(a)	First Mortgage Bonds	1.70	%	September 15, 2021	$	300	Refinance maturing mortgage bonds
Generation	SolGen Nonrecourse Debt	3.93	%	September 30, 2036	$	150	General corporate purposes
Generation	ExGen Texas Power Nonrecourse Debt	LIBOR + 4.25%		September 18, 2019	$	4	General corporate purposes for EGTP

Retirement and Redemptions of Current and Long-Term Debt

Income Taxes (Tables)

9 Months Ended

Sep. 30, 2016

Income Tax Disclosure [Abstract]

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]



	Three Months Ended September 30, 2016
						Successor
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.8	2.6	7.3	2.4	5.2	5.6	5.6	5.2	6.1
Qualified nuclear decommissioning trust fund income	4.0	7.8	—	—	—	—	—	—	—
Domestic production activities deduction	—	—	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	—	—	—	—	—
Amortization of investment tax credit, net deferred taxes	(0.9)	(1.6)	(0.6)	(0.1)	(0.2)	(0.1)	—	(0.2)	(0.1)
Plant basis differences	(3.0)	—	(1.9)	(6.7)	(0.5)	(5.0)	(6.7)	(1.3)	(4.6)
Production tax credits and other credits	(2.9)	(5.7)	(0.1)	—	—	—	—	—	—
Noncontrolling interests	0.2	0.5	—	—	—	—	—	—	—
Statute of limitations expiration	(0.1)	0.3	—	—	—	—	—	—	—
Penalties	4.3	—	27.2	—	—	—	—	—	—
Merger expenses	(0.6)	—	—	—	—	(5.7)	(2.3)	(8.6)	(2.9)
Other	(0.8)	(0.5)	0.1	0.1	(0.4)	(0.7)	(0.9)	0.1	(0.6)
Effective income tax rate	39.0%	38.4%	67.0%	30.7%	39.1%	29.1%	30.7%	30.2%	32.9%



	Three Months Ended September 30, 2015
						Predecessor
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	2.7	2.1	5.0	1.2	5.3	6.2	4.8	7.4	5.4
Qualified nuclear decommissioning trust fund income	(5.4)	(12.5)	—	—	—	—	—	—	—
Domestic production activities deduction	(4.9)	(11.6)	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	0.2	—	—	—	—
Amortization of investment tax credit, net deferred taxes	(2.3)	(5.2)	(0.3)	(0.1)	(0.2)	(0.2)	(0.1)	(0.6)	(0.3)
Plant basis differences	(1.4)	—	(0.1)	(7.0)	(0.6)	(3.7)	(3.5)	(3.5)	(3.1)
Production tax credits and other credits	(3.8)	(9.0)	—	—	—	(1.2)	—	—	—
Noncontrolling interests	1.7	3.9	—	—	—	—	—	—	—
Statute of limitations expiration	(6.4)	(15.2)	—	—	—	—	—	—	—
Other	1.2	0.4	0.3	—	(0.4)	(1.1)	(1.4)	(0.8)	1.9
Effective income tax rate	16.4%	(12.1)%	39.9%	29.1%	39.3%	35.0%	34.8%	37.5%	38.9%



									Successor	Predecessor
	Nine Months Ended September 30, 2016								March 24, 2016 to September 30, 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)	2.5	2.6	5.4	1.3	4.8	23.0	310.5	5.5	4.4	11.9
Qualified nuclear decommissioning trust fund income	4.8	8.8	—	—	—	—	—	—	—	—
Domestic production activities deduction	—	—	—	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.3)	(2.0)	(0.3)	(0.1)	(0.2)	(0.2)	(17.9)	0.5	0.5	(0.9)
Plant basis differences	(4.5)	—	(0.6)	(8.8)	(3.3)	(29.0)	(98.6)	7.8	17.5	(13.5)
Production tax credits and other credits	(4.1)	(7.6)	—	—	—	—	—	—	—	—
Noncontrolling interests	0.5	0.9	—	—	—	—	—	—	—	—
Statute of limitations expiration	(0.5)	(1.7)	—	—	—	—	—	—	—
Penalties	2.3	—	5.6	—	—	—	—	—	—
Merger expenses	6.2	—	—	—	—	36.7	635.9	(35.4)	(49.8)	11.1
Other^(c)	(1.8)	(2.1)	—	(1.5)	—	(2.5)	35.1	0.4	1.4	3.6
Effective income tax rate	39.1%	33.9%	45.1%	25.9%	36.3%	63.0%	900.0%	13.8%	9.0%	47.2%



	Nine Months Ended September 30, 2015
						Predecessor
	Exelon	Generation	ComEd	PECO	BGE	PHI	Pepco	DPL	ACE
U.S. Federal statutory rate	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%	35.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	3.1	2.8	5.2	1.2	5.3	7.1	4.6	6.1	5.5
Qualified nuclear decommissioning trust fund income	(0.9)	(1.6)	—	—	—	—	—	—	—
Domestic production activities deduction	(2.8)	(4.9)	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	0.2	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.2)	(1.9)	(0.3)	(0.1)	(0.1)	(0.3)	(0.1)	(0.4)	(0.5)
Plant basis differences	(1.2)	—	(0.1)	(7.3)	(0.4)	(5.0)	(6.2)	(2.0)	(2.5)
Production tax credits and other credits	(2.2)	(3.8)	—	—	—	(1.9)	—	—	—
Noncontrolling interests	—	0.1	—	—	—	—	—	—	—
Statute of limitations expiration	(1.6)	(2.9)	—	—	—	—	—	—	—
Other	0.9	0.6	0.2	0.2	(0.1)	(0.1)	(0.7)	(0.5)	0.8
Effective income tax rate	29.1%	23.4%	40.0%	29.0%	39.9%	34.8%	32.6%	38.2%	38.3%

Nuclear Decommissioning (Tables) - Exelon Generation Co L L C [Member]

9 Months Ended

Sep. 30, 2016

Schedule Of Nuclear Decommissioning [Line Items]

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 December 31, 2015 to September 30, 2016:



Nuclear decommissioning ARO at December 31, 2015^(a)	$	8,246
Accretion expense	325
Net increase due to changes in, and timing of, estimated cash flows	444
Costs incurred to decommission retired plants	(6		)
Nuclear decommissioning ARO at September 30, 2016^(a)	$	9,009

_________


(a)	Includes $44 million and $7 million for the current portion of the ARO at September 30, 2016 and December 31, 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 the three and nine months ended September 30, 2016 and 2015:



	Exelon and Generation					Exelon and Generation
	Three Months Ended September 30,					Nine Months Ended September 30,
	2016		2015			2016		2015
Net unrealized gains (losses) on decommissioning trust funds — Regulatory Agreement Units^(a)	$	155	$	(301	)	$	286	$	(385	)
Net unrealized gains (losses) on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	116		(218		)	216		(274		)

_________


(a)	Net unrealized gains 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)


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

Zion Station pledged assets

September 30, 2016 and December 31, 2015:



	Exelon and Generation
	September 30, 2016		December 31, 2015
Carrying value of Zion Station pledged assets	$	135	$	206
Payable to Zion Solutions^(a)	124		189
Current portion of payable to Zion Solutions^(b)	91		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)	855		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.

Retirement Benefits (Tables)

9 Months Ended

Sep. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule Of Pension And Other Postretirement Benefit Costs



	Three Months Ended September 30,				Nine Months Ended September 30,
Pension and Other Postretirement Benefit Costs	2016		2015		2016		2015
Exelon	$	161	$	159	$	458	$	476
Generation	54		67		163		200
ComEd	41		52		124		155
PECO	8		10		25		29
BGE	17		16		51		49
BSC^(a)	13		14		37		43
Pepco^(b)	8		7		24		22
DPL^(b)	4		3		13		11
ACE^(b)	4		3		11		11
PHISCO^(a)(b)	12		12		33		29



	Successor		Predecessor		Successor		Predecessor
Pension and Other Postretirement Benefit Costs	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016		Nine Months Ended September 30, 2015
PHI	$	28	$	25	$	58	$	23	$	73

_________


(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, PHI, Pepco, DPL or ACE amounts above.

Schedule Of Defined Contributions

The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2016 and 2015:



	Three Months Ended September 30,				Nine Months Ended September 30,
Savings Plan Matching Contributions	2016		2015		2016		2015
Exelon	$	51	$	51	$	107	$	111
Generation	31		27		56		60
ComEd	10		10		23		23
PECO	3		3		7		7
BGE	2		5		5		10
BSC^(a)	2		6		9		11
Pepco^(b)	—		—		2		2
DPL^(b)	1		1		2		2
ACE^(b)	—		—		1		1
PHISCO^(a)(b)	2		2		5		5



	Successor		Predecessor		Successor		Predecessor
Savings Plan Matching Contributions	Three Months Ended September 30, 2016		Three Months Ended September 30, 2015		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016		Nine Months Ended September 30, 2015
PHI	$	3	$	3	$	7	$	3	$	10

_________


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


(b)	Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million,and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016.

Schedule of Net Benefit Costs [Table Text Block]



	Pension Benefits Three Months Ended September 30,						Other Postretirement Benefits Three Months Ended September 30,
Components of net periodic benefit cost:	2016			2015			2016			2015
Service cost	$	92		$	82		$	27		$	30
Interest cost	215			178			47			42
Expected return on assets	(293		)	(257		)	(42		)	(38		)
Amortization of:
Prior service cost (benefit)	3			3			(48		)	(43		)
Actuarial loss	142			142			18			20
Net periodic benefit cost	$	159		$	148		$	2		$	11



	Pension Benefits Nine Months Ended September 30,						Other Postretirement Benefits Nine Months Ended September 30,
	2016^(a)			2015			2016^(a)			2015
Components of net periodic benefit cost:
Service cost	$	262		$	245		$	80		$	89
Interest cost	616			533			138			125
Expected return on assets	(847		)	(770		)	(121		)	(113		)
Amortization of:
Prior service cost (benefit)	10			10			(138		)	(130		)
Actuarial loss	411			427			47			60
Net periodic benefit cost	$	452		$	445		$	6		$	31

_______


(a)	PHI net periodic benefit costs for the period prior to the merger are not included in the table above.



	Predecessor
	PHI
	Pension Benefits									Other Postretirement Benefits
Components of net periodic benefit cost:	January 1, 2016 to March 23, 2016			Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015			January 1, 2016 to March 23, 2016			Three Months Ended September 30, 2015			Nine Months Ended September 30, 2015
Service cost	$	12		$	15		$	43		$	1		$	2		$	5
Interest cost	26			28			82			6			6			18
Expected return on assets	(30		)	(35		)	(105		)	(5		)	(6		)	(17		)
Amortization of:
Prior service cost (benefit)	—			—			1			(3		)	(3		)	(9		)
Actuarial loss	14			16			49			2			2			6
Net periodic benefit cost	$	22		$	24		$	70		$	1		$	1		$	3

Severance (Tables)

9 Months Ended

Sep. 30, 2016

Restructuring and Related Activities [Abstract]

Activity of severance obligations for the corporate restructuring (excluding obligations recorded in equity)



															Successor
Severance Liability	Exelon			Generation			ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Balance at December 31, 2015	$	35		$	23		$	3		$	—	$	1		$	—		$	—		$	—		$	—
Severance charges^(a)(b)	136			63			1			—		—			53			1			1			—
Payments	(39		)	(7		)	(1		)	—		(1		)	(25		)	(1		)	(1		)	—
Balance at September 30, 2016	$	132		$	79		$	3		$	—	$	—		$	28		$	—		$	—		$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration, the Clinton and Quad Cities early plant retirements and the cost management program.


(b)	Represents activity from March 24, 2016 to September 30, 2016 for PHI, Pepco, DPL and ACE.



	Exelon		Generation		ComEd		PECO		BGE
Nine Months Ended September 30, 2016
Severance benefits^(a)	$	18	$	13	$	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 nine months ended September 30, 2016.

Restructuring and Related Costs



	Three Months Ended September 30,				Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2016		2015		2016			2015
Exelon^(b)	$	20	$	22	$	123		$	84
Generation	9		10		29			30
ComEd^(c)	—		3		(6		)	9
PECO	1		1		3			4
BGE^(c)	1		2		(3		)	4
Pepco^(c)	3		1		26			3
DPL^(c)	2		—		18			2
ACE	2		—		17			1



	Successor		Predecessor		Successor		Predecessor
	Three Months Ended September 30,		Three Months Ended September 30,		March 24 to September 30,		January 1 to March 23,		Nine Months Ended September 30,
Acquisition, Integration and Financing Costs^(a)	2016		2015		2016		2016		2015
PHI^(c)	$	7	$	3	$	63	$	29	$	16

______________


(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.



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco^(b)		DPL^(c)		ACE
Nine Months Ended September 30, 2016
Severance benefits^(a)	$	55	$	9	$	2	$	1	$	1	$	42	$	20	$	12	$	10

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include amounts billed by BSC and/or PHISCO through intercompany allocations of $8 million, $2 million, $1 million, $1 million, $19 million, $11 million and $10 million for the nine months ended September 30, 2016.




	Exelon			Generation^(a)
Three Months Ended
September 30, 2016	$	(2	)	$	(2	)

Nine Months Ended
September 30, 2016	$	44		$	44

(a) The amounts above for Generation include $2 million for amounts billed by BSC through intercompany allocations for the nine months ended

September 30, 2016.



									Successor
	Exelon			Generation^(a)			ComEd^(a)		PHI
Three Months Ended
September 30, 2016	$	8		$	7		$	—	$	1
September 30, 2015	(3		)	(3		)	—		—

Nine Months Ended
September 30, 2016	$	12		$	10		$	1	$	1
September 30, 2015	18			17			1		—

Schedule of Restructuring Reserve by Type of Cost [Table Text Block]



															Successor
Severance Liability	Exelon			Generation			ComEd			PECO		BGE			PHI			Pepco			DPL			ACE
Balance at December 31, 2015	$	35		$	23		$	3		$	—	$	1		$	—		$	—		$	—		$	—
Severance charges^(a)(b)	136			63			1			—		—			53			1			1			—
Payments	(39		)	(7		)	(1		)	—		(1		)	(25		)	(1		)	(1		)	—
Balance at September 30, 2016	$	132		$	79		$	3		$	—	$	—		$	28		$	—		$	—		$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration, the Clinton and Quad Cities early plant retirements and the cost management program.


(b)	Represents activity from March 24, 2016 to September 30, 2016 for PHI, Pepco, DPL and ACE.



	Exelon		Generation		ComEd		PECO		BGE
Nine Months Ended September 30, 2016
Severance benefits^(a)	$	18	$	13	$	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 nine months ended September 30, 2016.

Mezzanine Equity Mezzanine Equity (Tables)

9 Months Ended

Sep. 30, 2016

Noncontrolling Interest [Abstract]

Redeemable Noncontrolling Interest [Table Text Block]

The following table summarizes the changes in the contingently redeemable noncontrolling interests for the nine months ended September 30, 2016:



Balance at December 31, 2015	$	28
Cash received from noncontrolling interests	105
Release of contingency	(107		)
Balance at September 30, 2016	$	26

Changes in Accumulated Other Comprehensive Income (Tables)

9 Months Ended

Sep. 30, 2016

Changes in Accumulated Other Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

nine months ended September 30, 2016 and 2015:



Nine Months Ended September 30, 2016	Gains and (losses) on Cash Flow Hedges			Unrealized Gains and (losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments			Total
Exelon^(a)
Beginning balance	$	(19	)	$	3	$	(2,565	)	$	(40	)	$	(3	)	$	(2,624	)
OCI before reclassifications	(1		)	—		(2		)	3			(5		)	(5		)
Amounts reclassified from AOCI^(b)	(3		)	—		104			5			—			106
Net current-period OCI	(4		)	—		102			8			(5		)	101
Ending balance	$	(23	)	$	3	$	(2,463	)	$	(32	)	$	(8	)	$	(2,523	)
Generation^(a)
Beginning balance	$	(21	)	$	1	$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	—			1		—			3			1			5
Amounts reclassified from AOCI^(b)	(3		)	—		—			5			—			2
Net current-period OCI	(3		)	1		—			8			1			7
Ending balance	$	(24	)	$	2	$	—		$	(32	)	$	(2	)	$	(56	)
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	)



Nine Months Ended September 30, 2015	Gains and (losses) on Hedging Activity			Unrealized Gains and (losses) on Marketable Securities		Pension and Non-Pension Postretirement Benefit Plan Items			Foreign Currency Items			AOCI of Equity Investments		Total
Exelon^(a)
Beginning balance	$	(28	)	$	3	$	(2,640	)	$	(19	)	$	—	$	(2,684	)
OCI before reclassifications	(18		)	—		(29		)	(17		)	—		(64		)
Amounts reclassified from AOCI^(b)	22			—		130			—			—		152
Net current-period OCI	4			—		101			(17		)	—		88
Ending balance	$	(24	)	$	3	$	(2,539	)	$	(36	)	$	—	$	(2,596	)
Generation^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—	$	(36	)
OCI before reclassifications	(13		)	—		—			(17		)	—		(30		)
Amounts reclassified from AOCI^(b)	6			—		—			—			—		6
Net current-period OCI	(7		)	—		—			(17		)	—		(24		)
Ending balance	$	(25	)	$	1	$	—		$	(36	)	$	—	$	(60	)
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	—			—		—			—			—		—
Amounts reclassified from AOCI^(b)	1			—		4			—			—		5
Net current-period OCI	1			—		4			—			—		5
Ending balance	$	(8	)	$	—	$	(33	)	$	—		$	—	$	(41	)

________


(a)	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.


(b)	See next tables for details about these reclassifications.

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 three and nine months ended September 30, 2016 and 2015.

Three Months Ended September 30, 2016




Details about AOCI components	Items reclassified out of AOCI^(a)						Affected line item in the Statement of Operations and Comprehensive Income
	Exelon			Generation
Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	19		$	—
Actuarial losses^(b)	(76		)	—
Total before tax	(57		)	—
Tax benefit	22			—
Net of tax	$	(35	)	$	—

Gains (losses) on foreign currency translation
Other	$	(5	)	$	(5	)	Other income and (deductions)
Total before tax	(5		)	(5		)
Tax expense	—			—
Net of tax	$	(5	)	$	(5	)

Total Reclassifications for the period	$	(40	)	$	(5	)	Comprehensive income

Nine Months Ended September 30, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement 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	$	5		$	5		$	—		Interest expense
Total before tax	5			5			—
Tax expense	(2		)	(2		)	—
Net of tax	$	3		$	3		$	—		Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	57		$	—		$	—
Actuarial losses^(b)	(227		)	—			(1		)
Total before tax	(170		)	—			(1		)
Tax benefit	66			—			—
Net of tax	$	(104	)	$	—		$	(1	)


Gains (losses) on foreign currency translation
Other	$	(5	)	$	(5	)	$	—		Other income and (deductions)
Total before tax	(5		)	(5		)	—
Tax expense	—			—			—
Net of tax	$	(5	)	$	(5	)	$	—

Total Reclassifications	$	(106	)	$	(2	)	$	(1	)	Comprehensive income

Three Months Ended September 30, 2015




Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement of Operations and Comprehensive Income
							Predecessor
	Exelon			Generation			PHI
Gains and (losses) on cash flow hedges
Other cash flow hedges	$	(4	)	$	(4	)	$	(1	)	Interest expense
Total before tax	(4		)	(4		)	(1		)
Tax expense	1			1			—
Net of tax	$	(3	)	$	(3	)	$	(1	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	19		$	—		$	—
Actuarial losses^(b)	(90		)	—			(2		)
Total before tax	(71		)	—			(2		)
Tax expense	28			—			2
Net of tax	$	(43	)	$	—		$	—

Total Reclassifications for the period	$	(46	)	$	(3	)	$	(1	)	Comprehensive income

Nine Months Ended September 30, 2015



Details about AOCI components	Items reclassified out of AOCI^(a)									Affected line item in the Statement 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	13			3			—
Net of tax	$	(22	)	$	(6	)	$	(1	)	Comprehensive income

Amortization of pension and other postretirement benefit plan items
Prior service costs^(b)	$	57		$	—		$	—
Actuarial losses^(b)	(270		)	—			(7		)
Total before tax	(213		)	—			(7		)
Tax benefit	83			—			3
Net of tax	$	(130	)	$	—		$	(4	)

Total Reclassifications	$	(152	)	$	(6	)	$	(5	)	Comprehensive income

_______


(a)	Amounts in parenthesis represent a decrease in net income.


(b)	This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 13 — Retirement Benefits for additional details).

Schedule Of Other Comprehensive Income Loss Tax

The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 2016 and 2015:



	Three Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2016			2015
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	7		$	8		$	22		$	22
Actuarial loss reclassified to periodic cost	(29		)	(35		)	(88		)	(105		)
Pension and non-pension postretirement benefit plans valuation adjustment	1			—			1			17
Change in unrealized gain/(loss) on cash flow hedges	(1		)	3			3			(3		)
Change in unrealized loss on equity investments	—			—			3			—
Change in unrealized gain on marketable securities	(1		)	—			(1		)	—
Total	$	(23	)	$	(24	)	$	(60	)	$	(69	)

Generation
Change in unrealized gain/(loss) on cash flow hedges	$	(2	)	$	3		$	1		$	4
Change in unrealized loss on equity investments	—			—			3			—
Change in unrealized gain on marketable securities	—			—			—			—
Total	$	(2	)	$	3		$	4		$	4

Earnings Per Share and Equity (Tables)

9 Months Ended

Sep. 30, 2016

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share



	Three Months Ended September 30,				Nine Months Ended September 30,
Exelon	2016		2015		2016		2015
Net income attributable to common shareholders	$	490	$	629	$	930	$	1,959
Weighted average common shares outstanding — basic	925		913		924		879
Assumed exercise and/or distributions of stock-based awards	2		2		2		4
Weighted average common shares outstanding — diluted	927		915		926		883

Commitments and Contingencies (Tables)

9 Months Ended

Sep. 30, 2016

Commitments And Contingencies Tables Disclosure [Line Items]

Energy Commitments

Utility Energy Purchase Commitments

Fuel Purchase Commitments

Other Purchase Obligation

Commercial Commitments

The Registrants’ commercial commitments as of September 30, 2016, representing commitments potentially triggered by future events were as follows:



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Letters of credit (non-debt)^(a)	$	1,720	$	1,650	$	16	$	23	$	2	$	1	$	—	$	—	$	1
Surety bonds^(b)	1,084		984		10		9		11		16		9		4		3
Financing trust guarantees	628		—		200		178		250		—		—		—		—
Nuclear insurance premiums^(c)	3,045		3,045		—		—		—		—		—		—		—
Guaranteed lease residual values^(d)	20		—		—		—		—		20		6		7		5
Total commercial commitments	$	6,497	$	5,679	$	226	$	210	$	263	$	37	$	15	$	11	$	9

________


(a)	Letters of credit (non-debt) - Exelon and certain 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)

Accrued environmental liabilities

of September 30, 2016 and December 31, 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:



September 30, 2016	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)
Exelon	$	427	$	318
Generation	76		—
ComEd	283		281
PECO	36		34
BGE	2		2
PHI (Successor)	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^(a)
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		—

_____________________________


(a)	For BGE, includes reserve for Riverside, a gas purification site. See discussion below for additional information.

