View Filing Data

Electrical Generation Revenue

$ 4,473

$ 5,632

Regulated Operating Revenue

444

624

3,100

3,198

2,657

2,574

7,573

8,830

Purchased power

2,440

3,426

814

1,044

2,835

2,081

685

610

325

304

Equity in (losses) earnings of unconsolidated affiliates

7,099

7,465

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

483

1,366

(277)

(335)

(10)

(114)

(80)

(173)

(265)

310

1,101

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

184

363

(3)

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

123

738

(50)

Net income attributable to common shareholders

173

693

Pension and non-pension postretirement benefit plans:

Prior service benefit reclassified to periodic benefit cost

(12)

(11)

Actuarial loss reclassified to periodic benefit cost

Pension and non-pension postretirement benefit plan valuation adjustment

(1)

(26)

Unrealized (loss) gain on cash flow hedges

(7)

Unrealized loss on equity investments

(3)

Unrealized loss on marketable securities

(1)

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

(12)

^[1]

Average shares of common stock outstanding:

$ 151

$ 749

Weighted average common shares outstanding — basic

923

862

Average common shares outstanding — diluted

925

867

Earnings per average common share:

Earnings per share - basic (in usd per share)

$ 0.19

$ 0.80

Earnings per average common share - diluted

Earnings per share - diluted (in usd per share)

0.19

0.80

Dividends per common share (in usd per share)

$ 0.31

Electrical Generation Revenue

$ 4,471

$ 5,629

268

211

4,739

5,840

2,440

3,426

1,296

1,162

171

149

289

254

126

122

Equity in (losses) earnings of unconsolidated affiliates

4,324

5,120

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

(1)

415

719

(87)

(90)

(10)

(12)

(93)

(94)

(4)

(8)

411

711

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

151

226

(3)

Net (loss) income attributable to noncontrolling interests

257

485

(53)

Net income attributable to membership interest

310

443

Pension and non-pension postretirement benefit plans:

Unrealized (loss) gain on cash flow hedges

(5)

Unrealized loss on equity investments

(2)

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

(12)

^[1]

(1)

(17)

256

468

Operating revenues

1,244

1,184

1,249

1,185

343

318

305

333

189

175

Equity in (losses) earnings of unconsolidated affiliates

980

955

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

274

230

(83)

(81)

(3)

(4)

(3)

(82)

(81)

192

149

Pension and non-pension postretirement benefit plans:

115

115

197

308

643

677

841

985

166

216

160

177

197

Gain (Loss) on Disposition of Other Assets

645

763

Equity in (losses) earnings of unconsolidated affiliates

196

223

(28)

(25)

(3)

(2)

(29)

(26)

167

197

Pension and non-pension postretirement benefit plans:

124

139

124

139

246

315

678

714

929

1,036

127

208

171

137

142

168

156

109

106

Equity in (losses) earnings of unconsolidated affiliates

742

832

187

204

(20)

(21)

(4)

(4)

(20)

(21)

167

183

Preferred security dividends and redemption

101

109

Net income attributable to common shareholders

106

Pension and non-pension postretirement benefit plans:

Pepco Holdings, LLC [Member] | Predecessor [Member]

101

109

Electric and Gas Revenue

$ 1,096

1,268

1,153

1,354

471

588

294

300

152

155

105

118

1,048

1,212

105

142

(65)

(68)

(9)

(69)

(59)

Pension and non-pension postretirement benefit plans:

Actuarial loss reclassified to periodic benefit cost

Pepco Holdings, LLC [Member] | Successor [Member]

$ 20

Electric and Gas Revenue

$ 90

105

Costs and Expenses, Related Party

447

516

(411)

(6)

(2)

(4)

(415)

(106)

Pension and non-pension postretirement benefit plans:

(309)

Actuarial loss reclassified to periodic benefit cost

$ (309)

550

544

551

545

191

211

288

112

Equity in (losses) earnings of unconsolidated affiliates

656

482

(105)

(37)

(30)

(9)

(5)

(28)

(25)

(133)

(25)

Pension and non-pension postretirement benefit plans:

(108)

(108)

301

333

362

421

147

178

204

Equity in (losses) earnings of unconsolidated affiliates

434

358

(72)

(12)

(3)

(2)

(9)

(10)

(81)

(9)

Pension and non-pension postretirement benefit plans:

(72)

(72)