Exelon Generation Co L L C [Member] | Equity Method Investments [Member]

Commitments And Contingencies Tables Disclosure [Line Items]

Other Commitments

, Generation’s estimated commitments relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



	Total
2016^(a)	$	79
2017	25
2018	4
Total	$	108

Supplemental Financial Information (Tables)

9 Months Ended

Sep. 30, 2016

Supplemental Financial Information [Abstract]

Components of non-operating income and expenses



	Three Months Ended September 30, 2016
															Successor
	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	$	57		$	57		$	—		$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	35			35			—			—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	155			155			—			—			—		—		—		—		—
Non-regulatory agreement units	116			116			—			—			—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(5		)	(5		)	—			—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(168		)	(168		)	—			—			—		—		—		—		—
Total decommissioning-related activities	190			190			—			—			—		—		—		—		—
Investment income	2			1			—			(1		)	—		—		—		—		—
Interest income related to uncertain income tax positions	8			—			—			—			—		—		—		—		—
Penalty related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—		—		—		—		—
AFUDC — Equity	19			—			5			2			5		7		5		1		1
Other	7			(6		)	1			1			—		12		7		2		1
Other, net	$	120		$	185		$	(80	)	$	2		$	5	$	19	$	12	$	3	$	2



																						Successor		Predecessor
	Nine Months Ended September 30, 2016																					March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE			Pepco		DPL		ACE		PHI		PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	181		$	181		$	—		$	—		$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	95			95			—			—			—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	286			286			—			—			—			—		—		—		—		—
Non-regulatory agreement units	216			216			—			—			—			—		—		—		—		—
Net unrealized losses on pledged assets
Zion Station decommissioning	(2		)	(2		)	—			—			—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(380		)	(380		)	—			—			—			—		—		—		—		—
Total decommissioning-related activities	396			396			—			—			—			—		—		—		—		—
Investment income (expense)	14			6			—			(1		)	2		^(d)	—		—		—		1		—
Long-term lease income	4			—			—			—			—			—		—		—		—		—
Interest income related to uncertain income tax positions	13			—			—			—			—			1		—		1		—		—
Penalty income related to uncertain income tax positions^(c)	(106		)	—			(86		)	—			—			—		—		—		—		—
AFUDC — Equity	43			—			8			6			14			14		3		5		15		7
Loss on debt extinguishment	(3		)	(2		)	—			—			—			—		—		—		—		—
Other	16			(5		)	6			1			—			13		6		2		15		(11		)
Other, net	$	377		$	395		$	(72	)	$	6		$	16		$	28	$	9	$	8	$	31	$	(4	)



	Three Months Ended September 30, 2015
																Predecessor
	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	$	39		$	39		$	—	$	—		$	—			$	—	$	—	$	—	$	—
Non-regulatory agreement units	18			18			—		—			—				—		—		—		—
Net unrealized losses on decommissioning trust funds
Regulatory agreement units	(301		)	(301		)	—		—			—				—		—		—		—
Non-regulatory agreement units	(218		)	(218		)	—		—			—				—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	207			207			—		—			—				—		—		—		—
Total decommissioning-related activities	(255		)	(255		)	—		—			—				—		—		—		—
Investment income (expense)	4			1			—		(1		)	1			^(d)	—		—		—		—
Long-term lease income	4			—			—		—			—				—		—		—		—
AFUDC — Equity	6			—			1		1			4				2		3		—		—
Other	(3		)	(3		)	3		1			(1		)		25		5		4		1
Other, net	$	(244	)	$	(257	)	$	4	$	1		$	4			$	27	$	8	$	4	$	1



	Nine Months Ended September 30, 2015
															Predecessor
	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	$	203		$	203		$	—	$	—		$	—		$	—	$	—	$	—	$	—
Non-regulatory agreement units	122			122			—		—			—			—		—		—		—
Net unrealized losses on decommissioning trust funds
Regulatory agreement units	(385		)	(385		)	—		—			—			—		—		—		—
Non-regulatory agreement units	(274		)	(274		)	—		—			—			—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning	9			9					—			—			—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	129			129			—		—			—			—		—		—		—
Total decommissioning-related activities	(196		)	(196		)	—		—			—			—		—		—		—
Investment income (expense)	6			1			—		(1		)	3		^(d)	—		—		—		—
Long-term lease income	12			—			—		—			—			—		—		—		—
Interest income related to uncertain income tax positions	—			1			—		—			—			—		—		—		1
AFUDC — Equity	16			—			2		4			10			11		9		1		1
Terminated interest rate swaps^(e)	(26		)	—			—		—			—			—		—		—		—
Other	9			1			12		—			—			37		12		7		2
Other, net	$	(179	)	$	(193	)	$	14	$	3		$	13		$	48	$	21	$	8	$	4

____


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


(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K for additional information regarding the accounting for nuclear decommissioning.


(c)	See Note 11— Income Taxes for discussion of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position.


(d)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information regarding the rate stabilization deferral.

(e)

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 nine months ended September 30, 2016 and 2015:



																			Successor		Predecessor
	Nine Months Ended September 30, 2016																		March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Depreciation, amortization, accretion and depletion
Property, plant and equipment^(a)	$	2,490		$	1,297		$	524	$	181	$	223	$	128	$	82	$	61	$	215	$	94
Amortization of regulatory assets^(a)	293			—			49		20		84		93		38		69		140		58
Amortization of intangible assets, net^(a)	38			32			—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	(7		)	(7		)	—		—		—		—		—		—		—		—
Nuclear fuel^(c)	862			862			—		—		—		—		—		—		—		—
ARO accretion^(d)	333			332			1		—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	4,009		$	2,516		$	574	$	201	$	307	$	221	$	120	$	130	$	355	$	152



	Nine Months Ended September 30, 2015
													Predecessor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization, accretion and depletion
Property, plant and equipment^(a)	$	1,648		$	739		$	471	$	179	$	216	$	292	$	122	$	76	$	57
Amortization of regulatory assets^(a)	131			—			57		19		55		182		69		37		78
Amortization of intangible assets, net^(a)	39			35			—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(b)	(20		)	(19		)	—		—		—		—		—		—		—
Nuclear fuel^(c)	841			841			—		—		—		—		—		—		—
ARO accretion^(d)	291			291			—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	2,930		$	1,887		$	528	$	198	$	271	$	474	$	191	$	113	$	135

________


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


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


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


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

Cash Flow Supplemental Disclosures



																									Successor			Predecessor
	Nine Months Ended September 30, 2016																								March 24, 2016 to September 30, 2016			January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd			PECO			BGE			Pepco			DPL			ACE			PHI			PHI
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	458		$	163		$	124		$	25		$	50		$	24		$	13		$	11		$	58		$	23
Loss from equity method investments	15			16			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	107			14			31			24			12			15			12			18			27			16
Stock-based compensation costs	88			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(237		)	(237		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(20		)	(20		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	7			—			3			1			—			2			—			1			2			1
Amortization of rate stabilization deferral	62			—			—			—			62			3			3			—			—			5
Amortization of debt fair value adjustment	(9		)	(9		)	—			—			—			—			—			—			—			—
Discrete impacts from EIMA^(c)	(36		)	—			(36		)	—			—			—			—			—			—			—
Amortization of debt costs	26			12			(3		)	2			3			—			—			—			—			—
Provision for excess and obsolete inventory	74			70			4			—			—			1			1			1			—			1
Merger-related commitments^(d)(e)	508			3			—			—			—			125			73			110			308			—
Severance costs	130			57			—			—			—			—			—			—			53			—
Asset retirement costs	—			—			—			—			—			—			5			2			—			—
Lower of cost or market inventory adjustment	36			36			—			—			—			—			—			—			—			—
Other	15			24			(1		)	(3		)	(18		)	(2		)	(8		)	(5		)	(7		)	(3		)
Total other non-cash operating activities	$	1,224		$	129		$	122		$	49		$	109		$	168		$	99		$	138		$	441		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(338	)	$	(289	)	$	(42	)	$	(4	)	$	17		$	15		$	(10	)	$	2		$	(5	)	$	11
Fair value of net assets contributed to Generation in connection with the PHI merger, net of cash^(d)(f)	—			119			—			—			—			—			—			—			—			—
Fair value of net assets distributed to Exelon in connection with the PHI Merger, net of cash ^(d)(f)	—			—			—			—			—			—			—			—			129			—
Fair value of pension obligation transferred in connection with the PHI Merger	—			—			—			—			—			—			—			—			53			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Assumption of merger commitment liability	—			—			—			—			—			33			—			—			33			—
Change in PPE related to ARO update	476			476			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			157			—			—			—			—			—			—			—
Non-cash financing of capital projects	84			84			—			—			—			—			—			—			—			—



	Nine Months Ended September 30, 2015
															Predecessor
	Exelon			Generation			ComEd		PECO			BGE			PHI			Pepco			DPL		ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	476		$	200		$	155	$	29		$	49		$	73		$	22		$	11	$	11
Loss from equity method investments	3			4			—		—			—			—			—			—		—
Provision for uncollectible accounts	114			15			46		37			15			49			15			18		15
Stock-based compensation costs	102			—			—		—			—			9			—			—		—
Other decommissioning-related activity^(a)	(31		)	(31		)	—		—			—			—			—			—		—
Energy-related options^(b)	18			18			—		—			—			—			—			—		—
Amortization of regulatory asset related to debt costs	—			—			—		—			—			4			2			—		—
Amortization of rate stabilization deferral	60			—			—		—			60			3			3			1		—
Amortization of debt fair value adjustment	(34		)	(9		)	—		—			—			—			—			—		—
Discrete impacts from EIMA^(c)	101			—			101		—			—			—			—			—		—
Amortization of debt costs	43			12			3		2			2			1			—			—		—
Provision for excess and obsolete inventory	7			8			—		—			—			1			—			—		—
Lower of cost or market inventory adjustment	15			15			—		—			—			—			—			—		—
Other	(18		)	(5		)	7		1			(15		)	3			—			1		1
Total other non-cash operating activities	$	856		$	227		$	312	$	69		$	111		$	143		$	42		$	31	$	27
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	59		$	48		$	62	$	(23	)	$	(14	)	$	(3	)	$	(1	)	$	2	$	—
Nuclear fuel procurement^(d)	—			—			—		—			—			—			—			—		—
Change in PPE related to ARO update	811			811			—		—			—			—			—			—		—
Indemnification of like-kind exchange position^(g)	—			—			5		—			—			—			—			—		—
Non-cash financing of capital projects	52			52			—		—			—			—			—			—		—
Long-term software licensing agreement^(f)	95			—			—		—			—			—			—			—		—

________

(a)


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


(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.


(d)	See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.


(e)	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.


(f)	Immediately following closing of the PHI Merger, the net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon. Exelon contributed a portion of such net assets to Generation.


(g)	See Note 11— Income Taxes for discussion of the like-kind exchange tax position.

Supplemental Balance Sheet Disclosures

The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2016 and December 31, 2015:



													Successor
September 30, 2016	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	18,354	^(a)	$	10,004	^(a)	$	3,841	$	3,213	$	3,198	$	146	$	3,026	$	1,171	$	1,008
Accounts receivable:
Allowance for uncollectible accounts	$	330		$	85		$	82	$	78	$	39	$	46	$	15	$	14	$	17



													Predecessor
December 31, 2015	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	16,375	^(b)	$	8,639	^(b)	$	3,710	$	3,101	$	3,016	$	5,341	$	2,929	$	1,139	$	968
Accounts receivable:
Allowance for uncollectible accounts	$	284		$	77		$	75	$	83	$	49	$	56	$	17	$	17	$	17

_______


(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $3,198 million.


(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million

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



	Three Months Ended September 30, 2016
											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	255	$	35	$	67	$	40	$	21	$	92	$	87	$	5	$	—



																	Successor		Predecessor
	Nine Months Ended September 30, 2016																March 24, 2016 to September 30, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Utility taxes	$	624	$	90	$	186	$	106	$	66	$	240	$	14	$	—	$	176	$	78



	Three Months Ended September 30, 2015
											Predecessor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	151	$	28	$	63	$	37	$	23	$	86	$	82	$	4	$	—



	Nine Months Ended September 30, 2015
											Predecessor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	430	$	79	$	180	$	104	$	67	$	253	$	239	$	14	$	—

Segment Information (Tables)

9 Months Ended

Sep. 30, 2016

Analysis and reconciliation of reportable segment information

Three Months Ended September 30, 2016 and 2015



									Successor
	Generation^(a)		ComEd		PECO		BGE		PHI^(b)		Other^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2016
Competitive businesses electric revenues	$	4,322	$	—	$	—	$	—	$	—	$	—		$	(499	)	$	3,823
Competitive businesses natural gas revenues	326		—		—		—		—		—			—			326
Competitive businesses other revenues	387		—		—		—		—		—			(1		)	386
Rate-regulated electric revenues	—		1,497		740		735		1,366		—			(8		)	4,330
Rate-regulated natural gas revenues	—		—		48		77		17		—			(5		)	137
Shared service and other revenues	—		—		—		—		11		362			(373		)	—
2015
Competitive businesses electric revenues	$	4,299	$	—	$	—	$	—	$	—	$	—		$	(204	)	$	4,095
Competitive businesses natural gas revenues	347		—		—		—		—		—			—			347
Competitive businesses other revenues	122		—		—		—		—		—			—			122
Rate-regulated electric revenues	—		1,376		691		655		—		—			(1		)	2,721
Rate-regulated natural gas revenues	—		—		49		70		—		—			(3		)	116
Shared service and other revenues	—		—		—		—		—		348			(348		)	—
Intersegment revenues^(e):
2016	$	500	$	4	$	2	$	7	$	11	$	362		$	(885	)	$	1
2015	205		1		1		3		—		347			(555		)	2
Net income (loss):
2016	$	271	$	37	$	122	$	56	$	166	$	(125	)	$	(1	)	$	526
2015	332		149		90		54		—		(36		)	(2		)	587
Total assets:
September 30, 2016	$	47,568	$	28,020	$	11,041	$	8,857	$	21,063	$	9,883		$	(11,897	)	$	114,535
December 31, 2015	46,529		26,532		10,367		8,295		—		15,389			(11,728		)	95,384

Analysis and reconciliation of reportable segment revenues for Generation

_________

(a)

Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. Intersegment revenues for Generation for the nine months ended September 30, 2016 include revenue from sales to PECO of $234 million and sales to BGE of $489 million in the Mid-Atlantic region, and sales to ComEd of $38 million in the Midwest region. For the nine months ended September 30, 2015, intersegment revenues for Generation include revenue from sales to PECO of $173 million and sales to BGE of $376 million in the Mid-Atlantic region, and sales to ComEd of $17 million in the Midwest region. For the Successor period of March 24, 2016 to September 30, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $223 million, sales to DPL of $109 million, and sales to ACE of $28 million in the Mid-Atlantic region.


(b)	Amounts included represent activity for PHI's successor period, March 24, 2016 through September 30, 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 nine months ended September 30, 2015.


(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.


(d)	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 19 — Supplemental Financial Information for total utility taxes for the nine months ended September 30, 2016 and 2015.

(e)

Generation total revenues:



	Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	4,776	$	(40	)	$	4,736	$	4,560	$	(69	)	$	4,491
Midwest	3,330		13			3,343		3,634		(1		)	3,633
New England	1,278		(6		)	1,272		1,752		(6		)	1,746
New York	906		(33		)	873		783		(5		)	778
ERCOT	659		6			665		691		(4		)	687
Other Power Regions	728		(42		)	686		940		(60		)	880
Total Revenues for Reportable Segments	11,677		(102		)	11,575		12,360		(145		)	12,215
Other^(b)	1,686		102			1,788		2,481		145			2,626
Total Generation Consolidated Operating Revenues	$	13,363	$	—		$	13,363	$	14,841	$	—		$	14,841

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b)

(c)

Generation total revenues net of purchased power and fuel expense:



	Nine Months Ended September 30, 2016							Nine Months Ended September 30, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)		Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	2,541	$	15		$	2,556	$	2,679	$	(2	)	$	2,677
Midwest	2,225		4			2,229		2,220		(15		)	2,205
New England	373		(23		)	350		425		(46		)	379
New York	607		(15		)	592		462		40			502
ERCOT	335		(104		)	231		344		(109		)	235
Other Power Regions	357		(104		)	253		341		(148		)	193
Total Revenues net of purchased power and fuel expense for Reportable Segments	6,438		(227		)	6,211		6,471		(280		)	6,191
Other^(b)	316		227			543		570		280			850
Total Generation Revenues net of purchased power and fuel expense	$	6,754	$	—		$	6,754	$	7,041	$	—		$	7,041

Analysis and reconciliation of reportable segment revenues for Generation




	Three Months Ended September 30, 2016							Three Months Ended September 30, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)			Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	881	$	6		$	887	$	979		$	18		$	997
Midwest	782		(1		)	781		760			(4		)	756
New England	170		(10		)	160		148			(15		)	133
New York	195		(1		)	194		157			13			170
ERCOT	144		(51		)	93		166			(55		)	111
Other Power Regions	143		(66		)	77		154			(71		)	83
Total Revenues net of purchased power and fuel for Reportable Segments	2,315		(123		)	2,192		2,364			(114		)	2,250
Other^(b)	131		123			254		(115		)	114			(1		)
Total Generation Revenues net of purchased power and fuel expense	$	2,446	$	—		$	2,446	$	2,249		$	—		$	2,249

__________


(a)	Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)

(c)




	Three Months Ended September 30, 2016							Three Months Ended September 30, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	1,813	$	(13	)	$	1,800	$	1,640	$	(8	)	$	1,632
Midwest	1,163		1			1,164		1,152		(1		)	1,151
New England	455		(4		)	451		520		—			520
New York	331		(8		)	323		254		(4		)	250
ERCOT	289		6			295		317		(1		)	316
Other Power Regions	271		(33		)	238		416		(40		)	376
Total Revenues for Reportable Segments	4,322		(51		)	4,271		4,299		(54		)	4,245
Other^(b)	713		51			764		469		54			523
Total Generation Consolidated Operating Revenues	$	5,035	$	—		$	5,035	$	4,768	$	—		$	4,768

__________


(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.

(b)

(c)

Significant Accounting Policies - Narrative (Details) - USD ($)	3 Months Ended		6 Months Ended	9 Months Ended
	Mar. 23, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Jan. 01, 2014
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Financing Activities				$ 1,251,000,000	$ 5,402,000,000
Net Cash Provided by (Used in) Operating Activities				7,363,000,000	5,674,000,000
Pepco Holdings LLC [Member] \| Predecessor [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results		$ 1,000,000			1,000,000
Net Cash Provided by (Used in) Financing Activities	$ 372,000,000				491,000,000
Net Cash Provided by (Used in) Operating Activities	$ 264,000,000				601,000,000
Pepco Holdings LLC [Member] \| Successor [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
Net Cash Provided by (Used in) Financing Activities			$ 65,000,000
Net Cash Provided by (Used in) Operating Activities			$ 546,000,000
Delmarva Power and Light Company [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results		1,000,000
Net Cash Provided by (Used in) Financing Activities				(14,000,000)	53,000,000
Net Cash Provided by (Used in) Operating Activities				267,000,000	188,000,000
Atlantic City Electric Company [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					1,000,000
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 Net Income		8,000,000			9,000,000
Net Cash Provided by (Used in) Financing Activities				74,000,000	40,000,000
Net Cash Provided by (Used in) Operating Activities				315,000,000	178,000,000
Potomac Electric Power Company [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Interest		$ 1,000,000
New Accounting Pronouncement or Change in Accounting Principle, Effect of Change on Operating Results					1,000,000
Net Cash Provided by (Used in) Financing Activities				28,000,000	148,000,000
Net Cash Provided by (Used in) Operating Activities				$ 504,000,000	$ 213,000,000

Variable Interest Entities - Narrative (Details)	3 Months Ended		9 Months Ended
Variable Interest Entities - Narrative (Details)	Sep. 30, 2016 USD ($) VIE	Sep. 30, 2015 USD ($)	Sep. 30, 2016 USD ($) VIE	Sep. 30, 2015 USD ($)	Aug. 31, 2016 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015 USD ($) VIE	Jul. 31, 2014 USD ($)	Apr. 01, 2014 USD ($)
Variable Interest Entity [Line Items]
Other Commitment	$ 6,497,000,000		$ 6,497,000,000		$ 513,000,000	$ 508,000,000
Variable Interest Entity, Financial or Other Support, Amount			$ 16,000,000
Number of Variable Interest Entities not consolidated by equity holders \| VIE	9		9				8
Number Of Variable Interest Entities Consolidated \| VIE	9		9				7
Guarantor Obligations, Current Carrying Value	$ 75,000,000		$ 75,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	50,000,000		50,000,000
Payments for Restructuring			39,000,000
Note Receivable				$ 27,000,000
Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests	250,000,000		250,000,000				$ 172,000,000
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	275,000,000		275,000,000
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 5,679,000,000		$ 5,679,000,000					$ 91,000,000
Equity Method Investment, Ownership Percentage	50.01%		50.01%
Related Party Purchase Of Nuclear Output By Third Party Percentage			49.99%
Payments for Restructuring			$ 7,000,000
Exelon Generation Co L L C [Member] \| Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	$ 275,000,000		275,000,000
Equity Method Investment, Summarized Financial Information, Equity Excluding Noncontrolling Interests							$ 78,000,000
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	8,000,000		8,000,000
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Other Commitment	263,000,000		263,000,000
Payments for Restructuring			1,000,000
Baltimore Gas and Electric Company [Member] \| RSB Bond Co LLC [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE	27,000,000	$ 21,000,000	64,000,000	63,000,000
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Other Commitment	9,000,000		9,000,000
Number Of Variable Interest Entities Consolidated \| VIE							1
Due from Affiliates	2,000,000		2,000,000				$ 0
Guarantor Obligations, Maximum Exposure, Undiscounted	13,000,000		13,000,000
Payments for Restructuring			0
Atlantic City Electric Company [Member] \| ATF [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE	20,000,000	$ 18,000,000	47,000,000	$ 45,000,000
Constellation Energy Nuclear Group [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Due from Affiliates	312,000,000		312,000,000						$ 400,000,000
Severance Benefits Obligations Balance									6,000,000
Financial Guarantee [Member] \| Constellation Energy Nuclear Group [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted									165,000,000
Payment Guarantee [Member] \| Constellation Energy Nuclear Group [Member]
Variable Interest Entity [Line Items]
Payables to affiliates									$ 245,000,000
Equity Method Investment Variable Interest Entities [Member] \| Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	$ 637,000,000		$ 637,000,000

Variable Interest Entities - Carrying Amounts and Classification of Consolidated VIE Assets and Liabilities (Details) - USD ($)
$ in Millions

Sep. 30, 2016

Dec. 31, 2015

Current Assets

^[2]

$ 914

^[1]

$ 909

Non Current Assets

^[2]

8,235

^[1]

8,009

Total Assets

^[2]

9,149

^[1]

8,918

Current Liabilities

^[2]

569

^[1]

473

^[2]

3,090

^[1]

2,927

^[2]

3,659

^[1]

3,400

114,535

95,384

Variable Interest Entity, Primary Beneficiary [Member]

^[3]

87,049

68,062

8,514

8,268

3,438

3,264

Current Assets

849

^[1]

881

Non Current Assets

8,201

^[1]

8,004

Total Assets

9,050

^[1]

8,885

Current Liabilities

439

^[1]

387

2,979

^[1]

2,884

3,418

^[1]

3,271

47,568

46,529

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

^[4]

33,829

33,559

8,415

8,235

3,196

3,135

122

^[5]

8,857

8,295

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

^[5]

6,100

5,418

122

124

172

16,188

11,592

111

156

21,063

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Predecessor [Member]

13,176

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Successor [Member]

172

156

124

139

172

3,507

3,387

Atlantic City Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]

2,442

2,387

$ 139

$ 172

[1]	.
[2]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[3]	Exelon’s consolidated assets include $8,514 million and $8,268 million at September 30, 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 $3,438 million and $3,264 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.
[4]	Generation’s consolidated assets include $8,415 million and $8,235 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,196 million and $3,135 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.
[5]	BGE’s consolidated assets include $47 million and $26 million at September 30, 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 $83 million and $122 million at September 30, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Variable Interest Entities - Assets and Liabilities of VIES which Creditors or Beneficiaries have no Recourse (Details) - USD ($)
$ in Millions

Sep. 30, 2016

Mar. 23, 2016

Dec. 31, 2015

Sep. 30, 2015

Dec. 31, 2014

$ 1,897

$ 6,502

$ 7,265

$ 1,878

321

205

4,061

3,187

1,013

912

754

1,365

Inventory

1,188

1,104

1,064

752

12,208

15,334

71,214

57,439

11,076

10,342

6,672

2,672

669

758

1,474

1,445

114,535

95,384

567

533

2,512

1,500

3,044

2,883

Mark-to-market derivative liabilities (current liabilities)

3,236

2,376

222

205

452

100

1,068

842

12,158

9,118

32,330

23,645

9,348

8,585

3,765

3,385

927

117

1,928

1,491

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

87,049

68,062

160

164

101

100

264

219

140

Inventory

192

181

866

882

5,139

5,160

2,173

2,036

257

7,648

7,386

8,514

8,268

191

111

201

216

Mark-to-market derivative liabilities (current liabilities)

102

115

566

472

661

666

^[2]

2,070

1,999

106

2,872

2,792

3,438

3,264

375

431

545

780

162

123

2,318

2,095

301

360

754

1,365

Inventory

849

880

788

535

6,135

6,342

26,374

25,843

11,076

10,342

630

733

692

627

47,568

46,529

254

1,465

1,583

Mark-to-market derivative liabilities (current liabilities)

942

935

203

182

100

392

356

4,307

4,933

8,077

7,936

9,160

8,431

117

691

602

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

^[3]

33,829

33,559

160

164

264

219

140

Inventory

192

181

801

854

5,139

5,160

2,173

2,036

223

7,614

7,381

8,415

8,235

201

216

Mark-to-market derivative liabilities (current liabilities)

113

435

386

550

623

2,070

1,999

^[2]

106

2,761

2,749

3,196

3,135

341

332

300

100

112

Inventory

1,114

845

6,904

6,597

^[4]

8,857

8,295

210

381

378

239

209

144

110

1,003

1,134

2,281

1,480

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

^[4]

6,100

5,418

Inventory

Mark-to-market derivative liabilities (current liabilities)

^[2]

122

Inventory

4,000

$ 319

272

581

319

Inventory

122

1,474

10,864

1,406

16,188

958

456

404

Mark-to-market derivative liabilities (current liabilities)

266

2,327

4,823

466

200

11,592

299

$ 319

595

345

Inventory

118

2,118

11,311

4,000

21,063

517

545

335

Mark-to-market derivative liabilities (current liabilities)

325

376

2,547

5,499

830

234

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Predecessor [Member]

13,176

Inventory

Mark-to-market derivative liabilities (current liabilities)

124

^[2]

124

Pepco Holdings LLC [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Successor [Member]

172

Inventory

Mark-to-market derivative liabilities (current liabilities)

111

^[2]

111

156

165

$ 4

$ 2

168

156

242

Inventory

520

546

2,456

2,322

3,507

3,387

110

338

297

1,129

1,153

Atlantic City Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]

2,442

2,387

Inventory

Mark-to-market derivative liabilities (current liabilities)

124

^[2]

124

$ 139

$ 172

[1]	Exelon’s consolidated assets include $8,514 million and $8,268 million at September 30, 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 $3,438 million and $3,264 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.
[2]	Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s balance sheet. See Note 13 - Retirement Benefits for additional details.
[3]	Generation’s consolidated assets include $8,415 million and $8,235 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,196 million and $3,135 million at September 30, 2016 and December 31, 2015, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.
[4]	BGE’s consolidated assets include $47 million and $26 million at September 30, 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 $83 million and $122 million at September 30, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Sep. 30, 2016

Dec. 31, 2015

^[1]

$ 1,117

$ 427

Exelon's ownership interest in VIE

^[1]

489

147

^[1]

193

Other ownership interests in VIE

^[1]

439

269

Assets Held-in-trust, Noncurrent

135

206

Commercial Agreement Variable Interest Entities [Member]

^[1]

586

263

Exelon's ownership interest in VIE

^[1]

181

^[1]

Other ownership interests in VIE

^[1]

405

241

Equity Method Investment Variable Interest Entities [Member]

^[1]

531

164

Exelon's ownership interest in VIE

^[1]

308

125

^[1]

193

Other ownership interests in VIE

^[1]

Investments [Member]

Investments [Member] | Maximum [Member]

225

Investments [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

Investments [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]

Contract Intangible Asset [Member] | Maximum [Member]

225

Contract Intangible Asset [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

Contract Intangible Asset [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]

Payment Guarantee [Member]

Payment Guarantee [Member] | Maximum [Member]

Payment Guarantee [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

Payment Guarantee [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]

Asset Held In Trust Noncurrent [Member] | Maximum [Member]

Asset Held In Trust Noncurrent [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

^[2]

Asset Held In Trust Noncurrent [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]

^[2]

^[2]

Assets Held-in-trust, Noncurrent

135

206

Payable to Zion Solutions

^[3]

124

$ 189

Exelon Generation Co L L C [Member] | Investments [Member] | Maximum [Member]

Business Acquisition, Pro Forma Revenue

$ 20

[1]	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
[2]	These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $135 million and $206 million as of September 30, 2016 and December 31, 2015, respectively; offset by payables to ZionSolutions LLC of $124 million and $189 million as of September 30, 2016 and December 31, 2015, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.
[3]	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.

Mergers, Acquisitions, and Dispositions - Narrative (Details) - USD ($)		1 Months Ended	3 Months Ended					6 Months Ended	9 Months Ended		12 Months Ended
	Mar. 31, 2016	Jul. 31, 2016	Mar. 31, 2017	Sep. 30, 2016	Jun. 30, 2016	Mar. 23, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Aug. 31, 2016	Mar. 24, 2016	Jul. 31, 2014
Business Acquisition [Line Items]
Revenues				$ 9,002,000,000			$ 7,401,000,000		$ 23,486,000,000	$ 22,746,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross									(6,896,000,000)	(28,000,000)
Business Combination, Integration Related Costs				20,000,000			22,000,000		123,000,000	84,000,000
Investments				$ 592,000,000				$ 592,000,000	$ 592,000,000		$ 639,000,000
Cash offered in exchange for each share of PHI stock				$ 27.25				$ 27.25	$ 27.25
Other noncurrent assets				$ 1,474,000,000				$ 1,474,000,000	$ 1,474,000,000		1,445,000,000
Other Commitment	$ 508,000,000			6,497,000,000				6,497,000,000	6,497,000,000			$ 513,000,000
Business Combination, Contingent Consideration, Asset				235,000,000				235,000,000	235,000,000
Net income				526,000,000			587,000,000		956,000,000	1,959,000,000
Goodwill, Acquired During Period						$ (4,016,000,000)			16,000,000
Net Working Capital									96,000,000
Other Intangible Assets [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Finite-lived Intangible Assets Acquired									1,500,000,000
Common Stock [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross											(180,000,000)
Other Investments [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				137,000,000				137,000,000	137,000,000
Other Investments [Member] \| Scenario, Adjustment [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				55,000,000				55,000,000	55,000,000
Pepco Holdings LLC [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent				3,442,000,000				3,442,000,000	3,442,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets				1,441,000,000				1,441,000,000	1,441,000,000
Revenues				1,437,000,000					2,656,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				513,000,000				513,000,000	513,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets				4,000,000,000				4,000,000,000	4,000,000,000
Net income				169,000,000					(92,000,000)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets				248,000,000				248,000,000	248,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities				2,752,000,000				2,752,000,000	2,752,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt				5,636,000,000				5,636,000,000	5,636,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other				187,000,000				187,000,000	187,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				11,088,000,000				11,088,000,000	11,088,000,000
Pepco Holdings LLC [Member] \| Common Stock [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross									(6,933,000,000)
Pepco Holdings LLC [Member] \| Common Stock [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross									(180,000,000)
Pepco Holdings LLC [Member] \| Successor [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross					$ (33,000,000)			(62,000,000)
PEPCO Holdings Inc [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross									(7,142,000,000)
PEPCO Holdings Inc [Member] \| Other Investments [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				444,000,000				444,000,000	444,000,000
ConEdision [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Consideration Transferred, Liabilities Incurred									22,000,000
Fitzpatrick [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross				(110,000,000)
Fitzpatrick [Member] \| Maximum [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs			$ 250,000,000
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Revenues				5,035,000,000			4,768,000,000		13,363,000,000	14,841,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross									(255,000,000)	(28,000,000)
Business Combination, Integration Related Costs				9,000,000			10,000,000		29,000,000	30,000,000
Investments				$ 381,000,000				$ 381,000,000	$ 381,000,000		210,000,000
Equity Method Investment, Ownership Percentage				50.01%				50.01%	50.01%
Other noncurrent assets				$ 692,000,000				$ 692,000,000	$ 692,000,000		627,000,000
Gain (Loss) on Disposition of Property Plant Equipment									32,000,000
Other Commitment				5,679,000,000				5,679,000,000	5,679,000,000					$ 91,000,000
Business Combination, Contingent Consideration, Asset				163,000,000				163,000,000	163,000,000
Net income				271,000,000			332,000,000		556,000,000	1,208,000,000
Members' Capital				9,265,000,000				9,265,000,000	9,265,000,000		8,997,000,000
Exelon Generation Co L L C [Member] \| ConEdision [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross				(257,000,000)					(235,000,000)
Net Working Capital				204,000,000
Atlantic City Electric Company [Member]
Business Acquisition [Line Items]
Revenues				421,000,000			386,000,000		982,000,000	1,003,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs				2,000,000			0		17,000,000	1,000,000
Other noncurrent assets				42,000,000				42,000,000	42,000,000		19,000,000
Other Commitment				9,000,000				9,000,000	9,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets				1,158,000,000				1,158,000,000	1,158,000,000
Net income				47,000,000			22,000,000		(50,000,000)	37,000,000
Atlantic City Electric Company [Member] \| Other Investments [Member] \| Scenario, Adjustment [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				10,000,000				10,000,000	10,000,000
Atlantic City Electric Company [Member] \| Pepco Holdings LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				111,000,000				111,000,000	111,000,000
Equity Contribution									49,000,000
Potomac Electric Power Company [Member]
Business Acquisition [Line Items]
Revenues				635,000,000			592,000,000		1,695,000,000	1,641,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Investments				100,000,000				100,000,000	100,000,000		68,000,000
Other noncurrent assets				4,000,000				4,000,000	4,000,000		4,000,000
Gain (Loss) on Disposition of Property Plant Equipment									8,000,000
Other Commitment				15,000,000				15,000,000	15,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets				1,683,000,000				1,683,000,000	1,683,000,000
Net income				79,000,000			60,000,000		20,000,000	128,000,000
Potomac Electric Power Company [Member] \| Successor [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross									(33,000,000)
Potomac Electric Power Company [Member] \| Other Investments [Member] \| Scenario, Adjustment [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				13,000,000				13,000,000	13,000,000
Potomac Electric Power Company [Member] \| Pepco Holdings LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				126,000,000				126,000,000	126,000,000
Equity Contribution									73,000,000
Delmarva Power and Light Company [Member]
Business Acquisition [Line Items]
Revenues				331,000,000			314,000,000		974,000,000	1,004,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs				2,000,000			0		18,000,000	2,000,000
Other noncurrent assets				7,000,000				7,000,000	7,000,000		$ 2,000,000
Gain (Loss) on Disposition of Property Plant Equipment		$ 4,000,000
Other Commitment				11,000,000				11,000,000	11,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets				1,128,000,000				1,128,000,000	1,128,000,000
Net income				44,000,000			15,000,000		(16,000,000)	55,000,000
Delmarva Power and Light Company [Member] \| Other Investments [Member] \| Scenario, Adjustment [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				27,000,000				27,000,000	27,000,000
Delmarva Power and Light Company [Member] \| Pepco Holdings LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				77,000,000				77,000,000	77,000,000
Equity Contribution									46,000,000
Pepco Holdings LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs				3,000,000			$ 1,000,000		26,000,000	$ 3,000,000
Goodwill, Acquired During Period						$ (4,016,000,000)
Pepco Holdings LLC [Member] \| Scenario, Adjustment [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent													$ 59,000,000
Pepco Holdings LLC [Member] \| Successor [Member]
Business Acquisition [Line Items]
Revenues				1,394,000,000				2,565,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs	$ 63,000,000			7,000,000
Investments				132,000,000				132,000,000	132,000,000
Other noncurrent assets				76,000,000				76,000,000	76,000,000
Business Combination, Contingent Consideration, Asset													301,000,000
Net income				166,000,000				(91,000,000)
Members' Capital				7,978,000,000				7,978,000,000	7,978,000,000				$ 7,200,000,000
Pepco Holdings LLC [Member] \| Other Investments [Member] \| Scenario, Adjustment [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				50,000,000				50,000,000	50,000,000
Pepco Holdings LLC [Member] \| Pepco Holdings LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment				314,000,000				314,000,000	314,000,000
Constellation Energy Group LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Total liabilities held for sale (b)				5,000,000				5,000,000	5,000,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				$ 46,000,000				$ 46,000,000	$ 46,000,000
Subsequent Event [Member] \| Fitzpatrick [Member] \| Minimum [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs			$ 200,000,000

Mergers, Acquisitions, and Dispositions Merger Transaction Table (Details) - USD ($) $ / shares in Units, shares in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Business Acquisition, Share Price	$ 27.25
Investments	$ 592,000,000		$ 639,000,000
Shares, Issued	958,014		954,668
Payments to Acquire Businesses, Gross	$ 6,896,000,000	$ 28,000,000
Preferred Stock [Member]
Payments to Acquire Businesses, Gross			$ 180,000,000
Pepco Holdings LLC [Member] \| Common Stock [Member]
Payments to Acquire Businesses, Gross	6,933,000,000
Pepco Holdings LLC [Member] \| Preferred Stock [Member]
Payments to Acquire Businesses, Gross	180,000,000
Pepco Holdings LLC [Member] \| Deferred Compensation, Share-based Payments [Member]
Payments to Acquire Businesses, Gross	$ 29,000,000

Mergers, Acquisitions, and Dispositions Purchase Price Allocation Table (Details) $ in Millions	9 Months Ended
	Sep. 30, 2016 USD ($)
Pepco Holdings LLC [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	$ 1,441
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	11,088
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedAssets	5,015
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets	248
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	21,792
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	2,752
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	(1,515)
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedLiabilities	297
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	5,636
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	187
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	(14,650)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	7,142
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	4,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	3,442
_BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRetirmentObligations	821
ConEdison Solutions [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	204
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	2
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	322
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	(65)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	(65)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	257
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	100
Business Combination, Consideration Transferred	257
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative Assets	6
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Intangible Assets, Other than Goodwill	9
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other	1
Potomac Electric Power Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	1,683
Delmarva Power and Light Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	$ 1,128

Mergers, Acquisitions, and Dispositions Goodwill Amortization Schedule (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 23, 2016	Sep. 30, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill		$ 6,672	$ 2,672
Goodwill, Acquired During Period	$ 4,016	(16)
Goodwill, Other Increase (Decrease)		(16)
Exelon Generation Co L L C [Member]
Goodwill [Line Items]
Goodwill		47	47
Pepco Holdings LLC [Member]
Goodwill [Line Items]
Goodwill		4,000	$ 0
Goodwill, Acquired During Period	$ 4,016
Goodwill, Other Increase (Decrease)		$ (16)

Mergers, Acquisitions, and Dispositions ProForma Impact of Merger (Details) - USD ($)
$ / shares in Units, $ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2015

$ 9,002

$ 8,545

$ 24,468

$ 26,129

$ 33,823

Business Acquisition, Pro Forma Net Income (Loss)

$ 501

$ 746

$ 1,346

$ 2,169

$ 2,618

Business Acquisition, Pro Forma Earnings Per Share, Basic

$ 0.5416

$ 0.8118

$ 1.4567

$ 2.3602

$ 2.8487

Business Acquisition, Pro Forma Earnings Per Share, Diluted

$ 0.5405

$ 0.8074

$ 1.4536

$ 2.3499

$ 2.8364

Consolidation, Eliminations [Member]

^[1],[2]

$ 508

Business Acquisition, Pro Forma Revenue

^[3]

$ 192

171

$ 426

$ 559

Regulatory Matters Additional Narrative Information [Line Items]

^[3]

$ 20

$ 25

$ 660

$ 100

$ 92

[1]	(e)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.
[2]	See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.
[3]	(a)The amounts above include adjustments for non-recurring costs directly related to the merger of $20 million and $660 million for the three and nine months ended September 30, 2016, respectively, and intercompany revenue of $171 million for the nine months ended September 30, 2016.