290

333

291

334

157

191

211

Equity in (losses) earnings of unconsolidated affiliates

412

305

(121)

(16)

(4)

(1)

(12)

(15)

(133)

(33)

Pension and non-pension postretirement benefit plans:

(100)

$ (100)

$ 9

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

Consolidated Statements of Cash Flows (Unaudited) - USD ($)		3 Months Ended
	Mar. 31, 2016	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		$ 123,000,000		$ 738,000,000
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		1,063,000,000		948,000,000
Impairment of long-lived assets		119,000,000		0
Gain on sales of assets		(9,000,000)		(1,000,000)
Deferred income taxes and amortization of investment tax credits		(127,000,000)		(129,000,000)
Net fair value changes related to derivatives		(107,000,000)		(91,000,000)
Gain (Loss) on Investments		55,000,000		47,000,000
Other non-cash operating activities		804,000,000		344,000,000
Changes in assets and liabilities:
Inventories		142,000,000		291,000,000
Accounts receivable		117,000,000		(270,000,000)
Accounts payable and accrued expenses		571,000,000		468,000,000
Option premiums received, net		17,000,000		5,000,000
Collateral received, net		206,000,000		257,000,000
Income taxes		47,000,000		174,000,000
Pension and non-pension postretirement benefit contributions		(239,000,000)		(269,000,000)
Other assets and liabilities		(311,000,000)		(250,000,000)
Net cash flows provided by operating activities		1,473,000,000		1,490,000,000
Cash flows from investing activities
Capital expenditures		(2,202,000,000)		(1,784,000,000)
Proceeds from nuclear decommissioning trust fund sales		2,240,000,000		1,681,000,000
Investment in nuclear decommissioning trust funds		(2,297,000,000)		(1,747,000,000)
Acquisition of businesses, net of cash acquired		(6,645,000,000)		(15,000,000)
Proceeds from Sale of Property Held-for-sale		0		142,000,000
Proceeds from termination of direct financing lease investment		360,000,000		0
Change in restricted cash		(2,000,000)		(26,000,000)
Other investing activities		(2,000,000)		(2,000,000)
Net cash flows used in investing activities		8,548,000,000		1,751,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from Short-term Debt, Maturing in More than Three Months		123,000,000		0
Changes in short-term borrowings		(1,647,000,000)		141,000,000
Proceeds from Issuance of Long-term Debt		151,000,000		1,206,000,000
Retirement of long-term debt		(116,000,000)		(580,000,000)
Dividends paid on common stock		(287,000,000)		(269,000,000)
Proceeds from employee stock plans		9,000,000		8,000,000
Other financing activities		(6,000,000)		16,000,000
Net cash flows provided by financing activities		1,533,000,000		208,000,000
Decrease in cash and cash equivalents		(5,542,000,000)		(53,000,000)
Cash and cash equivalents at beginning of period		6,502,000,000	$ 6,502,000,000	1,878,000,000
Cash and cash equivalents at end of period	$ 960,000,000	960,000,000		1,825,000,000
Exelon Generation Co L L C [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		257,000,000		485,000,000
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		667,000,000		591,000,000
Impairment of long-lived assets		119,000,000		0
Gain on sales of assets		0		1,000,000
Deferred income taxes and amortization of investment tax credits		(68,000,000)		(89,000,000)
Net fair value changes related to derivatives		(106,000,000)		(165,000,000)
Gain (Loss) on Investments		55,000,000		47,000,000
Other non-cash operating activities		51,000,000		45,000,000
Changes in assets and liabilities:
Inventories		93,000,000		228,000,000
Accounts receivable		173,000,000		24,000,000
Change Receivables Payables From Affiliates		17,000,000		(10,000,000)
Accounts payable and accrued expenses		363,000,000		254,000,000
Option premiums received, net		(17,000,000)		5,000,000
Collateral received, net		198,000,000		288,000,000
Income taxes		(60,000,000)		(104,000,000)
Pension and non-pension postretirement benefit contributions		(112,000,000)		(107,000,000)
Other assets and liabilities		(148,000,000)		(232,000,000)
Net cash flows provided by operating activities		782,000,000		837,000,000
Cash flows from investing activities
Capital expenditures		(1,125,000,000)		(937,000,000)
Proceeds from nuclear decommissioning trust fund sales		2,240,000,000		1,681,000,000
Investment in nuclear decommissioning trust funds		(2,297,000,000)		(1,747,000,000)
Acquisition of businesses, net of cash acquired		(1,000,000)		(15,000,000)
Proceeds from Sale of Property Held-for-sale		0		142,000,000