Mergers, Acquisitions, and Dispositions Merger Integration Related Costs Table (Details) - USD ($) $ in Millions		3 Months Ended			9 Months Ended
	Mar. 31, 2016	Sep. 30, 2016	Mar. 23, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Business Combination, Integration Related Costs		$ 20		$ 22	$ 123	$ 84
Exelon Generation Co L L C [Member]
Business Combination, Integration Related Costs		9		10	29	30
Commonwealth Edison Co [Member]
Business Combination, Integration Related Costs		0		3	(6)	9
PECO Energy Co [Member]
Business Combination, Integration Related Costs		1		1	3	4
Baltimore Gas and Electric Company [Member]
Business Combination, Integration Related Costs		1		2	(3)	4
Pepco Holdings LLC [Member]
Business Combination, Integration Related Costs		3		1	26	3
Delmarva Power and Light Company [Member]
Business Combination, Integration Related Costs		2		0	18	2
Atlantic City Electric Company [Member]
Business Combination, Integration Related Costs		2		0	17	1
Successor [Member] \| Pepco Holdings LLC [Member]
Business Combination, Integration Related Costs	$ 63	$ 7
Predecessor [Member] \| Pepco Holdings LLC [Member]
Business Combination, Integration Related Costs			$ 29	$ 3		$ 16
Regulatory Assets [Member] \| Commonwealth Edison Co [Member]
Business Combination, Integration Related Costs					8
Regulatory Assets [Member] \| Baltimore Gas and Electric Company [Member]
Business Combination, Integration Related Costs					6
Regulatory Assets [Member] \| Pepco Holdings LLC [Member]
Business Combination, Integration Related Costs					13
Regulatory Assets [Member] \| Potomac Electric Power Company [Member]
Business Combination, Integration Related Costs					10
Regulatory Assets [Member] \| Delmarva Power and Light Company [Member]
Business Combination, Integration Related Costs					$ 3

Regulatory Matters - Narrative (Details)

1 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

Jun. 03, 2016

USD ($)

Apr. 30, 2012

May 31, 2014

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2016

USD ($)

Mar. 31, 2016

USD ($)

Sep. 30, 2015

USD ($)

Jun. 30, 2016

USD ($)

Sep. 30, 2016

USD ($)

Sep. 30, 2015

USD ($)

Aug. 31, 2016

USD ($)

Dec. 31, 2015

USD ($)

Jul. 31, 2014

USD ($)

Aug. 31, 2010

USD ($)

$ 11,432,000,000

$ 6,824,000,000

20,000,000

$ 22,000,000

123,000,000

$ 84,000,000

338,000,000

59,000,000

4,985,000,000

4,570,000,000

10,022,000,000

6,065,000,000

548,000,000

369,000,000

Fair Value, Net Asset (Liability)

6,497,000,000

$ 508,000,000

6,497,000,000

$ 513,000,000

2,400,000,000

Regulatory Matters Additional Narrative Information [Line Items]

1,192,000,000

1,113,000,000

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

3,000,000

(6,000,000)

9,000,000

94,000,000

42,000,000

$ 62,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

3,781,000,000

3,614,000,000

$ 90,000,000

Public Utilities, Requested Rate Increase (Decrease), Percentage

11.50%

8.64%

8.59%

987,000,000

$ 987,000,000

895,000,000

204,000,000

155,000,000

Commonwealth Edison Co [Member] | Electric Distribution [Member]

226,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

138,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

139,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 1,000,000

Requested Debt and Equity Return on Distribution

6.71%

6.69%

ICC Approved Rate Increase (Decrease), Amount

$ 1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

1,688,000,000

1,617,000,000

1,000,000

3,000,000

$ 4,000,000

4,000,000

(23,000,000)

679,000,000

639,000,000

1,651,000,000

1,583,000,000

128,000,000

112,000,000

210,000,000

Regulatory Matters Additional Narrative Information [Line Items]

722,000,000

781,000,000

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

1,000,000

2,000,000

(3,000,000)

4,000,000

28,000,000

Customer Refund Liability, Noncurrent

30,000,000

(17,000,000)

14,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

172,000,000

222,000,000

12,000,000

Estimated number of smart meters to be installed

2,000,000

Total smart grid and smart meter investment grant amount

$ 480,000,000

Reimbursements received from the DOE

$ 200,000,000

Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint

508,000,000

514,000,000

Customer Refund

30,000,000

$ 30,000,000

10.50%

54,000,000

$ 54,000,000

38,000,000

Proposed Capital Expenditure

263,000,000

13,000,000

Baltimore Gas and Electric Company [Member] | Gas Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

$ 48,000,000

78,000,000

Baltimore Gas and Electric Company [Member] | Electric Distribution [Member]

9.65%

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

116,000,000

Public Utilities, Approved Rate Increase (Decrease), Amount

$ 44,000,000

ICC Approved Rate Increase (Decrease), Amount

9.75%

$ 44,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Unregulated Operating Revenue

9,000,000

10,000,000

29,000,000

30,000,000

101,000,000

Customer Refund Liability, Noncurrent

20,000,000

289,000,000

48,000,000

Customer Refund

20,000,000

License Costs

27,000,000

Exelon Generation Co L L C [Member] | Minimum [Member]

5,679,000,000

$ 91,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Purchase Obligation

3,000,000

Exelon Generation Co L L C [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Purchase Obligation

7,000,000

PEPCO Holdings Inc [Member]

Regulatory Matters Additional Narrative Information [Line Items]

37,000,000

Regulatory Matters Additional Narrative Information [Line Items]

2,582,000,000

213,000,000

2,277,000,000

PEPCO Holdings Inc [Member] | Successor [Member]

66,000,000

Regulatory Matters Additional Narrative Information [Line Items]

3,595,000,000

268,000,000

2,945,000,000

101,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

798,000,000

801,000,000

(23,000,000)

(15,000,000)

(1,000,000)

Public Utilities, Requested Rate Increase (Decrease), Amount

44,000,000

2,000,000

10.60%

Public Utilities, Requested Return on Equity, Percentage

676,000,000

$ 676,000,000

661,000,000

10.60%

Power Plant Output | MW

661,000,000

Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint

10.50%

CapitalProjectFundedByEntity

$ 500,000,000

Capital ProjectFundedByBonds

375,000,000

CapitalProjectFundedByAgency

$ 125,000,000

20,000,000

$ 20,000,000

15,000,000

Current Year Revenue Adjustment

15,000,000

(15,000,000)

Requested ROE

10.60%

Potomac Electric Power Company [Member] | Electric Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

82,000,000

$ 103,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

127,000,000

$ 86,000,000

Potomac Electric Power Company [Member] | Minimum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Power Plant Output | MW

650,000,000

Proposed Capital Expenditure

16,000,000

Potomac Electric Power Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Power Plant Output | MW

700,000,000

Projected Capital Expenditures

32,000,000

Regulatory Matters Additional Narrative Information [Line Items]

359,000,000

371,000,000

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

2,000,000

18,000,000

2,000,000

(14,000,000)

10,000,000

2,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 146,000,000

146,000,000

160,000,000

8,000,000

Requested Debt and Equity Return on Distribution

10.60%

Public Utilities, Interim Rate Increase (Decrease), Amount

$ 2,500,000

Public Utilities, Requested Return on Equity, Percentage

$ 297,000,000

299,000,000

10.60%

Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint

10.50%

46,000,000

$ 46,000,000

49,000,000

Current Year Revenue Adjustment

11,000,000

(12,000,000)

Requested ROE

10.60%

Delmarva Power and Light Company [Member] | Gas Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amount

$ 21,500,000

Delmarva Power and Light Company [Member] | Electric Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

57,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

66,000,000

62,800,000

Delmarva Power and Light Company [Member] | Minimum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Projected Capital Expenditures

5,000,000

Delmarva Power and Light Company [Member] | Maximum [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Projected Capital Expenditures

9,000,000

Regulatory Matters Additional Narrative Information [Line Items]

501,000,000

512,000,000

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

2,000,000

$ 0

17,000,000

1,000,000

(6,000,000)

(2,000,000)

Public Utilities, Requested Rate Increase (Decrease), Amount

36,000,000

25,000,000

8,000,000

Public Utilities, Interim Rate Increase (Decrease), Amount

$ 19,000,000

$ 9,000,000

Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint

412,000,000

$ 412,000,000

414,000,000

10.50%

35,000,000

$ 35,000,000

18,000,000

Current Year Revenue Adjustment

9,000,000

Atlantic City Electric Company [Member] | Electric Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Approved Rate Increase (Decrease), Amount

45,000,000

ICC Approved Rate Increase (Decrease), Amount

45,000,000

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]

74,000,000

84,000,000

Regulatory Matters Additional Narrative Information [Line Items]

^[1]

31,000,000

43,000,000

Under Recovered Energy And Transmission Costs [Member] | PECO Energy Co [Member]

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

^[2]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

^[3]

25,000,000

40,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | PEPCO Holdings Inc [Member] | Successor [Member]

33,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Potomac Electric Power Company [Member]

18,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Delmarva Power and Light Company [Member]

1,000,000

9,000,000

^[4]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Energy And Transmission Costs [Member] | Atlantic City Electric Company [Member]

^[5]

8,000,000

11,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member]

^[6]

9,000,000

13,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Commonwealth Edison Co [Member]

23,000,000

6,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | PECO Energy Co [Member]

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 Inc [Member] | Predecessor [Member]

^[7]

10,000,000

6,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | PEPCO Holdings Inc [Member] | Successor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Potomac Electric Power Company [Member]

13,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Delmarva Power and Light Company [Member]

10,000,000

^[8]

10,000,000

^[8]

Regulatory Matters Additional Narrative Information [Line Items]

Merger Integration Costs [Member] | Atlantic City Electric Company [Member]

3,000,000

^[9]

3,000,000

^[9]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | Commonwealth Edison Co [Member]

232,000,000

189,000,000

Regulatory Matters Additional Narrative Information [Line Items]

^[10]

232,000,000

189,000,000

Under Recovered Distribution Service Costs [Member] | PECO Energy Co [Member]

11,000,000

$ 11,000,000

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 Inc [Member] | Predecessor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Under Recovered Distribution Service Costs [Member] | PEPCO Holdings Inc [Member] | Successor [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] | Delmarva Power and Light 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]

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member]

AMI Expenses [Member] | Commonwealth Edison Co [Member]

704,000,000

399,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | PECO Energy Co [Member]

160,000,000

140,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Baltimore Gas and Electric Company [Member]

53,000,000

63,000,000

Regulatory Matters Additional Narrative Information [Line Items]

235,000,000

196,000,000

^[11]

Amount of Impairment to Carrying Amount of Regulatory Assets

235,000,000

196,000,000

52,000,000

AMI Expenses [Member] | Baltimore Gas and Electric Company [Member] | Gas Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

37,000,000

AMI Expenses [Member] | Baltimore Gas and Electric Company [Member] | Electric Distribution [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Public Utilities, Requested Rate Increase (Decrease), Amended, Amount

104,000,000

AMI Expenses [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | PEPCO Holdings Inc [Member] | Successor [Member]

267,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Potomac Electric Power Company [Member]

256,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Delmarva Power and Light Company [Member]

171,000,000

^[11]

171,000,000

^[11]

180,000,000

Regulatory Matters Additional Narrative Information [Line Items]

AMI Expenses [Member] | Atlantic City Electric Company [Member]

85,000,000

^[11]

85,000,000

^[11]

87,000,000

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]

642,000,000

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 Inc [Member] | Predecessor [Member]

289,000,000

278,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | PEPCO Holdings Inc [Member] | Successor [Member]

401,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Potomac Electric Power Company [Member]

352,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Delmarva Power and Light Company [Member]

254,000,000

289,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Energy Efficiency And Demand Response Programs [Member] | Atlantic City Electric Company [Member]

98,000,000

111,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Legacy AMI [Member] | Baltimore Gas and Electric Company [Member]

$ 1,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Legacy AMI [Member] | Potomac Electric Power Company [Member]

55,000,000

Regulatory Matters Additional Narrative Information [Line Items]

Legacy AMI [Member] | Delmarva Power and Light Company [Member]

75,000,000

Regulatory Matters Additional Narrative Information [Line Items]

$ 14,000,000

[1]	As of September 30, 2016, ComEd’s regulatory asset of $31 million included $24 million associated with transmission costs recoverable through its FERC approved formula rate and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of September 30, 2016, ComEd’s regulatory liability of $72 million included $43 million related to over-recovered energy costs and $29 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, 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.
[2]	As of September 30, 2016, PECO's regulatory liability of $59 million included $30 million related to over-recovered costs under the DSP program, $13 million related to the over-recovered natural gas costs under the PGC, $10 million related to over-recovered non-bypassable transmission service charges and $6 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.
[3]	As of September 30, 2016, BGE's regulatory asset of $25 million included $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $19 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $1 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.
[4]	As of September 30, 2016, Pepco's regulatory liability of $17 million included $9 million of over-recovered transmission costs and $8 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.
[5]	As of September 30, 2016, DPL's regulatory asset of $8 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $7 million of under-recovered electric energy costs. As of September 30, 2016, DPL's regulatory liability of $11 million included $6 million of over-recovered electric energy costs and $5 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.
[6]	As of September 30, 2016, ACE's regulatory asset of $9 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $5 million of under-recovered electric energy costs. As of September 30, 2016, ACE's regulatory liability of $12 million included $7 million of over-recovered transmission costs and $5 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.
[7]	As of September 30, 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.
[8]	epresents previously incurred PHI acquisition costs expected to be recovered in distribution rates
[9]	.
[10]	As of September 30, 2016, ComEd’s regulatory asset of $232 million was comprised of $178 million for the 2014 - 2016 annual reconciliations and $54 million related to significant one-time events including $24 million of deferred storm costs, $11 million of Constellation and PHI merger and integration related costs and $19 million of smart meter related costs. As of December 31, 2015, ComEd’s regulatory asset of $189 million was comprised of $142 million for the 2014 and 2015 annual reconciliations and $47 million related to significant one-time events, including $36 million of deferred storm costs and $11 million of Constellation merger and integration related costs. See Note 4— Merger, Acquisitions, and Dispositions of the Exelon 2015 Form 10-K for further information.
[11]	$134 million for Pepco and $40 million for DPL, of which $75 million for Pepco and $14 million for DPL relates to retired legacy meters which are not earning a return

Regulatory Matters Regulatory Matters - Purchase of Receivables Programs (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Sep. 30, 2016

Dec. 31, 2015

$ 396

$ 229

^[1]

$ 360

198

Discount rate

1.00%

$ 123

103

^[1]

106

^[2]

^[1]

^[3]

100

^[1]

PEPCO Holdings Inc [Member] | Successor [Member]

117

^[1]

Potomac Electric Power Company [Member] | Maryland Service Territory [Member] | Minimum [Member]

$ 111

Potomac Electric Power Company [Member] | Maryland Service Territory [Member] | Maximum [Member]

0.00%

Potomac Electric Power Company [Member] | District of Columbia Service Territory [Member] | Minimum [Member]

2.00%

Potomac Electric Power Company [Member] | District of Columbia Service Territory [Member] | Maximum [Member]

0.00%

Potomac Electric Power Company [Member] | Predecessor [Member]

6.00%

^[4]

Potomac Electric Power Company [Member] | Successor [Member]

$ 79

^[4]

Delmarva Power and Light Company [Member] | Maryland Service Territory [Member] | Minimum [Member]

$ 75

Delmarva Power and Light Company [Member] | Maryland Service Territory [Member] | Maximum [Member]

0.00%

Delmarva Power and Light Company [Member] | Predecessor [Member]

1.00%

^[1]

Delmarva Power and Light Company [Member] | Successor [Member]

$ 12

^[1]

Atlantic City Electric Company [Member] | Predecessor [Member]

^[1]

Atlantic City Electric Company [Member] | Successor [Member]

$ 17

^[1]

Property, Plant and Equipment [Line Items]

$ 24

[1]	For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing tariff
[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
[3]	As of September 30, 2016, BGE's regulatory asset of $25 million included $3 million of costs associated with transmission costs recoverable through its FERC approved formula rate, $19 million related to under-recovered electric energy costs, $3 million of abandonment costs to be recovered upon FERC approval, and $1 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.
[4]	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.

Regulatory Matters Annual Electric Transmission Fillings (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Jun. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			$ 90
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 94
Public Utilities, Approved Return on Equity, Percentage			11.50%
Public Utilities, Approved Equity Capital Structure, Percentage			8.47%	8.61%
Prior Year Revenue Adjustment			$ 4
Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			12
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ 28
Public Utilities, Approved Return on Equity, Percentage			10.50%
Public Utilities, Approved Equity Capital Structure, Percentage			8.09%	8.46%
Prior Year Revenue Adjustment			$ 3
Proposed Capital Expenditure			13
Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			2
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (23)
Public Utilities, Approved Return on Equity, Percentage		10.60%
Public Utilities, Approved Return on Equity, Percentage			10.50%
Public Utilities, Approved Equity Capital Structure, Percentage			7.88%	8.36%
Prior Year Revenue Adjustment	$ (10)
Current Year Revenue Adjustment			$ (15)
Delmarva Power and Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			8
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (14)
Public Utilities, Approved Return on Equity, Percentage			10.50%
Public Utilities, Requested Equity Capital Structure, Percentage	10.60%
Public Utilities, Approved Equity Capital Structure, Percentage			7.21%	7.80%
Prior Year Revenue Adjustment	$ (10)
Current Year Revenue Adjustment			$ (12)
Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount			8
Public Utilities, Requested Rate Increase (Decrease), Amended, Amount			$ (6)
Public Utilities, Approved Return on Equity, Percentage			10.50%
Public Utilities, Approved Equity Capital Structure, Percentage			7.83%	8.51%
Prior Year Revenue Adjustment	$ (14)
Current Year Revenue Adjustment			$ 0

Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2016
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Estimated residual value of leased assets	$ 356	$ 356
Proceeds From Lease Termination		360	$ 0
Gain (Loss) on Contract Termination		4
Wind Assets [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Tangible Asset Impairment Charges		36
Disposal Group, Including Discontinued Operation, Assets, Current	24	24		$ 60
Constellation Energy Group LLC [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Tangible Asset Impairment Charges	$ 15	$ 119

Early Nuclear Plant Retirements Early Nuclear Plant Retirements (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	$ 1,188	$ 1,104
Property, plant and equipment, net	71,214	$ 57,439
Ginna [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	31
Nuclear Fuel, Net of Amortization	41
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	13
Asset Retirement Obligation	(667)
Property, plant and equipment, net	124
Three Mile Island [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	39
Nuclear Fuel, Net of Amortization	93
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	38
Asset Retirement Obligation	(492)
Property, plant and equipment, net	956
Nine Mile Point [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	70
Nuclear Fuel, Net of Amortization	214
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	53
Asset Retirement Obligation	(780)
Property, plant and equipment, net	$ 1,151

Early Nuclear Plant Retirements Early Nuclear Plant Retirements table (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

^[1]

$ 862

$ 841

^[2]

333

291

Facility Closing [Member]

^[3]

2,490

$ 1,648

Property, Plant and Equipment [Line Items]

Other Expenses

443

Restructuring Reserve, Accrual Adjustment

$ 146

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

Early Nuclear Plant Retirements Early Plant Retirement Pretax Expense (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

^[1]

$ 862

$ 841

^[2]

2,490

1,648

$ 120

$ (244)

377

$ (179)

Nuclear Plant [Member]

Accretion Expense, Including Asset Retirement Obligations

459

Fair Value, Inputs, Level 3 [Member]

(55)

Other Expenses

$ 443

[1]	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[2]	(a)Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.

Fair Value of Financial Assets and Liabilities - Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation (Details) - USD ($)

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2016

Mar. 23, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Jun. 30, 2016

Mar. 24, 2016

Dec. 31, 2015

Jun. 30, 2015

Dec. 31, 2014

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

$ 1,466,000,000

$ 1,661,000,000

$ 1,466,000,000

$ 1,661,000,000

$ 1,185,000,000

$ 20,000,000

$ 1,529,000,000

$ 1,536,000,000

$ 1,501,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

93,000,000

(48,000,000)

(334,000,000)

(83,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

(1,000,000)

1,000,000

2,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

(17,000,000)

(20,000,000)

21,000,000

(19,000,000)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

214,000,000

67,000,000

420,000,000

259,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

(7,000,000)

(18,000,000)

(11,000,000)

(42,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

288,000,000

180,000,000

248,000,000

538,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

(1,000,000)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(28,000,000)

(13,000,000)

(119,000,000)

(75,000,000)

214,000,000

67,000,000

420,000,000

259,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

31,000,000

90,000,000

(51,000,000)

72,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

69,000,000

2,000,000

84,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

(4,000,000)

(3,000,000)

(11,000,000)

(38,000,000)

Fair Value, Inputs, Level 3 [Member] | Consolidation, Eliminations [Member]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

(6,000,000)

(18,000,000)

(17,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

6,000,000

18,000,000

17,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value, Assets and Liabilities Measured on Recurring Basis, Gain (Loss) Included in Earnings

190,000,000

229,000,000

579,000,000

623,000,000

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Realized Investment Gains (Losses)

2,000,000

1,000,000

13,000,000

8,000,000

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

1,689,000,000

1,904,000,000

1,689,000,000

1,904,000,000

1,386,000,000

1,776,000,000

1,759,000,000

1,708,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

92,000,000

(48,000,000)

(336,000,000)

(83,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

6,000,000

18,000,000

17,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

(1,000,000)

1,000,000

2,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

214,000,000

67,000,000

420,000,000

259,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

(7,000,000)

(18,000,000)

(11,000,000)

(42,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

288,000,000

180,000,000

247,000,000

538,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(28,000,000)

(13,000,000)

(119,000,000)

(75,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

214,000,000

67,000,000

420,000,000

259,000,000

Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Inputs Reconciliation, Period Increase (Decrease)

25,000,000

19,000,000

10,000,000

44,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

31,000,000

90,000,000

(51,000,000)

72,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

69,000,000

2,000,000

84,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

(4,000,000)

(3,000,000)

(11,000,000)

(38,000,000)

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

693,000,000

669,000,000

693,000,000

669,000,000

715,000,000

670,000,000

667,000,000

605,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

(4,000,000)

2,000,000

4,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

6,000,000

18,000,000

17,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

4,000,000

15,000,000

123,000,000

122,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

(1,000,000)

(8,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

3,000,000

(1,000,000)

7,000,000

2,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(28,000,000)

(13,000,000)

(119,000,000)

(75,000,000)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

4,000,000

15,000,000

123,000,000

122,000,000

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

4,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

19,000,000

29,000,000

19,000,000

29,000,000

25,000,000

22,000,000

41,000,000

50,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

(1,000,000)

1,000,000

2,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

1,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

(5,000,000)

(13,000,000)

(5,000,000)

(24,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3

1,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

935,000,000

1,174,000,000

935,000,000

1,174,000,000

609,000,000

1,051,000,000

1,021,000,000

1,050,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

95,000,000

^[1]

(48,000,000)

^[2]

(339,000,000)

^[1]

(87,000,000)

^[2]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

207,000,000

^[3]

50,000,000

289,000,000

^[3]

107,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

(2,000,000)

(5,000,000)

(10,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

285,000,000

181,000,000

240,000,000

536,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

207,000,000

^[3]

50,000,000

289,000,000

^[3]

107,000,000

(3,000,000)

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Indefinite-lived Intangible Assets Acquired

168,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

31,000,000

90,000,000

(51,000,000)

72,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

(1,000,000)

69,000,000

1,000,000

80,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

(4,000,000)

(11,000,000)

(38,000,000)

Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Other Investments [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

42,000,000

32,000,000

42,000,000

32,000,000

37,000,000

33,000,000

30,000,000

3,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

1,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

3,000,000

2,000,000

7,000,000

29,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

3,000,000

2,000,000

7,000,000

29,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

1,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

(244,000,000)

^[4]

(243,000,000)

^[5]

(244,000,000)

^[4]

(244,000,000)

^[4]

(243,000,000)

^[5]

(221,000,000)

^[4]

(247,000,000)

^[4]

(223,000,000)

^[5]

(207,000,000)

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

^[4]

^[5]

^[4]

^[5]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

^[4]

^[5]

^[4]

^[5]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

^[4]

^[5]

^[4]

^[5]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

(23,000,000)

^[4]

(20,000,000)

^[5]

3,000,000

^[4]

(36,000,000)

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

^[4]

^[5]

^[4]

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

^[4]

^[5]

^[4]

^[5]

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

^[4]

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

^[4]

^[5]

^[4]

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3

^[4]

^[5]

^[4]

^[5]

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

^[5]

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

^[5]

(243,000,000)

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

^[4]

^[5]

^[4]

^[5]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3

^[4]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3

^[4]

Pepco Holdings LLC [Member] | 6311 Life Insurance [Member] | Predecessor [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

$ 0

Pepco Holdings LLC [Member] | 6311 Life Insurance [Member] | Successor [Member]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

(1,000,000)

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | Predecessor [Member]

(1,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

16,000,000

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

15,000,000

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | Successor [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

20,000,000

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | 6311 Life Insurance [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

(2,000,000)

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | 6311 Life Insurance [Member] | Predecessor [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

20,000,000

19,000,000

20,000,000

19,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

1,000,000

4,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

(2,000,000)

(3,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

1,000,000

2,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(1,000,000)

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | 6311 Life Insurance [Member] | Successor [Member]

(2,000,000)

(3,000,000)

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

21,000,000

20,000,000

$ 20,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

1,000,000

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Nuclear Decommissioning Payable

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Regulatory assets

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

1,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Issuances

(1,000,000)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3

Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers out of Level 3

Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]

Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Change In Collateral

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | Preferred Stock [Member] | Predecessor [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

18,000,000

3,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

(18,000,000)

15,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

15,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

Pepco Holdings LLC [Member] | Fair Value, Inputs, Level 3 [Member] | Preferred Stock [Member] | Successor [Member]

$ 0

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

18,000,000

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

15,000,000

Delmarva Power and Light Company [Member] | 6311 Life Insurance [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

1,000,000

Delmarva Power and Light Company [Member] | Fair Value, Inputs, Level 3 [Member] | 6311 Life Insurance [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

1,000,000

Potomac Electric Power Company [Member] | 6311 Life Insurance [Member]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

(3,000,000)

(1,000,000)

(4,000,000)

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

2,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements

(3,000,000)

(1,000,000)

(4,000,000)

Potomac Electric Power Company [Member] | Fair Value, Inputs, Level 3 [Member]

18,000,000

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

1,000,000

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

Potomac Electric Power Company [Member] | Fair Value, Inputs, Level 3 [Member] | 6311 Life Insurance [Member]

Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value

$ 21,000,000

18,000,000

$ 21,000,000

21,000,000

18,000,000

$ 20,000,000

$ 19,000,000

$ 20,000,000

$ 18,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings

1,000,000

Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases

3,000,000

4,000,000

Fair Value, Assets Measured on Recurring Basis, Change in Unrealized Gain (Loss)

$ 0

Exelon Generation Co L L C [Member] | Derivative [Member]

$ 3,000,000

$ 4,000,000

[1]	Includes a reduction for the reclassification of $190 million and $579 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2016, respectively.
[2]	Includes a reduction for the reclassification of $229 million and $623 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2015, respectively.
[3]	Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.
[4]	Includes $25 million of decreases in fair value and realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2016. Includes $10 million of decreases in fair value and realized losses due to settlements of $13 million for the nine months ended September 30, 2016.
[5]	ncludes $19 million of decreases in fair value and a reduction for realized gains due to settlements of $1 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended September 30, 2015. Includes $44 million of decreases in fair value and an increase for realized losses due to settlements of $8 million for the nine months ended September 30, 2015.

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities - Narrative (Details)	Sep. 30, 2016 USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward Power Basis	$ 2.81
Forward Gas Basis	0.36
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	170,000,000
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	73,000,000
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	$ 220,000,000

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($)

9 Months Ended

12 Months Ended

Sep. 30, 2016

Dec. 31, 2015

Dec. 31, 2014

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

$ 788,000,000

^[1],[2]

$ 857,000,000

^[3],[4]

Exelon Generation Co L L C [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]

Exelon Generation Co L L C [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]

Forward gas price assets

1.24

1.18

Exelon Generation Co L L C [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Minimum [Member]

130

Forward gas price assets

$ 9.53

$ 8.95

Exelon Generation Co L L C [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Maximum [Member]

Volatility percentage

5.00%

Exelon Generation Co L L C [Member] | Proprietary Trading [Member]

Volatility percentage

115.00%

152.00%

Derivatives, Fair Value [Line Items]

Derivative Liability, Fair Value, Amount Not Offset Against Collateral

$ (3,000,000)

^[1],[2]

$ (7,000,000)

^[3],[4]

Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Minimum [Member]

Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Maximum [Member]

Commonwealth Edison Co [Member] | Derivative [Member]

Derivatives, Fair Value [Line Items]

Derivative Asset, Fair Value, Amount Not Offset Against Collateral

$ (244,000,000)

$ (247,000,000)

Commonwealth Edison Co [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]

Derivatives Fair Value Footnotes [Abstract]

Forward heat rate

(8.00%)

Fair Value Inputs, Discount for Lack of Marketability

3.00%

3.50%

Fair Value Inputs Renewable Factor

86.00%

87.00%

Commonwealth Edison Co [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]

Derivatives Fair Value Footnotes [Abstract]

Forward heat rate

(9.00%)

Fair Value Inputs, Discount for Lack of Marketability

8.00%

7.00%

Fair Value Inputs Renewable Factor

121.00%

128.00%

[1]	(a)The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[2]	The fair values do not include cash collateral posted on level three positions of $150 million as of September 30, 2016.
[3]	The fair values do not include cash collateral posted on level three positions of $201 million as of December 31, 2015.
[4]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) - USD ($)
$ in Millions

Sep. 30, 2016

Dec. 31, 2015

$ 35

754

$ 1,365

669

758

222

205

422

374

(4)

754

1,365

630

733

203

182

InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member]

197

150

(9)

(8)

(10)

(8)

(19)

(16)

InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member] | Economic Hedges [Member]

(4)

(10)

(2)

(9)

(1)

(19)

(3)

InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member] | Collateral And Netting [Member]

(10)

(5)

(11)

(1)

(21)

(6)

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

Derivative [Member]

745

1,350

624

719

1,369

2,069

213

197

412

366

625

563

Derivative [Member] | Exelon Generation Co L L C [Member]

744

1,506

^[1]

745

1,350

^[1]

624

719

^[1]

1,369

2,069

^[1]

194

174

^[1]

187

142

^[1]

381

316

Not Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member]

^[1]

988

1,753

(3)

(9)

(3)

(6)

(12)

Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member]

(9)

(8)

(10)

(8)

(19)

(16)

Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member] | Exelon Generation Co L L C [Member]

(8)

(10)

(8)

(18)

(16)

Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member] | Corporate, Non-Segment [Member]

(18)

(16)

$ 39

$ 25

[1]

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Jun. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2015

Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net

$ 340

$ 115

$ 625

$ 805

^[1]

Increase (Decrease) in Fair Value of Hedged Item in Price Risk Fair Value Hedge

$ 3

(13)

(4)

Gain (Loss) on Fair Value Hedges Recognized in Earnings

Derivative Instruments Not Designated as Hedging Instruments, Asset, at Fair Value

(10)

$ (8)

Increase (Decrease) in Fair Value of Hedged Item in Price Risk Fair Value Hedge

173

$ (36)

293

371

^[1]

Interest Expense [Member] | Fair Value Hedging [Member]

Increase (Decrease) in Fair Value of Hedged Item in Price Risk Fair Value Hedge

(3)

Interest Rate Swap [Member] | Fair Value Hedging [Member]

Gain (Loss) on Fair Value Hedges Recognized in Earnings

$ (8)

Interest Rate Swap [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member]

Gain (Loss) on Fair Value Hedges Recognized in Earnings

^[1]

$ 0

(1)

Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member]

$ (1)

[1]	For the nine months ended September 30, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

Derivative Financial Instruments Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($)
$ in Millions

Sep. 30, 2016

Mar. 23, 2016

Dec. 31, 2015

$ 754

$ 1,365

669

758

(222)

(205)

(422)

(374)

Derivative [Member]

745

1,350

Total mark-to-market derivative net assets (liabilities)

624

719

744

1,506

1,369

2,069

(213)

(197)

(412)

(366)

(625)

(563)

754

1,365

630

733

(203)

(182)

Exelon Generation Co L L C [Member] | Economic Hedging Instrument [Member]

(197)

(150)

3,482

5,236

Total mark-to-market derivative net assets (liabilities)

2,139

1,860

507

516

5,621

7,096

(3,229)

(4,907)

(1,885)

(1,673)

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]

(5,114)

(6,580)

Current assets collateral offset

135

352

Noncurrent assets collateral offset

180

Current liabilities collateral offset

156

480

Noncurrent liabilities collateral offset

110

222

Total cash collateral received net of cash collateral posted

485

(1,234)

Exelon Generation Co L L C [Member] | Derivative [Member]

^[1]

745

1,350

Total mark-to-market derivative net assets (liabilities)

^[1]

624

719

^[1]

988

1,753

^[1]

1,369

2,069

^[1]

(194)

(174)

^[1]

(187)

(142)

Exelon Generation Co L L C [Member] | Proprietary Trading [Member]

^[1]

(381)

(316)

108

Total mark-to-market derivative net assets (liabilities)

(4)

130

(61)

(94)

(41)

(33)

Exelon Generation Co L L C [Member] | Collateral And Netting [Member]

(102)

(127)

(2,804)

(3,994)

Total mark-to-market derivative net assets (liabilities)

(1,546)

(1,163)

^[2]

485

1,234

^[2]

(4,350)

(5,157)

3,096

4,827

1,739

1,564

^[2]

4,835

6,391

(19)

(23)

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]

(225)

(224)

Total mark-to-market derivative net assets (liabilities)

^[3]

(244)

(247)

^[3]

(23)

225

(224)

Delmarva Power and Light Company [Member] | Designated as Hedging Instrument [Member]

^[3]

(244)

(247)

Total mark-to-market derivative net assets (liabilities)

(2)

Delmarva Power and Light Company [Member] | Derivative [Member]

^[4]

Total mark-to-market derivative net assets (liabilities)

^[4]

^[4]

^[4]

^[4]

Delmarva Power and Light Company [Member] | Collateral And Netting [Member]

^[4]

(1)

Total mark-to-market derivative net assets (liabilities)

(1)

(1)

(2)

(2)

Total mark-to-market derivative net assets (liabilities)

$ 0

Total mark-to-market derivative net assets (liabilities)

$ 0

Total mark-to-market derivative net assets (liabilities)

Pepco Holdings LLC [Member] | Derivative [Member] | Corporate, Non-Segment [Member]

Total mark-to-market derivative net assets (liabilities)

$ 0

[1]	.
[2]	.
[3]	.
[4]	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 AOCI related to Cash Flow Hedges (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Jun. 30, 2016

Dec. 31, 2015

Jun. 30, 2015

Dec. 31, 2014

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

$ (2,523)

$ (2,596)

$ (2,523)

$ (2,596)

$ (2,624)

$ (2,684)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(5)

(64)

^[1],[2]

(106)

(152)

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

340

115

625

805

Reclassifications from accumulated OCI to net income

4,535

4,564

12,243

14,278

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(56)

(60)

(56)

(60)

(63)

(36)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(30)

^[1],[2]

(2)

(6)

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

173

(36)

293

371

Reclassifications from accumulated OCI to net income

4,533

4,562

12,234

14,270

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(23)

(24)

(23)

(24)

(19)

(28)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(1)

(18)

^[1],[2]

(22)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(23)

^[1]

(24)

^[1]

(23)

^[1]

(24)

^[1]

$ (26)

$ (19)

(28)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]

(8)

Accumulated Other Comprehensive Income (Loss), Net of Tax

(24)

^[1]

(25)

^[1]

(24)

^[1]

(25)

^[1]

$ (21)

(18)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(13)

^[1],[2]

(6)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | Cash Flow Hedging [Member]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(24)

^[1]

(25)

^[1]

(24)

^[1]

(25)

^[1]

$ (18)

(7)

Accumulated Other Comprehensive Income (Loss), Net of Tax

(24)

^[1]

(25)

^[1]

(24)

^[1]

(25)

^[1]

$ (25)

$ (21)

Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Exelon Generation Co L L C [Member]

^[3]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[3]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]

^[3]

(1)

(13)

Interest Expense [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member]

(1)

^[3]

$ 2

^[3]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

Interest Expense [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | 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

$ 1

$ 3

Interest Expense [Member] | Operating Revenue [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | 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

(18)

Interest Expense [Member] | Total Cash Flow Hedges [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | 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

(13)

Operating Revenue [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | 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

(2)

Operating Revenue [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | 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

(2)

Operating Revenue [Member] | Total Cash Flow Hedges [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member] | 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

Operating Revenue [Member] | Total Cash Flow Hedges [Member] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | 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

$ 16

[1]	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.
[2]	See next tables for details about these reclassifications.
[3]	Amounts in parenthesis represent a decrease in net income.

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	$ 207	$ (42)	$ 163	$ 350
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(118)	(97)	(267)	(98)
Unrealized Gain (Loss) on Derivatives			(100)	363
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	1	2	(3)	48
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	207	(42)	163	350
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(118)	(97)	(267)	(98)
Unrealized Gain (Loss) on Derivatives			(112)	252
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	1	2	(3)	12
Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	(73)	(178)	36	(163)
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(26)	46	217	249
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	0	0	0	0
Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts				0
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net				0
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge		0		36
Interest Expense [Member] \| Corporate, Non-Segment [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net
Change in fair value		0
Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	280	136	127	513
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(92)	(143)	(484)	(347)
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	1	2	(3)	12
Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(1)	(6)	1	(5)
Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	58
Unrealized Gain (Loss) on Derivatives	(1)	0	(9)	106
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	88	(139)	(113)	358
Foreign Exchange Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	(6)
Unrealized Gain (Loss) on Derivatives	(1)	0	(9)	6
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	88	(139)	(113)	258
Foreign Exchange Contract [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	0	0	0	0
Unrealized Gain (Loss) on Derivatives	0	0	0	0
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(99)	(132)	253	86
Foreign Exchange Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net		0		64
Unrealized Gain (Loss) on Derivatives		0		100
Unrealized Gain (Loss) on Derivatives and Commodity Contracts		0		100
Foreign Exchange Contract [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	(6)
Unrealized Gain (Loss) on Derivatives	(1)	0	(9)	6
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	187	(7)	(366)	172
Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	1	(3)	2	(9)
Unrealized Gain (Loss) on Derivatives	1	0	0	(2)
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	0	3	(2)	7
Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	89	(139)	(104)	252
Commodity Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	89	(139)	(104)	252
Commodity Contract [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(99)	(132)	253	86
Commodity Contract [Member] \| Interest Expense [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives		0		0
Commodity Contract [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	188	(7)	(357)	166
Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	4	(4)	18	5
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(6)	(2)	(17)	(8)
Unrealized Gain (Loss) on Derivatives	$ (2)	$ (6)	$ 1	$ (3)

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	$ 207	$ (42)	$ 163	$ 350
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(118)	(97)	(267)	(98)
Unrealized Gain (Loss) on Derivatives			(100)	363
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	1	2	(3)	48
Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	(1)	(6)	1	(5)
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	207	(42)	163	350
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(118)	(97)	(267)	(98)
Unrealized Gain (Loss) on Derivatives			(112)	252
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	1	2	(3)	12
Commodity Contract [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	89	(139)	(104)	252
Commodity Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	4	(4)	18	5
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(6)	(2)	(17)	(8)
Unrealized Gain (Loss) on Derivatives	(2)	(6)	1	(3)
Commodity Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	89	(139)	(104)	252
Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	58
Unrealized Gain (Loss) on Derivatives	(1)	0	(9)	106
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	88	(139)	(113)	358
Foreign Exchange Contract [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	1	(3)	2	(9)
Unrealized Gain (Loss) on Derivatives	1	0	0	(2)
Change in Unrealized Gain (Loss) on Hedged Item in Foreign Currency Fair Value Hedge	0	3	(2)	7
Foreign Exchange Contract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments, Gain (Loss) Reclassified from Accumulated OCI into Income, Effective Portion, Net	(2)	(2)	(6)	(6)
Unrealized Gain (Loss) on Derivatives	(1)	0	(9)	6
Unrealized Gain (Loss) on Derivatives and Commodity Contracts	$ 88	$ (139)	$ (113)	$ 258

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member]
$ in Millions

Sep. 30, 2016

USD ($)

Investor-owned utilities, marketers and power producers

$ 757

Energy Cooperatives And Municipalities

712

Financial institutions

117

Net Exposure [Member]

1,013

No external ratings - internally rated - investment grade

153

420

No external ratings - internally rated - non-investment grade

Total Exposure Before Credit Collateral [Member]

1,644

1,017

No external ratings - internally rated - investment grade

175

423

No external ratings - internally rated - non-investment grade

Credit Collateral [Member]

1,676

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]

^[1]

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]

355

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

$ 355

[1]	of September 30, 2016, credit collateral held from counterparties where Generation had credit exposure included $10 million of cash and $22 million of letters of credit. The credit collateral does not include non-liquid collateral.

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

Sep. 30, 2016

Dec. 31, 2015

Aggregate fair value of derivatives with credit-risk-related contingent features

$ (975)

$ (932)

Contractual right of offset related to derivative assets

664

684

Net liability position after contractual right of offset

^[1]

$ (311)

$ (248)

[1]

unt 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.Ge

Derivative Financial Instruments - Narrative (Details)
$ in Millions

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2016

USD ($)

GWh

Jun. 30, 2016

USD ($)

Sep. 30, 2015

USD ($)

GWh

Jun. 30, 2015

USD ($)

Sep. 30, 2016

USD ($)

GWh

Sep. 30, 2015

USD ($)

GWh

Dec. 31, 2015

USD ($)

Mar. 31, 2016

USD ($)

$ 340

$ 115

$ 625

$ 805

$ 100

$ 600

Derivative Instruments, Loss Recognized in Other Comprehensive Income (Loss), Effective Portion

$ 3

Hypothetical increase in interest rates associated with variable-rate debt

Ineffective portion recognized in income

^[1]

Mark-to-market derivative liabilities (noncurrent liabilities)

422

$ 374

222

205

Cash collateral posted

Letters of credit posted

Debt Instrument, Face Amount

750

Mark-to-market derivative liabilities (noncurrent liabilities)

173

$ (36)

293

$ 371

197

150

Cash collateral received not offset against net derivative positions

203

182

(5)

Cash collateral posted

501

1,267

Letters of credit held

Letters of credit posted

420

497

Cash collateral held

Incremental collateral for loss of investment grade credit rating

1,900

2,000

Derivative, Nonmonetary Notional Amount, Energy Measure | GWh

$ (4)

1,506

1,913

4,015

5,378

Commonwealth Edison Company [Member]

Cash collateral held

$ 3

Mark-to-market derivative liabilities (noncurrent liabilities)

$ 99

244

$ 226

225

224

Incremental collateral for loss of investment grade credit rating

Cash collateral held

Credit Exposure Under Off System Sales

Estimated percentage of natural gas purchases hedged

$ 121

122

25.00%

Incremental collateral for loss of investment grade credit rating

$ 25

Incremental collateral for loss of investment grade credit rating

109

141

Credit Exposure Under Off System Sales

Incremental collateral for loss of investment grade credit rating

$ 9

Minimum [Member] | Exelon Generation Co L L C [Member]

Expected Generation Hedged In Next Twelve Months

98.00%

Expected Generation Hedged In Year Two

85.00%

Expected generation hedged in year three

54.00%

Minimum [Member] | Baltimore Gas and Electric Company [Member]

Estimated percentage of natural gas purchases hedged

10.00%

Maximum [Member] | Exelon Generation Co L L C [Member]

Expected Generation Hedged In Next Twelve Months

101.00%

Expected Generation Hedged In Year Two

88.00%

Expected generation hedged in year three

57.00%

Maximum [Member] | Baltimore Gas and Electric Company [Member]

Estimated percentage of natural gas purchases hedged

20.00%

Interest Rate Swap [Member]

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

800

$ 800

Cash Flow Hedging [Member]

Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]

$ 100

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

672

Designated as Hedging Instrument [Member] | Commonwealth Edison Co [Member]

Mark-to-market derivative liabilities (noncurrent liabilities)

^[2]

(244)

(247)

(225)

224

Designated as Hedging Instrument [Member] | Delmarva Power and Light Company [Member]

(19)

Mark-to-market derivative liabilities (noncurrent liabilities)

(2)

Foreign Exchange Contract [Member] | Exelon Generation Co L L C [Member]

(2)

Brokered Natural Gas Margin Revenue

Derivative [Member]

Mark-to-market derivative liabilities (noncurrent liabilities)

744

1,506

412

366

Derivative [Member] | Exelon Generation Co L L C [Member]

213

197

Mark-to-market derivative liabilities (noncurrent liabilities)

^[3]

988

1,753

^[3]

187

142

Derivative [Member] | Delmarva Power and Light Company [Member]

^[3]

194

174

Mark-to-market derivative liabilities (noncurrent liabilities)

^[4]

Fair Value Hedging [Member] | Interest Rate Swap [Member]

^[4]

Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments

800

$ 25

Cash Flow Hedging [Member] | Interest Rate Swap [Member]

Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Exelon Generation Co L L C [Member]

Increase In Notional Amount Of Derivative Instruments

176

Other Solar Projects [Member] | Exelon Generation Co L L C [Member]

Notional amounts on forward starting interest rate swaps

Other Solar Projects [Member] | Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]

Notional amounts on forward starting interest rate swaps

PHI Merger [Member] | Interest Rate Swap [Member]

PHI Merger [Member] | Designated as Hedging Instrument [Member]

$ 2,400

Derivative, Gain (Loss) on Derivative, Net

$ 64

ExGen Texas Power [Member] | Interest Rate Swap [Member]

ExGen Texas Power [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member]

496

Mark-to-market derivative liabilities (noncurrent liabilities)

Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification out of Accumulated Other Comprehensive Income [Member] | Exelon Generation Co L L C [Member]

^[5]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[5]

Cash Flow Hedge Gain Loss Reclassified To Pretax Net Income From Accumulated Other Comprehensive Income

^[5]

(1)

(13)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Exelon Generation Co L L C [Member]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

$ (1)

^[5]

Commonwealth Edison Co Affiliate [Member] | Exelon Generation Co L L C [Member]

^[5]

(2)

$ (10)

PECO Energy Co Affiliate [Member] | Exelon Generation Co L L C [Member]

Net receivable from affiliated electric and gas utility

Baltimore Gas And Electric Company Affiliate [Member] | Exelon Generation Co L L C [Member]

Net receivable from affiliated electric and gas utility

Potomac Electric Power Company [Member] | 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] | Exelon Generation Co L L C [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

$ 10

[1]	For the nine months ended September 30, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.
[2]	.
[3]	.
[4]	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.
[5]	Amounts in parenthesis represent a decrease in net income.