Change in restricted cash		4,000,000		(21,000,000)
Other investing activities		(25,000,000)		(2,000,000)
Changes in Exelon intercompany money pool		(1,183,000,000)		936,000,000
Net cash flows used in investing activities		1,204,000,000		899,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings		(1,377,000,000)		1,000,000
Proceeds from Debt, Maturing in More than Three Months		123,000,000
Retirement of long-term debt		(94,000,000)		(18,000,000)
Proceeds from Issuance of Debt		151,000,000		806,000,000
Repayments of Related Party Debt		0		(550,000,000)
Changes in Exelon intercompany money pool		(1,183,000,000)		936,000,000
Other financing activities		(5,000,000)		3,000,000
Distribution to member		(55,000,000)		(1,356,000,000)
Proceeds from Contributions from Affiliates		44,000,000		0
Net cash flows provided by financing activities		368,000,000		(186,000,000)
Decrease in cash and cash equivalents		(54,000,000)		(248,000,000)
Cash and cash equivalents at beginning of period		431,000,000	431,000,000	780,000,000
Cash and cash equivalents at end of period	377,000,000	377,000,000		532,000,000
Commonwealth Edison Co [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		115,000,000		90,000,000
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		189,000,000		175,000,000
Gain on sales of assets		(5,000,000)		0
Deferred income taxes and amortization of investment tax credits		(70,000,000)		(35,000,000)
Other non-cash operating activities		32,000,000		126,000,000
Changes in assets and liabilities:
Inventories		(7,000,000)		(10,000,000)
Accounts receivable		(69,000,000)		38,000,000
Change Receivables Payables From Affiliates		0		2,000,000
Accounts payable and accrued expenses		(207,000,000)		121,000,000
Collateral received, net		(7,000,000)		5,000,000
Income taxes		20,000,000		131,000,000
Pension and non-pension postretirement benefit contributions		(32,000,000)		(121,000,000)
Other assets and liabilities		14,000,000		9,000,000
Net cash flows provided by operating activities		284,000,000		251,000,000
Cash flows from investing activities
Capital expenditures		639,000,000		530,000,000
Other investing activities		(13,000,000)		(7,000,000)
Net cash flows used in investing activities		(626,000,000)		(523,000,000)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings		(349,000,000)		(21,000,000)
Proceeds from Issuance of Long-term Debt		0		(400,000,000)
Dividends paid on common stock		(91,000,000)		75,000,000
Other financing activities		1,000,000		(4,000,000)
Contributions from parent		(39,000,000)		14,000,000
Net cash flows provided by financing activities		296,000,000		314,000,000
Decrease in cash and cash equivalents		(46,000,000)		42,000,000
Cash and cash equivalents at beginning of period		67,000,000	67,000,000	66,000,000
Cash and cash equivalents at end of period	21,000,000	21,000,000		108,000,000
PECO Energy Co [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		124,000,000		139,000,000
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		67,000,000		62,000,000
Deferred income taxes and amortization of investment tax credits		(23,000,000)		(5,000,000)
Other non-cash operating activities		24,000,000		44,000,000
Changes in assets and liabilities:
Inventories		24,000,000		34,000,000
Accounts receivable		(51,000,000)		(115,000,000)
Change Receivables Payables From Affiliates		4,000,000		5,000,000
Accounts payable and accrued expenses		(18,000,000)		1,000,000
Income taxes		29,000,000		67,000,000
Pension and non-pension postretirement benefit contributions		(29,000,000)		(12,000,000)
Other assets and liabilities		(95,000,000)		(70,000,000)
Net cash flows provided by operating activities		138,000,000		158,000,000
Cash flows from investing activities
Capital expenditures		(195,000,000)		(148,000,000)
Changes in Exelon intercompany money pool		(160,000,000)		0
Other investing activities		4,000,000		4,000,000
Changes in Exelon intercompany money pool				65,000,000
Net cash flows used in investing activities		351,000,000		144,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in Exelon intercompany money pool				65,000,000
Dividends paid on common stock		(69,000,000)		(70,000,000)
Other financing activities		0		1,000,000
Net cash flows provided by financing activities		(69,000,000)		(6,000,000)
Decrease in cash and cash equivalents		(282,000,000)		8,000,000
Cash and cash equivalents at beginning of period		295,000,000	295,000,000	30,000,000
Cash and cash equivalents at end of period	13,000,000	13,000,000		38,000,000