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	$ 10	$ 294
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	0	210
PEPCO Holdings Inc [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	0	484
Potomac Electric Power Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	0	64
Delmarva Power and Light Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	17	105
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	$ 0	$ 5

Debt and Credit Agreements - Narrative (Details) - USD ($) $ in Millions		9 Months Ended
	Feb. 29, 2016	Sep. 30, 2016	Apr. 01, 2016	Mar. 31, 2016	Jan. 13, 2016	Dec. 31, 2015	Sep. 30, 2015
Debt Instrument [Line Items]
Interest Rate		4.10%
Debt Instrument, Face Amount							$ 750
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 600	$ 100
Revolving Credit Facility [Member] \| Minimum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		$ 500
Exelon Generation Co L L C [Member] \| NonrecourseDebtSeptember2019Member [Member]
Debt Instrument [Line Items]
Interest Rate		4.80%
Debt Instrument, Face Amount		$ 4
Exelon Generation Co L L C [Member] \| Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity			$ 200	$ 150
Pepco Holdings LLC [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable					$ 500		$ 300
Short-term Debt, Percentage Bearing Variable Interest Rate					1.00%
Pepco Holdings LLC [Member] \| Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity		900
Pepco Holdings LLC [Member] \| Revolving Credit Facility [Member] \| Minimum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		1,500
Delmarva Power and Light Company [Member] \| Variable Rate Demand Obligation [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities		105
CEU Holdings, LLC [Member]
Debt Instrument [Line Items]
Repayments of Bank Debt		7
Line of Credit Facility, Increase (Decrease), Other, Net	$ 45
Secured Demand Note Deficiency	$ 23	16
Outstanding borrowings/facility draws						$ 85
Line of Credit Facility, Maximum Borrowing Capacity		$ 500
Long-term Debt				$ 61		$ 68

Debt and Credit Agreements - Schedule of Issuance of Long-Term Debt (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Debt Instrument [Line Items]
Interest Rate	4.10%
Debt Instrument, Face Amount		$ 750
Proceeds from (Repayments of) Other Long-term Debt	$ (30)	0
SeniorUnsecured245April2021 [Member]
Debt Instrument [Line Items]
Interest Rate	2.45%
Debt Instrument, Face Amount	$ 300
SeniorUnsecured340April2026 [Member]
Debt Instrument [Line Items]
Interest Rate	3.40%
Debt Instrument, Face Amount	$ 750
SeniorUnsecured445April2046 [Member]
Debt Instrument [Line Items]
Interest Rate	4.45%
Debt Instrument, Face Amount	$ 750
Exelon Generation Co L L C [Member] \| Energy Efficiency Project Financing [Member]
Debt Instrument [Line Items]
Interest Rate	1.43%
Debt Instrument, Face Amount	$ 86
Exelon Generation Co L L C [Member] \| EscoNotes390February2018 [Member]
Debt Instrument [Line Items]
Interest Rate	3.40%
Debt Instrument, Face Amount	$ 13
Exelon Generation Co L L C [Member] \| DominionFederal [Member]
Debt Instrument [Line Items]
Interest Rate	0.00%
Debt Instrument, Face Amount	$ 16
Exelon Generation Co L L C [Member] \| NonrecourseDebtSeptember2036 [Member]
Debt Instrument [Line Items]
Interest Rate	3.90%
Debt Instrument, Face Amount	$ 150
Exelon Generation Co L L C [Member] \| NonrecourseDebtSeptember2019Member [Member]
Debt Instrument [Line Items]
Interest Rate	4.80%
Debt Instrument, Face Amount	$ 4
Exelon Generation Co L L C [Member] \| DOE Financing Project [Member] \| Energy Efficiency Project Financing [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 150
Commonwealth Edison Co [Member] \| FirstMortgageBonds120 [Member]
Debt Instrument [Line Items]
Interest Rate	2.55%
Debt Instrument, Face Amount	$ 500
Commonwealth Edison Co [Member] \| FirstMortgageBonds121 [Member]
Debt Instrument [Line Items]
Interest Rate	3.65%
Debt Instrument, Face Amount	$ 700
PECO Energy Co [Member]
Debt Instrument [Line Items]
Proceeds from (Repayments of) Other Long-term Debt	$ (30)	$ 0
PECO Energy Co [Member] \| FirstMortgageBondsSeptember2021 [Member]
Debt Instrument [Line Items]
Interest Rate	1.70%
Debt Instrument, Face Amount	$ 0
Potomac Electric Power Company [Member] \| EscoNotes330August2017 [Member]
Debt Instrument [Line Items]
Interest Rate	3.50%
Debt Instrument, Face Amount	$ 11
Potomac Electric Power Company [Member] \| ESCONotesDOEGDecember2017 [Member]
Debt Instrument [Line Items]
Interest Rate	3.30%
Debt Instrument, Face Amount	$ 2
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Proceeds from (Repayments of) Other Long-term Debt	(190)
Baltimore Gas and Electric Company [Member] \| SeniorNotesAugust2046 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	500
Baltimore Gas and Electric Company [Member] \| SeniorNotesAugust2026Member [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	$ 350
Baltimore Gas and Electric Company [Member] \| Notes Payable, Other Payables [Member] \| SeniorNotesAugust2046 [Member]
Debt Instrument [Line Items]
Interest Rate	3.50%
Baltimore Gas and Electric Company [Member] \| Notes Payable, Other Payables [Member] \| SeniorNotesAugust2026Member [Member]
Debt Instrument [Line Items]
Interest Rate	2.40%

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended			6 Months Ended	9 Months Ended
	Sep. 30, 2016	Mar. 23, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	3.80%		2.70%		2.50%	3.10%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(4.00%)		(5.40%)		(4.80%)	(0.90%)
Domestic production activities deduction	(0.00%)		(4.90%)		(0.00%)	(2.80%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%		0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.90%)		(2.30%)		(1.30%)	(1.20%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	(3.00%)		(1.40%)		(4.50%)	1.20%
Production tax credits and other credits	(0.60%)				(6.20%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(2.90%)		(3.80%)		(4.10%)	(2.20%)
Noncontrolling interests	0.20%		1.70%		0.50%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(0.10%)		(6.40%)		(0.50%)	(1.60%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	4.30%				2.30%
Other(c)	0.80%		(1.20%)		(1.80%)	(0.90%)
Effective income tax rate	39.00%		16.40%		39.10%	29.10%
Predecessor [Member]
Increase (decrease) due to:
Domestic production activities deduction			(0.00%)
Noncontrolling interests			0.00%
Successor [Member]
Increase (decrease) due to:
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent		0.00%		0.00%
Exelon Generation Co L L C [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	2.60%		2.10%		2.60%	2.80%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(7.80%)		(12.50%)		(8.80%)	(1.60%)
Domestic production activities deduction	(0.00%)		(11.60%)		(0.00%)	(4.90%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%		0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(1.60%)		(5.20%)		(2.00%)	(1.90%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Production tax credits and other credits	(0.00%)				(0.00%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(5.70%)		(9.00%)		(7.60%)	(3.80%)
Noncontrolling interests	0.50%		3.90%		0.90%	0.10%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(0.30%)		(15.20%)		1.70%	(2.90%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	0.00%				0.00%
Other(c)	0.50%		(0.40%)		2.10%	(0.60%)
Effective income tax rate	38.40%		(12.10%)		33.90%	23.40%
Commonwealth Edison Co [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	7.30%		5.00%		5.40%	5.20%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Domestic production activities deduction	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%		0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.60%)		(0.30%)		(0.30%)	(0.30%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	1.90%		0.10%		0.60%	0.10%
Production tax credits and other credits	(0.00%)				(0.00%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.10%)		(0.00%)		(0.00%)	(0.00%)
Noncontrolling interests	0.00%		0.00%		0.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(0.00%)		(0.00%)		(0.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	27.20%				5.60%
Other(c)	(0.10%)		(0.30%)		(0.00%)	(0.20%)
Effective income tax rate	67.00%				45.10%	40.00%
PECO Energy Co [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	2.40%		1.20%		1.30%	1.20%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Domestic production activities deduction	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%		0.00%	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)		(0.10%)		(0.10%)	(0.10%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	6.70%		7.00%		8.80%	7.30%
Production tax credits and other credits	(0.00%)				(0.00%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Noncontrolling interests	0.00%		0.00%		0.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(0.00%)		(0.00%)		(0.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	0.00%				0.00%
Other(c)	(0.10%)		(0.00%)		1.50%	(0.20%)
Effective income tax rate	30.70%				25.90%	29.00%
Baltimore Gas and Electric Company [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	5.20%		5.30%		4.80%	5.30%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Domestic production activities deduction	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.20%		0.00%	0.20%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)		(0.20%)		(0.20%)	(0.10%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	0.50%		0.60%		3.30%	0.40%
Production tax credits and other credits	(0.00%)				(0.00%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Noncontrolling interests	0.00%		0.00%		0.00%	0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(0.00%)		(0.00%)		(0.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	0.00%				0.00%
Other(c)	0.40%		0.40%		(0.00%)	0.10%
Effective income tax rate	39.10%				36.30%	39.90%
Pepco Holdings LLC [Member]
Increase (decrease) due to:
Domestic production activities deduction						(0.00%)
Pepco Holdings LLC [Member] \| Predecessor [Member]
Increase (decrease) due to:
U.S. Federal statutory rate			35.00%			35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent			6.20%			7.10%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent			(0.00%)			(0.00%)
Domestic production activities deduction						(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%)			(0.30%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent			3.70%			5.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent			(1.20%)			(1.90%)
Noncontrolling interests						0.00%
Other(c)			1.10%			0.10%
Effective income tax rate			35.00%			34.80%
Pepco Holdings LLC [Member] \| Successor [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	5.60%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)				(0.00%)
Domestic production activities deduction	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	5.00%
Production tax credits and other credits	(5.70%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.00%)
Noncontrolling interests	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%				0.00%
Other(c)	0.70%
Effective income tax rate	29.10%
Delmarva Power and Light Company [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	5.20%		7.40%		310.50%	6.10%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Domestic production activities deduction	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%			0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.20%)		(0.60%)		(17.90%)	(0.40%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	1.30%		3.50%		98.60%	2.00%
Production tax credits and other credits	(8.60%)				(635.90%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Noncontrolling interests	0.00%		0.00%			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%				0.00%
Other(c)	(0.10%)		0.80%		(35.10%)	0.50%
Effective income tax rate	30.20%		37.50%		900.00%	38.20%
Potomac Electric Power Company [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	5.60%		4.80%		23.00%	4.60%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Domestic production activities deduction	(0.00%)		(0.00%)		(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%			0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.00%)		(0.10%)		(0.20%)	(0.10%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	6.70%		3.50%		29.00%	6.20%
Production tax credits and other credits	(2.30%)				(36.70%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Noncontrolling interests	0.00%		0.00%			0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent	(0.00%)		(0.00%)		(0.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	0.00%				0.00%
Other(c)	0.90%		1.40%		2.50%	0.70%
Effective income tax rate	30.70%		34.80%		63.00%	32.60%
Atlantic City Electric Company [Member]
Increase (decrease) due to:
U.S. Federal statutory rate	35.00%		35.00%		35.00%	35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent	6.10%		5.40%		5.50%	5.50%
Effective Income Tax Rate Reconciliation, Tax Contingency, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Domestic production activities deduction	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Effective Income Tax Rate Reconciliation, Deduction, Medicare Prescription Drug Benefit, Percent	0.00%		0.00%			0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	(0.10%)		(0.30%)		(0.50%)	(0.50%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	4.60%		3.10%		(7.80%)	2.50%
Production tax credits and other credits	(2.90%)				(35.40%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent	(0.00%)		(0.00%)		(0.00%)	(0.00%)
Noncontrolling interests	0.00%		0.00%			0.00%
Effective Income Tax Rate Reconciliation, Tax Settlement, Percent					(0.00%)
Effective Income Tax Rate Reconciliation, Tax Settlement, Other, Percent	0.00%				0.00%
Other(c)	0.60%		(1.90%)		(0.40%)	(0.80%)
Effective income tax rate	32.90%		38.90%		13.80%	38.30%
Atlantic City Electric Company [Member] \| Predecessor [Member]
Increase (decrease) due to:
Production tax credits and other credits		(11.10%)
Atlantic City Electric Company [Member] \| Successor [Member]
Increase (decrease) due to:
U.S. Federal statutory rate		35.00%		35.00%
Effective Income Tax Rate Reconciliation, State and Local Income Taxes, Percent		11.90%		4.40%
Domestic production activities deduction		(0.00%)		(0.00%)
Amortization of investment tax credit, including deferred taxes on basis difference		0.90%		0.50%
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent		13.50%		(17.50%)
Production tax credits and other credits				(49.80%)
Effective Income Tax Rate Reconciliation, Tax Credit, Other, Percent		(0.00%)		(0.00%)
Noncontrolling interests		0.00%
Other(c)		(3.60%)		(1.40%)
Effective income tax rate		47.20%		9.00%

Income Taxes - Narrative (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015	Mar. 31, 2014	Sep. 30, 2016	Dec. 31, 2015	Mar. 31, 2013	Dec. 31, 2009
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	$ 937			$ 937	$ 1,101
Payments for Other Taxes				1,000
Unrecognized Tax Benefits, Period Increase (Decrease)	328			164
Deferred Gain on Sale of Property							$ 1,200
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	251			251
IRS asserted penalties for understatement of tax	90
Expected non-cash charge to earnings						$ 265
Early termination amount		$ 200
Taxes Payable, Current		150
Income Taxes Receivable	80			80
Unrecognized Tax Benefits, Income Tax Penalties Accrued	1,400			1,400
Tax Adjustments, Settlements, and Unusual Provisions				300
Parent Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities				1
Exelon Generation Co L L C [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	516			516	534
Unrecognized tax benefits that if recognized would affect the effective tax rate	52			52
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	52			52
Tax Adjustments, Settlements, and Unusual Provisions				6
Commonwealth Edison Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	(12)			(12)	142
Unrecognized Tax Benefits, Period Increase (Decrease)	154
Expected non-cash charge to earnings			$ 172
Non-cash equity contributions			$ 172
Taxes Payable, Current		$ 150
Income Taxes Receivable	345			345
Unrecognized Tax Benefits, Income Tax Penalties Accrued	300			300
PECO Energy Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	0			0	0
Baltimore Gas and Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	120			120	120
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	120			120
Pepco Holdings LLC [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	157			157
Unrecognized Tax Benefits, Period Increase (Decrease)	135
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	79			79
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits					22
PEPCO Holdings Inc [Member]
Income Tax Additional Narrative Information [Line Items]
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent	8			8
Potomac Electric Power Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	79			79	8
Unrecognized Tax Benefits, Period Increase (Decrease)	71
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	59			59
Delmarva Power and Light Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	34			34	3
Unrecognized Tax Benefits, Period Increase (Decrease)	31
Significant Change in Unrecognized Tax Benefits is Reasonably Possible, Amount of Unrecorded Benefit	20			20
Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits	22			$ 22	$ 0
Unrecognized Tax Benefits, Period Increase (Decrease)	$ 22

Income Taxes Income Tax Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 937	$ 1,101
Exelon Generation Co L L C [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	516	534
Commonwealth Edison Co [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	(12)	142
PECO Energy Co [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	0	0
Baltimore Gas and Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	120	120
Pepco Holdings LLC [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	157
Pepco Holdings LLC [Member] \| Predecessor [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits		22
Delmarva Power and Light Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	34	3
Potomac Electric Power Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	79	8
Atlantic City Electric Company [Member]
Income Tax Contingency [Line Items]
Unrecognized Tax Benefits	$ 22	$ 0

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) - USD ($)
$ in Millions

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2015

^[1]

$ 333

$ 291

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Exelon Generation Co L L C [Member] | Oyster Creek [Member]

^[1]

332

$ 291

Current portion of ARO

$ 7

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Exelon Generation Co L L C [Member] | Clinton And Quad Cities [Member]

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Exelon Generation Co L L C [Member] | Nuclear Decommissioning [Member]

384

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Nuclear Decommissioning ARO, Beginning Balance

^[2]

8,246

Asset Retirement Obligation, Liabilities Settled

325

(6)

Asset Retirement Obligation, Period Increase (Decrease)

763

Nuclear Decommissioning ARO, Ending Balance

444

^[2]

9,009

Current portion of ARO

$ 44

[1]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[2]	Includes $44 million and $7 million for the current portion of the ARO at September 30, 2016 and December 31, 2015, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

Nuclear Decommissioning (Details) - USD ($) $ in Millions	Sep. 30, 2016	Dec. 31, 2015
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Liability, Noncurrent	$ 33	$ 90
Decommissioning Fund Investments	11,076	10,342
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Liability, Noncurrent	33	90
Decommissioning Fund Investments	11,076	$ 10,342
Nuclear Plant [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Liability, Noncurrent	$ 87

Nuclear Decommissioning - Unrealized Gains on NDT Funds (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

Net unrealized gains (losses) on decommissioning trust funds - regulatory agreement units

^[1]

$ 155

$ (301)

$ 286

$ (385)

Net unrealized gains (losses) on decommissioning trust funds - non-regulatory agreement units

^[2],[3]

116

$ (218)

216

(274)

Unrealized Gain Loss Investment Income Pledged Assets

$ (5)

$ (2)

$ 9

[1]	Net unrealized gains 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 $(5) million of net unrealized gain related to the Zion Station pledged assets for the three months ended September 30, 2016. Excludes $(2) million and $9 million of net unrealized gain related to the Zion Station pledged assets for the nine months ended September 30, 2016 and 2015, 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 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 - Assets, Payables and Withdrawals by ZionSolutions (Details) - USD ($)
$ in Millions

9 Months Ended

12 Months Ended

Sep. 30, 2016

Dec. 31, 2015

Nuclear Decommissioning Additional Narrative Information [Line Items]

$ 135

$ 206

Nuclear Decommissioning Additional Narrative Information [Line Items]

Payable to Zion Solutions

135

206

^[1]

124

189

Current portion of payable to Zion Solutions

^[2]

Withdrawals by Zion Solutions to pay decommissioning costs

^[3]

$ 855

$ 786

[1]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT funds. The NDT funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.

Retirement Benefits - Narrative (Details) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Mar. 31, 2016	Sep. 30, 2016
Defined Benefit Plan Disclosure [Line Items]
Increase in regulatory assets due valuation received by Exelon for its legacy pension and other postretirement benefit obligations.	$ 27
Increase in regulatory liabilities due to updated valuation of Exelon's legacy pension and postretirement benefit obligations	3
Increase (Decrease) in Pension Plan Obligations	35
Increase (Decrease) in Postretirement Obligations	8
Defined Benefit Plan, Accumulated Other Comprehensive Income Net Gains (Losses), after Tax	$ (2)
PHI Pension and Postretirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase (Decrease) in Pension Plan Obligations		$ 25
Pension Plan, Defined Benefit [Member] \| Exelon Legacy Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		7.00%
Discount rate		4.29%
Pension Plan, Defined Benefit [Member] \| Pepco Holdings LLC [Member] \| PHI Pension and Postretirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		6.50%
Discount rate		3.96%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		6.71%
Discount rate		4.29%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| Pepco Holdings LLC [Member] \| PHI Pension and Postretirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets		6.75%
Discount rate		3.80%

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2016

Mar. 23, 2016

Mar. 22, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Pension Plan, Defined Benefit [Member]

$ 458

$ 476

$ 92

$ 82

262

^[1]

245

215

178

616

^[1]

533

(293)

(257)

(847)

^[1]

(770)

^[1]

142

411

^[1]

427

Other Postretirement Benefit Plan, Defined Benefit [Member]

159

148

452

^[1]

445

^[1]

138

^[1]

125

(42)

(38)

(121)

^[1]

(113)

(48)

(43)

(138)

^[1]

(130)

^[1]

$ 2

^[1]

$ 7

$ 23

Pepco Holdings LLC [Member] | Pension Plan, Defined Benefit [Member] | Predecessor [Member]

$ 58

(30)

(35)

(105)

Pepco Holdings LLC [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member] | Predecessor [Member]

(5)

(6)

(17)

(3)

(9)

$ 1

Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

$ 11

$ 9

[1]	(a)PHI net periodic benefit costs for the period prior to the merger are not included in the table above.

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2016

Mar. 23, 2016

Mar. 22, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Other Pension Plan, Postretirement or Supplemental Plans [Member]

$ 458

$ 476

Corporate, Non-Segment [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

$ 161

$ 159

458

476

Pepco Holdings LLC [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

^[1]

Pepco Holdings LLC [Member] | Corporate, Non-Segment [Member]

$ 58

Pepco Holdings LLC [Member] | Corporate, Non-Segment [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

$ 9

^[1],[2]

Exelon Generation Co L L C [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

163

200

163

200

Commonwealth Edison Co [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

124

155

124

155

PECO Energy Co [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

Baltimore Gas and Electric Company [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

Potomac Electric Power Company [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

^[2]

Delmarva Power and Light Company [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

^[2]

Atlantic City Electric Company [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

$ 3

Predecessor [Member] | Pepco Holdings LLC [Member]

^[2]

$ 4

$ 11

Predecessor [Member] | Pepco Holdings LLC [Member] | Other Pension Plan, Postretirement or Supplemental Plans [Member]

$ 23

Successor [Member] | Pepco Holdings LLC [Member]

$ 23

$ 25

$ 73

$ 58

[1]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO, BGE, PHI, Pepco, DPL or ACE amounts above.
[2]	Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the nine months ended September 30, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016.

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2016

Mar. 23, 2016

Mar. 22, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

$ 51

$ 107

$ 111

$ 7

Business Services Company [Member]

^[1]

^[2]

$ 1

^[2]

^[2]

Predecessor [Member] | Pepco Holdings LLC [Member]

^[2]

Corporate, Non-Segment [Member] | Pepco Holdings LLC [Member]

$ 3

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1],[2]

$ 2

$ 1

$ 2

$ 5

[1]	These amounts primarily represent amounts billed to Exelon and PHI's subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, BGE, Pepco and DPL amounts above.
[2]	Pepco's, DPL's and PHISCO's matching contributions for the nine months ended September 30, 2016 include $1 million, $1 million,and $1 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016, which is not included in Exelon’s matching contributions for the nine months ended September 30, 2016.

Severance - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Severance - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 8	$ (3)	$ 12	$ 18
Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	(2)		44
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	7	$ (3)	10	$ 17
Exelon Generation Co L L C [Member] \| Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	(2)		44
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1		$ 2
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member] \| Facility Closing [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 2

Severance - Ongoing Severance Plans (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 8	$ (3)	$ 12	$ 18
Regulatory Assets	11,432		11,432		$ 6,824
Exelon Generation Co L L C [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	7	(3)	10	$ 17
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	1		2
Commonwealth Edison Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	0	$ 0	1
Regulatory Assets	1,192		1,192		1,113
Commonwealth Edison Co [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
PECO Energy Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Regulatory Assets	1,688		1,688		1,617
Baltimore Gas and Electric Company [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Regulatory Assets	722		722		781
Pepco Holdings LLC [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	1		1
Pepco Holdings LLC [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
Potomac Electric Power Company [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Regulatory Assets	798		798		801
Delmarva Power and Light Company [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Regulatory Assets	359		359		371
Atlantic City Electric Company [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Regulatory Assets	$ 501		$ 501		$ 512

Severance - PHI Merger (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
Severance - PHI Merger (Details) - USD ($) $ in Millions	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 8	$ (3)	$ 12	$ 18
PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			55
Exelon Generation Co L L C [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	7	(3)	10	$ 17
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	1		2
Exelon Generation Co L L C [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			9
Exelon Generation Co L L C [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			8
Commonwealth Edison Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	0	$ 0	1
Commonwealth Edison Co [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
Commonwealth Edison Co [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			2
Commonwealth Edison Co [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			2
PECO Energy Co [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
PECO Energy Co [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
Baltimore Gas and Electric Company [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
Baltimore Gas and Electric Company [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
Pepco Holdings LLC [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 1		1
Pepco Holdings LLC [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			1
Pepco Holdings LLC [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			42
Potomac Electric Power Company [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			20
Potomac Electric Power Company [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			19
Delmarva Power and Light Company [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			12
Delmarva Power and Light Company [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			11
Atlantic City Electric Company [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			10
Atlantic City Electric Company [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs			$ 10

Severance - Severance Liabilities (Details) $ in Millions	9 Months Ended
Severance - Severance Liabilities (Details) $ in Millions	Sep. 30, 2016 USD ($)
Restructuring Reserve [Roll Forward]
Beginning Balance	$ 35
Severance Charges Expense	(136)
Payments for Restructuring	(39)
Ending Balance	132
Exelon Generation Co L L C [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	23
Severance Charges Expense	(63)
Payments for Restructuring	(7)
Ending Balance	79
Commonwealth Edison Co [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	3
Severance Charges Expense	(1)
Payments for Restructuring	(1)
Ending Balance	3
PECO Energy Co [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	0
Payments for Restructuring	0
Ending Balance	0
Baltimore Gas and Electric Company [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	1
Severance Charges Expense	0
Payments for Restructuring	(1)
Ending Balance	0
Pepco Holdings LLC [Member]
Restructuring Reserve [Roll Forward]
Ending Balance	28
Potomac Electric Power Company [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	(1)
Payments for Restructuring	(1)
Ending Balance	0
Delmarva Power and Light Company [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	(1)
Payments for Restructuring	(1)
Ending Balance	0
Atlantic City Electric Company [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	0
Payments for Restructuring	0
Ending Balance	0
Successor [Member] \| Pepco Holdings LLC [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	53
Payments for Restructuring	$ (25)

Severance Severance - Cost Management Program-Related (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2016	Mar. 31, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 8		$ (3)	$ 12	$ 18
Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs		$ 17		18
PECO Energy Co [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				1
PECO Energy Co [Member] \| Corporate, Non-Segment [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				1
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	7		(3)	10	$ 17
Exelon Generation Co L L C [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1			13
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1			2
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				7
Commonwealth Edison Co [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	0		$ 0	1
Commonwealth Edison Co [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				3
Commonwealth Edison Co [Member] \| Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				1
Commonwealth Edison Co [Member] \| Corporate, Non-Segment [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				3
Baltimore Gas and Electric Company [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				1
Baltimore Gas and Electric Company [Member] \| Corporate, Non-Segment [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				1
Pepco Holdings LLC [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 1			1
Pepco Holdings LLC [Member] \| Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs				$ 1

Mezzanine Equity Mezzanine Equity (Details) - USD ($)	9 Months Ended		12 Months Ended
Mezzanine Equity Mezzanine Equity (Details) - USD ($)	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Mar. 23, 2016
Redeemable Noncontrolling Interest [Line Items]
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	$ 26,000,000		$ 28,000,000
Temporary Equity, Other Changes	107,000,000
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Number of preferred shares purchased			18,000
Payments to Acquire Businesses, Gross	6,896,000,000	$ 28,000,000
Preferred Stock [Member]
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Payments to Acquire Businesses, Gross			$ 180,000,000
Exelon Generation Co L L C [Member]
Redeemable Noncontrolling Interest [Line Items]
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	26,000,000		28,000,000
Temporary Equity, Other Changes	(107,000,000)
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	105,000,000
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Payments to Acquire Businesses, Gross	$ 255,000,000	$ 28,000,000
Pepco Holdings LLC [Member]
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Derivative, Fair Value, Net				$ 0
Increase (Decrease) in Derivative Assets			$ 18,000,000

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2015

Dec. 31, 2014

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

$ (2,523)

$ (2,596)

$ (2,523)

$ (2,596)

$ (2,624)

$ (2,684)

^[1]

(5)

(64)

^[1],[2]

106

152

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(23)

(24)

(23)

(24)

(19)

(28)

^[1]

(1)

(18)

^[1],[2]

(3)

Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

(4)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

^[1]

Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(2,463)

(2,539)

(2,463)

(2,539)

(2,565)

(2,640)

(2)

^[1]

(29)

^[1],[2]

104

130

Accumulated Translation Adjustment [Member]

^[1]

102

101

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(32)

^[1]

(36)

^[1]

(32)

^[1]

(36)

^[1]

(40)

^[1]

(19)

^[1]

(17)

(5)

Accumulated Equity Investment [Member]

^[1]

(17)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(8)

(3)

^[1]

(5)

^[1],[2]

AOCI Attributable to Parent [Member]

^[1]

(5)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

101

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(56)

(60)

(56)

(60)

(63)

(36)

^[1]

(30)

^[1],[2]

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(13)

(24)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(24)

^[1]

(25)

^[1]

(24)

^[1]

(25)

^[1]

(21)

(18)

^[1]

(13)

^[1],[2]

(3)

Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

(3)

(7)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

^[1]

Exelon Generation Co L L C [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(32)

^[1]

(36)

^[1]

(32)

^[1]

(36)

^[1]

(40)

^[1]

(19)

^[1]

(17)

Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]

^[1]

(17)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

(2)

(3)

^[1]

^[1],[2]

Exelon Generation Co L L C [Member] | AOCI Attributable to Parent [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(56)

(63)

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

PECO Energy Co [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[1]

PECO Energy Co [Member] | Accumulated Translation Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

PECO Energy Co [Member] | Accumulated Equity Investment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(35)

^[3]

(41)

(35)

^[3]

(41)

(36)

(46)

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(8)

^[3]

(8)

^[3]

(8)

(9)

(1)

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[3]

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

(27)

^[3]

(33)

(27)

^[3]

(33)

(28)

(37)

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Translation Adjustment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

^[3]

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Equity Investment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Accumulated Other Comprehensive Income (Loss), Net of Tax

$ 0

^[3]

$ 0

^[3]

$ 0

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

$ 0

[1]	All amounts are net of tax and noncontrolling interest. Amounts in parenthesis represent a decrease in AOCI.
[2]	See next tables for details about these reclassifications.
[3]	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.

Changes in Accumulated Other Comprehensive Income - Reclassification out of Accumulated Other Comprehensive Income (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

$ 9,002

$ 7,401

$ 23,486

$ 22,746

871

703

1,597

2,767

(340)

(115)

(625)

(805)

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

526

587

956

1,959

562

619

1,052

2,047

Equity in (losses) earnings of unconsolidated affiliates

120

(244)

377

(179)

(15)

(3)

Reclassification out of Accumulated Other Comprehensive Income [Member]

506

243

1,148

724

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(5)

^[1]

^[1]

(5)

(46)

(5)

(152)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

(5)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(4)

(35)

^[1]

(2)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]

^[1]

(3)

(22)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]

^[1]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member]

(11)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[1]

(26)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(57)

(71)

(170)

(213)

^[1]

Prior service benefit reclassified to periodic benefit cost

^[1]

(35)

(43)

(104)

(130)

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

^[1],[2]

(76)

(90)

(227)

(270)

Accumulated Net Unrealized Investment Gain (Loss) [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(106)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

5,035

4,768

13,363

14,841

450

297

865

1,583

(173)

(293)

(371)

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

271

332

556

1,208

275

319

558

1,184

Equity in (losses) earnings of unconsolidated affiliates

185

(257)

395

(193)

(16)

(4)

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

243

236

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(5)

^[1]

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

^[1]

(5)

(3)

(5)

(6)

^[1]

(5)

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

(5)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(4)

(9)

^[1]

(2)

^[1]

(3)

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]

^[1]

(3)

(6)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

Exelon Generation Co L L C [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

(11)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

PEPCO Holdings Inc [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[1]

(2)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

PEPCO Holdings Inc [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]

(1)

(5)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

(1)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

(1)

PEPCO Holdings Inc [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

(1)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

(2)

(1)

(7)

(2)

Prior service benefit reclassified to periodic benefit cost

(1)

(4)

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

(2)

(1)

(7)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

635

592

1,695

1,641

114

190

(35)

(32)

(34)

(62)

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

128

128

Equity in (losses) earnings of unconsolidated affiliates

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

331

314

974

1,004

(19)

(9)

(18)

(34)

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

(16)

(16)

Equity in (losses) earnings of unconsolidated affiliates

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

421

386

982

1,003

(58)

(23)

(14)

(23)

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

(50)

(50)

Equity in (losses) earnings of unconsolidated affiliates

Interest Expense [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

$ 15

$ 47

$ 48

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Interest Expense [Member] | Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(4)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

$ (4)

[1]	Amounts in parenthesis represent a decrease in net income.
[2]	This AOCI component is included in the computation of net periodic pension and OPEB cost (see Note 13 — Retirement Benefits for additional details).

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended			9 Months Ended
	Sep. 30, 2016	Mar. 23, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$ 7		$ 8	$ 22	$ 22
Actuarial loss reclassified to periodic cost	(29)		(35)	(88)	(105)
Pension and non-pension postretirement benefit plans valuation adjustment	1		0	1	17
Change in unrealized gain/(loss) on cash flow hedges	(1)		3	3	(3)
Change in unrealized loss on equity investments	0		0	3	0
Change in unrealized gain on marketable securities	(1)		0	(1)	0
Total	(23)		(24)	(60)	(69)
PEPCO Holdings Inc [Member]
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	2	$ 0			3
Exelon Generation Co L L C [Member]
Pension and non-pension postretirement benefit plans:
Change in unrealized gain/(loss) on cash flow hedges	(2)		3	1	4
Change in unrealized loss on equity investments	0		0	3	0
Change in unrealized gain on marketable securities	0		0	0	0
Total	$ (2)		$ 3	$ 4	$ 4

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 490	$ 629	$ 930	$ 1,959
Weighted average common shares outstanding — basic	925	913	924	879
Assumed exercise and/or distributions of stock-based awards	2	2	2	4
Weighted average common shares outstanding — diluted	927	915	926	883

Earnings Per Share and Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions			3 Months Ended		9 Months Ended
	Sep. 18, 2016	Jul. 03, 2016	Sep. 30, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2015	Dec. 31, 2015	Oct. 01, 2015
Statement Of Equity Line Item [Line Items]
Treasury Stock, Shares held			35,000,000		35,000,000
Treasury Stock, Value			$ (2,327)		$ (2,327)		$ (2,327)
Preferred Stock, Value, Issued			$ 0		$ 0		193
Stock Redeemed or Called During Period, Shares	500,000	400,000	600,000		400,000
Preferred Stock, Dividend Rate, Percentage	6.97%	7.125%	6.99%		6.70%
Equity units issued [Member]
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding			1,000,000	4,000,000	1,000,000	2,000,000
Employee Stock Option [Member]
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding			11,000,000	14,000,000	12,000,000	14,000,000
Baltimore Gas and Electric Company [Member]
Statement Of Equity Line Item [Line Items]
Preferred Stock, Redemption Price Per Share			$ 100		$ 100
Preferred Stock, Value, Issued			$ 0		$ 0		$ 190	$ 190
Stock Redeemed or Called During Period, Value	$ 90	$ 100

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) - Exelon Generation Co L L C [Member] $ in Millions	Sep. 30, 2016 USD ($)
Equity Unit Purchase Agreements [Member]
Guarantor Obligations [Line Items]
Other Unrecorded Amounts	$ 20
Unrecorded Unconditional Purchase Obligation, Due in Next Twelve Months	79
2015	25
2016	4
Total	108
Noncontrolling Interest [Member]
Guarantor Obligations [Line Items]
Other Unrecorded Amounts	$ 31

Commitments and Contingencies - Commitments Narrative (Details)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

USD ($)

Sep. 30, 2016

USD ($)

Jun. 30, 2013

USD ($)

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 50

^[1],[2]

$ 508

Power Volume | MW

220

Costs Incurred, Development Costs

^[2]

$ 3

404

Minimum [Member] | Exelon Generation Co L L C [Member]

Business Acquisition, Development Of New Generation Cost

450

$ 450

Business Acquisition, Expected New Generation Mwh | MW

275

Maximum [Member] | Exelon Generation Co L L C [Member]

Business Acquisition, Development Of New Generation Cost

550

$ 550

Business Acquisition, Expected New Generation Mwh | MW

300

Equity Unit Purchase Agreements [Member] | Exelon Generation Co L L C [Member]

$ 105

Merger Commitment [Member]

2015

$ 25

Merger Commitment [Member] | Minimum [Member]

$ 1,000

Merger Commitment [Member] | Maximum [Member]

Supplemental Income Statement Information [Line Items]

$ 0

[1]	(e)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.
[2]	See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.

Commitments and Contingencies - Contingencies Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2016	Sep. 30, 2015
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear Insurance Financial Protection Pool Surcharge On Nuclear Incident Assessment	12730000000.00%
Guarantor Obligations, Maximum Exposure, Undiscounted	$ 50
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Loss Contingency Accrual	44
Required nuclear liability insurance per site	0
Nuclear financial protection pool value	400
Current Liability Per Incident	13,400
Maximum liability per nuclear incident		$ 13,000
Potomac Electric Power Company [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	13
Nuclear Insurance Premiums [Member] \| Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear financial protection pool value	2,700
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	19
Maximum liability per nuclear incident	$ 0

Commitments and Contingencies - Environmental Issues Narrative (Details) $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended
	Aug. 31, 2015 gal	Oct. 31, 2007 USD ($)	Sep. 30, 2016 USD ($) MGPSite gal	Sep. 30, 2016 USD ($) Defendant MGPSite Open_claim gal
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Claims Dismissed, Number \| Defendant				30
Commonwealth Edison Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites \| MGPSite			17	17
Approved clean-up \| MGPSite			42	42
Other Increase (Decrease) in Environmental Liabilities			$ 7
PECO Energy Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites \| MGPSite			16	16
Approved clean-up \| MGPSite			26	26
Other Increase (Decrease) in Environmental Liabilities			$ 2
Baltimore Gas and Electric Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Approved clean-up \| MGPSite			13	13
Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, New Claims Filed, Number \| Open_claim				63
Site Contingency, Loss Exposure Not Accrued, Best Estimate			$ 90
Consent decree penalty		$ 1
Environmental loss contingencies			$ 13	$ 13
PEPCO Holdings Inc [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Sites under study/remediation \| MGPSite			9	9
Environmental Remediation Expense				$ 10
PEPCO Holdings Inc [Member] \| Minimum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			$ 7	7
PEPCO Holdings Inc [Member] \| Maximum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			$ 18	18
Potomac Electric Power Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
QuantityOfMineralOilSPill \| gal	6,100
Potomac Electric Power Company [Member] \| Minimum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost				3
Potomac Electric Power Company [Member] \| Maximum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost				$ 6
Delmarva Power and Light Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites \| gal			2	2
Calpine Corporation [Member] \| Maximum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			$ 10	$ 10
Sixty-Eighth Street Dump [Member] \| Baltimore Gas and Electric Company [Member] \| Minimum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			50	50
Sixty-Eighth Street Dump [Member] \| Baltimore Gas and Electric Company [Member] \| Maximum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			64	64
Rossville Ash Site [Member] \| Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			6	6
Sauer Dump Site [Member] \| Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss			$ 2	$ 2

Commitments and Contingencies - Litigation and Regulatory Matters (Details) $ in Millions	3 Months Ended
	Sep. 30, 2016 USD ($) claimant Open_claim	Dec. 31, 2015 USD ($)
Exelon Generation Co L L C [Member]
Asbestos Loss Contingency [Abstract]
Asbestos liability reserve	$ 22	$ 0
Asbestos liability reserve related to open claims	$ 0
Open asbestos liability claims \| Open_claim	61,000,000
Asbestos liability reserve related to anticipated claims	$ 95
Telephone Consumer Protection Act Lawsuit [Abstract]
Loss Contingency Accrual	44
Loss Contingency, Damages Sought, Value	$ 14
Baltimore Gas and Electric Company [Member]
Asbestos Loss Contingency [Abstract]
Number of claimants \| claimant	83,000,000

Supplemental Financial Information - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2016	Dec. 31, 2015
Supplemental Financial Information Tables [Line Items]
Debt Instrument, Face Amount	$ 750
Gain (Loss) on Sale of Derivatives	26
PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net		$ 16	$ 15
Financing Receivable, Allowance for Credit Losses		14	$ 15
Low To Medium Risk [Member] \| PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	1	0
Risk Level, Medium [Member] \| PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	3	3
Risk Level, High [Member] \| PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	$ 11	$ 11

Supplemental Financial Information - Operations (Detail) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2016

Mar. 23, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

$ 255

$ 151

$ 624

$ 430

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

181

203

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

122

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

155

(301)

286

(385)

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

116

(218)

216

(274)

Net unrealized income (losses) on pledged assets

(5)

(2)

Regulatory offset to decommissioning trust fund-related activities

(168)

207

^[2]

(380)

129

^[2]

Total decommissioning-related activities

190

(255)

396

(196)

Income Tax Examination, Penalties and Interest Expense

106

Unrecognized Tax Benefits, Income Tax Penalties Expense

^[3]

(26)

(90)

Gains (Losses) on Extinguishment of Debt

(3)

(3)

120

(244)

377

(179)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

181

203

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

122

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

155

(301)

286

(385)

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

116

(218)

216

(274)

Net unrealized income (losses) on pledged assets

(5)

(2)

Regulatory offset to decommissioning trust fund-related activities

(168)

207

^[2]

(380)

129

^[2]

Total decommissioning-related activities

190

(255)

396

(196)

Gains (Losses) on Extinguishment of Debt

(2)

(6)

(3)

(5)

185

(257)

395

(193)

Supplemental Income Statement Information [Line Items]

186

180

Income Tax Examination, Penalties and Interest Expense

(80)

(72)

Supplemental Income Statement Information [Line Items]

106

104

(1)

Supplemental Income Statement Information [Line Items]

^[4]

(1)

Supplemental Income Statement Information [Line Items]

240

239

Supplemental Income Statement Information [Line Items]

$ 176

$ 31

Supplemental Income Statement Information [Line Items]

$ 78

253

(11)

$ (4)

Supplemental Income Statement Information [Line Items]

Supplemental Income Statement Information [Line Items]

Depreciation, Amortization and Accretion [Abstract]

$ 2

$ 1

$ 8

$ 4

[1]	Includes investment income and realized gains and losses on sales of investments of the trust funds.
[2]	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 16 — Asset Retirement Obligations of the Exelon 2015 Form 10-K 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 were probable not to occur. As a result, $26 million of anticipated payments were reclassified from AOCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
[4]	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters of the Exelon 2015 Form 10-K for additional information regarding the rate stabilization deferral.