Baltimore Gas and Electric Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		101,000,000		109,000,000
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		109,000,000		106,000,000
Deferred income taxes and amortization of investment tax credits		(26,000,000)		(33,000,000)
Other non-cash operating activities		44,000,000		64,000,000
Changes in assets and liabilities:
Inventories		17,000,000		38,000,000
Accounts receivable		(44,000,000)		(141,000,000)
Change Receivables Payables From Affiliates		7,000,000		(8,000,000)
Accounts payable and accrued expenses		(3,000,000)		14,000,000
Collateral received, net		0		(27,000,000)
Income taxes		78,000,000		26,000,000
Pension and non-pension postretirement benefit contributions		(38,000,000)		(4,000,000)
Other assets and liabilities		(30,000,000)		99,000,000
Net cash flows provided by operating activities		273,000,000		281,000,000
Cash flows from investing activities
Capital expenditures		(176,000,000)		(136,000,000)
Change in restricted cash		(20,000,000)		2,000,000
Other investing activities		5,000,000		2,000,000
Net cash flows used in investing activities		191,000,000		132,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings		60,000,000		120,000,000
Dividends paid on common stock		(45,000,000)		(36,000,000)
Other financing activities		(1,000,000)		13,000,000
Contributions from parent		(21,000,000)		0
Dividends paid on preference stock		(3,000,000)		(3,000,000)
Net cash flows provided by financing activities		(86,000,000)		(172,000,000)
Decrease in cash and cash equivalents		(4,000,000)		(23,000,000)
Cash and cash equivalents at beginning of period		9,000,000	9,000,000	64,000,000
Cash and cash equivalents at end of period	5,000,000	5,000,000		41,000,000
Pepco Holdings, LLC [Member] \| Predecessor [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income			19,000,000	53,000,000
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			152,000,000	155,000,000
Deferred income taxes and amortization of investment tax credits			(19,000,000)	(49,000,000)
Net fair value changes related to derivatives			(18,000,000)	0
Other non-cash operating activities			(46,000,000)	57,000,000
Changes in assets and liabilities:
Inventories			4,000,000	(3,000,000)
Accounts receivable			28,000,000	(214,000,000)
Change Receivables Payables From Affiliates			0	0
Accounts payable and accrued expenses			(42,000,000)	(43,000,000)
Collateral received, net			(1,000,000)	0
Income taxes			12,000,000	(3,000,000)
Pension and non-pension postretirement benefit contributions			4,000,000	5,000,000
Other assets and liabilities			9,000,000	25,000,000
Net cash flows provided by operating activities			264,000,000	157,000,000
Cash flows from investing activities
Capital expenditures			(273,000,000)	(246,000,000)
Purchases of investments			(68,000,000)	0
Change in restricted cash			3,000,000	9,000,000
Other investing activities			(5,000,000)	2,000,000
Changes in Exelon intercompany money pool			0	0
Net cash flows used in investing activities			343,000,000	235,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from Short-term Debt, Maturing in More than Three Months			500,000,000	0
Changes in short-term borrowings			121,000,000	(74,000,000)
Proceeds from Issuance of Long-term Debt			0	208,000,000
Retirement of long-term debt			(11,000,000)	(22,000,000)
Changes in Exelon intercompany money pool			0	0
Dividends paid on common stock			0	(68,000,000)
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan			2,000,000	8,000,000
Other financing activities			(2,000,000)	13,000,000
Proceeds from Issuance of Preferred Stock and Preference Stock			0	18,000,000
Net cash flows provided by financing activities			372,000,000	205,000,000
Decrease in cash and cash equivalents			293,000,000	127,000,000
Cash and cash equivalents at beginning of period	319,000,000	26,000,000	26,000,000	15,000,000
Cash and cash equivalents at end of period			319,000,000	142,000,000
Pepco Holdings, LLC [Member] \| Successor [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income	(309,000,000)
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	14,000,000
Deferred income taxes and amortization of investment tax credits	112,000,000
Net fair value changes related to derivatives	0
Other non-cash operating activities	(410,000,000)
Changes in assets and liabilities:
Inventories	0
Accounts receivable	(16,000,000)
Change Receivables Payables From Affiliates	(46,000,000)
Accounts payable and accrued expenses	4,000,000
Collateral received, net	0
Income taxes	7,000,000