Supplemental Financial Information - Cash Flow (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Jun. 30, 2016

Mar. 23, 2016

Mar. 22, 2016

Sep. 30, 2016

Sep. 30, 2015

Mar. 24, 2016

Dec. 31, 2015

^[1]

$ 2,490

$ 1,648

^[1]

293

131

Amortization of energy contract assets and liabilities

^[1]

^[2]

(7)

(20)

^[3]

862

841

4,009

2,930

458

476

107

114

102

^[4]

(237)

(31)

Amortization of regulatory asset related to debt costs

^[5]

(20)

(9)

(34)

^[6]

(36)

101

^[7],[8]

508

Restructuring Costs

130

(18)

Changes In Other Assets and Liabilities [Abstract]

1,224

856

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(537)

(322)

6,896

(338)

(59)

$ 476

476

$ 811

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

^[9]

333

291

Capital Project [Member]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Nuclear Fuel Project [Member]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

1,297

739

Amortization of energy contract assets and liabilities

^[1]

^[2]

(7)

(19)

^[3]

862

841

2,516

1,887

163

200

^[4]

(237)

(31)

Amortization of regulatory asset related to debt costs

^[5]

(20)

(9)

^[8]

Restructuring Costs

(5)

Changes In Other Assets and Liabilities [Abstract]

129

227

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(204)

(245)

^[8]

119

255

(289)

(48)

476

811

Exelon Generation Co L L C [Member] | Capital Project [Member]

^[9]

332

291

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Exelon Generation Co L L C [Member] | Nuclear Fuel Project [Member]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

^[1]

524

471

^[1]

574

528

124

155

Amortization of regulatory asset related to debt costs

^[6]

(36)

101

(3)

(1)

Changes In Other Assets and Liabilities [Abstract]

122

312

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

104

(42)

(62)

Commonwealth Edison Co [Member] | Indemnification Agreement [Member]

^[9]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Contribution of Property

^[10]

157

Depreciation, Amortization and Accretion [Abstract]

^[1]

181

179

^[1]

201

198

Amortization of regulatory asset related to debt costs

(3)

Changes In Other Assets and Liabilities [Abstract]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(49)

(16)

(4)

Depreciation, Amortization and Accretion [Abstract]

^[1]

223

216

^[1]

307

271

Amortization of regulatory asset related to debt costs

Changes In Other Assets and Liabilities [Abstract]

109

111

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(2)

(28)

(14)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Depreciation, Amortization and Accretion [Abstract]

^[1]

128

122

^[1]

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

221

191

$ 7

Amortization of regulatory asset related to debt costs

^[8]

125

(2)

Changes In Other Assets and Liabilities [Abstract]

168

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(83)

(94)

Potomac Electric Power Company [Member] | Successor [Member]

^[9]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

Amortization of energy contract assets and liabilities

^[1]

^[2]

Asset retirement obligation accretion

^[3]

120

113

Amortization of regulatory asset related to debt costs

^[8]

(8)

Changes In Other Assets and Liabilities [Abstract]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(70)

(22)

(10)

(2)

^[9]

(5)

Depreciation, Amortization and Accretion [Abstract]

^[1]

^[1]

Amortization of energy contract assets and liabilities

^[1]

^[2]

Asset retirement obligation accretion

^[3]

130

135

$ 3

Amortization of regulatory asset related to debt costs

^[8]

110

(5)

Changes In Other Assets and Liabilities [Abstract]

138

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(87)

$ 0

^[9]

(2)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

$ 0

Depreciation, Amortization and Accretion [Abstract]

^[1]

292

^[1]

182

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

152

474

Amortization of regulatory asset related to debt costs

(3)

Changes In Other Assets and Liabilities [Abstract]

143

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(9)

(112)

^[9]

$ 0

Depreciation, Amortization and Accretion [Abstract]

^[1]

215

^[1]

140

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

355

Amortization of regulatory asset related to debt costs

^[8]

308

Restructuring Costs

(53)

(7)

Changes In Other Assets and Liabilities [Abstract]

441

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(248)

Business Combination, Contingent Consideration, Liability, Noncurrent

129

$ 53

(5)

^[9]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Deferred Compensation, Share-based Payments [Member] | Pepco Holdings LLC [Member]

$ 33

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Deferred Compensation, Share-based Payments [Member] | Pepco Holdings LLC [Member] | Successor [Member]

$ 29

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

$ 29

[1]	(a)Included in Depreciation and amortization on the Registrants' Consolidated Statements of Operations and Comprehensive Income.
[2]	(b)Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[3]	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[4]	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 of the Exelon 2015 Form 10-K for additional information regarding the accounting for nuclear decommissioning
[5]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded
[6]	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information
[7]	(e)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.
[8]	See Note 4 — Mergers, Acquisitions and Dispositions for additional information related to the merger with PHI.
[9]	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[10]	See Note 11— Income Taxes for discussion of the like-kind exchange tax position

Supplemental Financial Information - Balance Sheet (Details) - USD ($)
$ in Millions

Sep. 30, 2016

Dec. 31, 2015

$ 18,354

^[1]

$ 16,375

^[2]

330

284

10,004

^[1]

8,639

^[2]

Exelon Generation Co L L C [Member] | Nuclear Fuel [Member]

3,198

2,861

3,841

3,710

3,213

3,101

3,198

3,016

5,341

146

3,026

2,929

1,171

1,139

1,008

968

$ 17

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $3,198 million
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million

Supplemental Financial Information Supplemental Financial Information - Utility Taxes (Details) - USD ($) $ in Millions	3 Months Ended			6 Months Ended	9 Months Ended
	Sep. 30, 2016	Mar. 23, 2016	Sep. 30, 2015	Sep. 30, 2016	Sep. 30, 2016	Sep. 30, 2015
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	$ 255		$ 151		$ 624	$ 430
Exelon Generation Co L L C [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	35		28		90	79
Commonwealth Edison Co [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	67		63		186	180
PECO Energy Co [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	40		37		106	104
Baltimore Gas and Electric Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	21		23		66	67
Pepco Holdings LLC [Member] \| Predecessor [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes		$ 78	86			253
Pepco Holdings LLC [Member] \| Successor [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	92			$ 176
Potomac Electric Power Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	87		82		240	239
Delmarva Power and Light Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	5		4		14	14
Atlantic City Electric Company [Member]
Supplemental Income Statement Information [Line Items]
Utilities Operating Expense, Taxes	$ 0		$ 0		$ 0	$ 0

Segment Information - Narrative (Details)	9 Months Ended
Segment Information - Narrative (Details)	Sep. 30, 2016 Reportable_segment
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	6

Segment Information - Reconciliation to Consolidated Financial Statements (Details) - USD ($)
$ in Millions

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2016

Jun. 30, 2016

Mar. 23, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Dec. 31, 2015

$ 9,002

$ 7,401

$ 23,486

$ 22,746

3,823

4,095

10,559

11,796

4,330

2,721

10,461

7,564

386

122

169

581

326

347

1,515

1,901

526

587

956

1,959

114,535

$ 114,535

114,535

$ 95,384

137

116

781

904

Corporate, Non-Segment [Member]

(125)

(36)

(340)

(96)

9,883

15,389

Intersegment Eliminations [Member]

362

348

1,166

1,007

(499)

(204)

(1,118)

(564)

(8)

(1)

(24)

(3)

(1)

(2)

(885)

(555)

(1)

(2)

(3)

(11,897)

(11,728)

(5)

(3)

(10)

(12)

Intersegment Eliminations [Member] | Successor [Member]

(373)

(348)

(1,199)

(1,007)

(4)

(9)

(4)

(9)

(4,743)

Intersegment Eliminations [Member] | Predecessor [Member]

$ (4)

(4)

(3)

(10)

(5,238)

Exelon Generation Co L L C [Member] | Operating Segments [Member]

4,322

4,299

11,677

12,360

387

122

171

580

326

347

1,515

1,901

271

332

556

1,208

47,568

46,529

Exelon Generation Co L L C [Member] | Intersegment Eliminations [Member]

Generation Midwest [Member]

500

205

1,121

567

Generation Midwest [Member] | Operating Segments [Member]

1,164

1,151

3,343

3,633

Generation Midwest [Member] | Intersegment Eliminations [Member]

1,163

^[1]

1,152

^[1]

3,330

^[2]

3,634

^[2]

Commonwealth Edison Co [Member] | Operating Segments [Member]

(1)

1,497

1,376

4,031

3,709

149

297

339

28,020

26,532

Commonwealth Edison Co [Member] | Intersegment Eliminations [Member]

PECO Energy Co [Member] | Operating Segments [Member]

740

691

1,971

1,950

122

346

299

11,041

10,367

322

436

PECO Energy Co [Member] | Intersegment Eliminations [Member]

Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

735

655

1,998

1,908

191

212

8,857

8,295

423

480

Baltimore Gas and Electric Company [Member] | Intersegment Eliminations [Member]

Corporate and Other [Member] | Intersegment Eliminations [Member]

1,166

1,003

1,366

2,485

166

(91)

1,096

1,317

3,680

129

Pepco Holdings LLC [Member] | Corporate, Non-Segment [Member] | Successor [Member]

(15)

(16)

11,057

Pepco Holdings LLC [Member] | Corporate, Non-Segment [Member] | Predecessor [Member]

161

(44)

(6)

(23)

7,162

Pepco Holdings LLC [Member] | Operating Segments [Member] | Successor [Member]

1,366

2,485

166

(91)

21,063

Pepco Holdings LLC [Member] | Operating Segments [Member] | Predecessor [Member]

197

Pepco Holdings LLC [Member] | Intersegment Eliminations [Member] | Successor [Member]

16,188

Corporate, Non-Segment [Member] | Intersegment Eliminations [Member]

Segment Elimination [Member] | Intersegment Eliminations [Member]

362

347

Generation Total Consolidated Group [Member]

(2,351)

(1,581)

Generation Total Consolidated Group [Member] | Operating Segments [Member]

5,035

4,768

13,363

14,841

Generation Total Consolidated Group [Member] | Intersegment Eliminations [Member]

5,035

^[1]

4,768

^[1]

13,363

^[2]

14,841

^[2]

Potomac Electric Power Company [Member] | Operating Segments [Member] | Successor [Member]

635

$ 1,184

(12)

7,219

Potomac Electric Power Company [Member] | Operating Segments [Member] | Predecessor [Member]

511

592

1,641

128

6,908

Delmarva Power and Light Company [Member] | Operating Segments [Member] | Successor [Member]

314

593

(42)

4,023

Delmarva Power and Light Company [Member] | Operating Segments [Member] | Predecessor [Member]

279

295

875

3,969

129

Atlantic City Electric Company [Member] | Operating Segments [Member] | Successor [Member]

421

714

(55)

3,507

$ 3,507

3,507

Atlantic City Electric Company [Member] | Operating Segments [Member] | Predecessor [Member]

$ 0

268

386

1,003

$ 3,387

PECO Energy Co Affiliate [Member] | Operating Segments [Member]

$ 0

PECO Energy Co Affiliate [Member] | Generation Midwest [Member] | Operating Segments [Member]

234

173

Baltimore Gas And Electric Company Affiliate [Member] | Generation Midwest [Member] | Operating Segments [Member]

Commonwealth Edison Co Affiliate [Member] | Generation Midwest [Member] | Operating Segments [Member]

183

141

489

376

PotomacElectricPowerCompanyAffiliate [Member] | Generation Midwest [Member] | Operating Segments [Member]

$ 2

$ 38

$ 17

PotomacElectricPowerCompanyAffiliate [Member] | Generation Midwest [Member] | Operating Segments [Member] | Successor [Member]

128

DelmarvaPowerandLightCompanyAffiliate [Member] | Generation Midwest [Member] | Operating Segments [Member]

223

DelmarvaPowerandLightCompanyAffiliate [Member] | Generation Midwest [Member] | Operating Segments [Member] | Successor [Member]

AtlanticCityElectricCompanyAffiliate [Member] | Generation Midwest [Member] | Operating Segments [Member]

109

AtlanticCityElectricCompanyAffiliate [Member] | Generation Midwest [Member] | Operating Segments [Member] | Successor [Member]

$ 28

[1]

Three Months Ended September 30, 2016 Three Months Ended September 30, 2015 Revenuesfrom externalcustomers(a)IntersegmentrevenuesTotalRevenuesRevenuesfrom externalcustomers(a)(c)Intersegmentrevenues(c)TotalRevenues(c)Mid-Atlantic$1,813 $(13) $1,800 $1,640 $(8) $1,632Midwest1,163 1 1,164 1,152 (1) 1,151New England455 (4) 451 520 — 520New York331 (8) 323 254 (4) 250ERCOT289 6 295 317 (1) 316Other Power Regions271 (33) 238 416 (40) 376Total Revenues for Reportable Segments4,322 (51) 4,271 4,299 (54) 4,245Other(b)713 51 764 469 54 523Total Generation Consolidated Operating Revenues$5,035 $— $5,035 $4,768 $— $4,768

[2]

{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk5ZDczZmJiZmVlMzQwYjliY2U1YWJiOTI2MjM3MWNhfFRleHRTZWxlY3Rpb246NDNBNkVDOEMwNDMyNUYwOEEwRjQ1MDc1RjM2NzgxOTMM}

Segment Information - Generation Total Revenues (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Jun. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

$ (9,002)

$ (7,401)

$ (23,486)

$ (22,746)

(1)

(2)

526

587

956

1,959

Generation Mid Atlantic [Member]

$ (3)

Generation New England [Member]

(1,800)

(1,632)

(4,736)

(4,491)

Generation New York [Member]

(451)

(520)

(1,272)

(1,746)

Generation ERCOT [Member]

(323)

(250)

(873)

(778)

Generation Other Regions [Member]

(295)

(316)

(665)

(687)

Generation Reportable Segments Total [Member]

(238)

(376)

(686)

(880)

Generation Reportable Segments Total [Member] | Scenario, Adjustment [Member]

(4,271)

(4,245)

(11,575)

(12,215)

(54)

(144)

Generation All Other Segments [Member]

(54)

(144)

Amortization of intangible assets related to commodity contracts

(764)

(523)

(1,788)

(2,626)

(21)

(3)

(10)

Derivative, Gain on Derivative

(187)

171

Generation All Other Segments [Member] | Scenario, Adjustment [Member]

(7)

(366)

(54)

144

Generation Total Consolidated Group [Member]

(54)

(144)

Operating Segments [Member] | Generation Mid Atlantic [Member]

(5,035)

(4,768)

(13,363)

(14,841)

Operating Segments [Member] | Generation New England [Member]

(1,813)

^[1]

(1,640)

^[1]

(4,776)

^[2],[3]

(4,560)

^[2],[3]

Operating Segments [Member] | Generation New York [Member]

(455)

^[1]

(520)

^[1]

(1,278)

^[3]

(1,752)

^[3]

Operating Segments [Member] | Generation ERCOT [Member]

(331)

^[1]

(254)

^[1]

(906)

^[2],[3]

(783)

^[2],[3]

Operating Segments [Member] | Generation Other Regions [Member]

(289)

^[1]

(317)

^[1]

(659)

^[3]

(691)

^[3]

Operating Segments [Member] | Generation Reportable Segments Total [Member]

(271)

^[1],[4]

(416)

^[1],[4]

(728)

^[3],[5]

(940)

^[3],[5]

Operating Segments [Member] | Generation Total Consolidated Group [Member]

(4,322)

^[1]

(4,299)

^[1]

(11,677)

^[3]

(12,360)

^[3]

Operating Segments [Member] | Exelon Generation Co L L C [Member]

(5,035)

^[1]

(4,768)

^[1]

(13,363)

^[3]

(14,841)

^[3]

Corporate, Non-Segment [Member]

271

332

556

1,208

Corporate, Non-Segment [Member] | Generation All Other Segments [Member]

(125)

(36)

(340)

(96)

Intersegment Eliminations [Member]

(713)

^[1],[6]

(469)

^[1],[6]

(1,686)

^[3],[7]

(2,481)

^[3],[7]

885

555

(3)

Intersegment Eliminations [Member] | Corporate and Other [Member]

(1)

(2)

(3)

Intersegment Eliminations [Member] | Segment Elimination [Member]

(1,166)

(1,003)

Intersegment Eliminations [Member] | Generation Mid Atlantic [Member]

2,351

1,581

Intersegment Eliminations [Member] | Generation New England [Member]

^[2]

Intersegment Eliminations [Member] | Generation New York [Member]

Intersegment Eliminations [Member] | Generation ERCOT [Member]

^[2]

Intersegment Eliminations [Member] | Generation Other Regions [Member]

(6)

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

^[4]

^[5]

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

102

145

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]

(51)

^[6]

(54)

^[6]

(102)

^[7]

(145)

^[7]

Intersegment Eliminations [Member] | Exelon Generation Co L L C [Member]

$ (500)

$ (205)

$ (1,121)

$ (567)

[1]	Three Months Ended September 30, 2016 Three Months Ended September 30, 2015 Revenuesfrom externalcustomers(a)IntersegmentrevenuesTotalRevenuesRevenuesfrom externalcustomers(a)(c)Intersegmentrevenues(c)TotalRevenues(c)Mid-Atlantic$1,813 $(13) $1,800 $1,640 $(8) $1,632Midwest1,163 1 1,164 1,152 (1) 1,151New England455 (4) 451 520 — 520New York331 (8) 323 254 (4) 250ERCOT289 6 295 317 (1) 316Other Power Regions271 (33) 238 416 (40) 376Total Revenues for Reportable Segments4,322 (51) 4,271 4,299 (54) 4,245Other(b)713 51 764 469 54 523Total Generation Consolidated Operating Revenues$5,035 $— $5,035 $4,768 $— $4,768
[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk5ZDczZmJiZmVlMzQwYjliY2U1YWJiOTI2MjM3MWNhfFRleHRTZWxlY3Rpb246MTdGRTY4QTU5RDRENTQxRUI0NzhEODYyMUI4Q0UwRDQM}
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk5ZDczZmJiZmVlMzQwYjliY2U1YWJiOTI2MjM3MWNhfFRleHRTZWxlY3Rpb246NDNBNkVDOEMwNDMyNUYwOEEwRjQ1MDc1RjM2NzgxOTMM}
[4]	Three Months Ended September 30, 2016 Three Months Ended September 30, 2015 Revenuesfrom externalcustomers(a)IntersegmentrevenuesTotalRevenuesRevenuesfrom externalcustomers(a)(c)Intersegmentrevenues(c)TotalRevenues(c)Mid-Atlantic$1,813 $(13) $1,800 $1,640 $(8) $1,632Midwest1,163 1 1,164 1,152 (1) 1,151New England455 (4) 451 520 — 520New York331 (8) 323 254 (4) 250ERCOT289 6 295 317 (1) 316Other Power Regions271 (33) 238 416 (40) 376Total Revenues for Reportable Segments4,322 (51) 4,271 4,299 (54) 4,245Other(b)713 51 764 469 54 523Total Generation Consolidated Operating Revenues$5,035 $— $5,035 $4,768 $— $4,768
[5]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk5ZDczZmJiZmVlMzQwYjliY2U1YWJiOTI2MjM3MWNhfFRleHRTZWxlY3Rpb246NUY3NkI2RTJCMDAyNTZBQUJFNUZBOTU5MTExODhGMDgM}
[6]	Three Months Ended September 30, 2016 Three Months Ended September 30, 2015 Revenuesfrom externalcustomers(a)IntersegmentrevenuesTotalRevenuesRevenuesfrom externalcustomers(a)(c)Intersegmentrevenues(c)TotalRevenues(c)Mid-Atlantic$1,813 $(13) $1,800 $1,640 $(8) $1,632Midwest1,163 1 1,164 1,152 (1) 1,151New England455 (4) 451 520 — 520New York331 (8) 323 254 (4) 250ERCOT289 6 295 317 (1) 316Other Power Regions271 (33) 238 416 (40) 376Total Revenues for Reportable Segments4,322 (51) 4,271 4,299 (54) 4,245Other(b)713 51 764 469 54 523Total Generation Consolidated Operating Revenues$5,035 $— $5,035 $4,768 $— $4,768
[7]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjk5ZDczZmJiZmVlMzQwYjliY2U1YWJiOTI2MjM3MWNhfFRleHRTZWxlY3Rpb246QjRCNEYyM0QzNjhCNTEwRTlDNjBCQ0NFMEYxMzZERTAM}

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($)
$ in Millions

3 Months Ended

9 Months Ended

Sep. 30, 2016

Sep. 30, 2015

Sep. 30, 2016

Sep. 30, 2015

Unrealized Gain (Loss) on Derivatives

$ 9,002

$ 7,401

$ 23,486

$ 22,746

(100)

363

Generation Total Consolidated Group [Member]

^[1]

862

841

Segment Reporting Information Revenue Net of Purchase Power And Fuel

2,446

2,249

6,754

7,041

Generation Mid Atlantic [Member]

5,035

4,768

13,363

14,841

Segment Reporting Information Revenue Net of Purchase Power And Fuel

887

997

2,556

2,677

Generation Midwest [Member]

1,800

1,632

4,736

4,491

Segment Reporting Information Revenue Net of Purchase Power And Fuel

781

756

2,229

2,205

Generation New England [Member]

1,164

1,151

3,343

3,633

Segment Reporting Information Revenue Net of Purchase Power And Fuel

160

133

350

379

Generation New York [Member]

451

520

1,272

1,746

Segment Reporting Information Revenue Net of Purchase Power And Fuel

194

170

592

502

Generation ERCOT [Member]

323

250

873

778

Segment Reporting Information Revenue Net of Purchase Power And Fuel

111

231

235

Generation Other Regions [Member]

295

316

665

687

Segment Reporting Information Revenue Net of Purchase Power And Fuel

253

193

238

376

686

880

Other Segments [Member]

Segment Reporting Information Revenue Net of Purchase Power And Fuel

(1)

Other Segments [Member] | Scenario, Adjustment [Member]

Segment Reporting Information Revenue Net of Purchase Power And Fuel

(6)

Generation All Other Segments [Member]

Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel

(22)

(4)

(15)

Segment Reporting Information Revenue Net of Purchase Power And Fuel

254

543

850

Derivative, Gain on Derivative

764

523

1,788

2,626

(187)

171

Unrealized Gain (Loss) on Derivatives

139

(113)

258

Generation All Other Segments [Member] | Scenario, Adjustment [Member]

(28)

(38)

Segment Reporting Information Revenue Net of Purchase Power And Fuel

(12)

(22)

Generation Reportable Segments Total [Member]

(144)

Segment Reporting Information Revenue Net of Purchase Power And Fuel

2,192

2,250

6,211

6,191

Generation Reportable Segments Total [Member] | Scenario, Adjustment [Member]

4,271

4,245

11,575

12,215

Segment Reporting Information Revenue Net of Purchase Power And Fuel

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]

144

Intersegment Eliminations [Member] | Generation Mid Atlantic [Member]

(2)

Intersegment Eliminations [Member] | Generation Midwest [Member]

(13)

(8)

(40)

^[2]

(69)

^[2]

(1)

(4)

(15)

Intersegment Eliminations [Member] | Generation New England [Member]

(1)

(10)

(15)

(23)

(46)

Intersegment Eliminations [Member] | Generation New York [Member]

(4)

(6)

(1)

(15)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

(8)

(4)

(33)

^[2]

(5)

^[2]

(51)

(55)

(104)

(109)

Intersegment Eliminations [Member] | Generation Other Regions [Member]

(1)

(4)

(66)

(71)

(104)

(148)

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

(33)

^[3]

(40)

^[3]

(42)

^[4]

(60)

^[4]

123

114

227

280

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

^[5]

102

^[6]

145

^[6]

(123)

(114)

(227)

(280)

Operating Segments [Member] | Generation Total Consolidated Group [Member]

(51)

(54)

(102)

(145)

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

2,446

2,249

6,754

7,041

Operating Segments [Member] | Generation Mid Atlantic [Member]

5,035

^[7]

4,768

^[7]

13,363

^[8]

14,841

^[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

881

979

2,541

2,679

Operating Segments [Member] | Generation Midwest [Member]

1,813

^[7]

1,640

^[7]

4,776

^[2],[8]

4,560

^[2],[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

782

760

2,225

2,220

Operating Segments [Member] | Generation New England [Member]

1,163

^[7]

1,152

^[7]

3,330

^[8]

3,634

^[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

170

148

373

425

Operating Segments [Member] | Generation New York [Member]

455

^[7]

520

^[7]

1,278

^[8]

1,752

^[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

195

157

607

462

Operating Segments [Member] | Generation ERCOT [Member]

331

^[7]

254

^[7]

906

^[2],[8]

783

^[2],[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

144

166

335

344

Operating Segments [Member] | Generation Other Regions [Member]

289

^[7]

317

^[7]

659

^[8]

691

^[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

143

154

357

341

Operating Segments [Member] | Generation All Other Segments [Member]

271

^[3],[7]

416

^[3],[7]

728

^[4],[8]

940

^[4],[8]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

131

(115)

316

570

Operating Segments [Member] | Generation Reportable Segments Total [Member]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

2,315

2,364

6,438

6,471