Pension and non-pension postretirement benefit contributions	0
Other assets and liabilities	25,000,000
Net cash flows provided by operating activities	43,000,000
Cash flows from investing activities
Capital expenditures	(29,000,000)
Purchases of investments	(2,000,000)
Change in restricted cash	(1,000,000)
Other investing activities	2,000,000
Changes in Exelon intercompany money pool	(53,000,000)
Net cash flows used in investing activities	30,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Proceeds from Short-term Debt, Maturing in More than Three Months
Changes in short-term borrowings	20,000,000
Proceeds from Issuance of Long-term Debt	0
Retirement of long-term debt	0
Changes in Exelon intercompany money pool	(53,000,000)
Dividends paid on common stock	0
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan	0
Other financing activities	0
Proceeds from Issuance of Preferred Stock and Preference Stock	0
Net cash flows provided by financing activities	(181,000,000)
Decrease in cash and cash equivalents	(168,000,000)
Cash and cash equivalents at beginning of period	319,000,000
Cash and cash equivalents at end of period	151,000,000	151,000,000	319,000,000
PEPCO Holdings Inc [Member] \| Predecessor [Member]
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			152,000,000	155,000,000
PEPCO Holdings Inc [Member] \| Successor [Member]
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	14,000,000
Potomac Electric Power Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		(108,000,000)		26,000,000
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		75,000,000		62,000,000
Deferred income taxes and amortization of investment tax credits		(31,000,000)		12,000,000
Other non-cash operating activities		153,000,000		23,000,000
Changes in assets and liabilities:
Inventories		(1,000,000)		6,000,000
Accounts receivable		24,000,000		93,000,000
Change Receivables Payables From Affiliates		(55,000,000)		(21,000,000)
Accounts payable and accrued expenses		4,000,000		(6,000,000)
Income taxes		151,000,000		0
Pension and non-pension postretirement benefit contributions		1,000,000		0
Other assets and liabilities		(9,000,000)		(18,000,000)
Net cash flows provided by operating activities		258,000,000		33,000,000
Cash flows from investing activities
Capital expenditures		(109,000,000)		(119,000,000)
Purchases of investments		(31,000,000)		0
Change in restricted cash		2,000,000		3,000,000
Other investing activities		2,000,000		3,000,000
Net cash flows used in investing activities		136,000,000		113,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings		64,000,000		104,000,000
Proceeds from Issuance of Long-term Debt		0		208,000,000
Retirement of long-term debt		0		(12,000,000)
Dividends paid on common stock		(39,000,000)		0
Other financing activities		0		4,000,000
Contributions from parent		0		(112,000,000)
Net cash flows provided by financing activities		(103,000,000)		200,000,000
Decrease in cash and cash equivalents		19,000,000		120,000,000
Cash and cash equivalents at beginning of period		5,000,000	5,000,000	6,000,000
Cash and cash equivalents at end of period	24,000,000	24,000,000		126,000,000
Delmarva Power and Light Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		(72,000,000)		32,000,000
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		39,000,000		39,000,000
Deferred income taxes and amortization of investment tax credits		4,000,000		(21,000,000)
Other non-cash operating activities		118,000,000		12,000,000
Changes in assets and liabilities:
Inventories		1,000,000		5,000,000
Accounts receivable		4,000,000		(82,000,000)
Change Receivables Payables From Affiliates		20,000,000		4,000,000
Accounts payable and accrued expenses		3,000,000		(12,000,000)
Collateral received, net		1,000,000		0
Income taxes		52,000,000		0
Other assets and liabilities		(9,000,000)		14,000,000
Net cash flows provided by operating activities		147,000,000		57,000,000
Cash flows from investing activities
Capital expenditures		(81,000,000)		(68,000,000)
Change in restricted cash		0		5,000,000
Other investing activities		0		2,000,000
Net cash flows used in investing activities		81,000,000		61,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings		30,000,000		(69,000,000)
Dividends paid on common stock		(38,000,000)		(62,000,000)
Net cash flows provided by financing activities		(68,000,000)		7,000,000
Decrease in cash and cash equivalents		(2,000,000)		3,000,000
Cash and cash equivalents at beginning of period		5,000,000	5,000,000	4,000,000
Cash and cash equivalents at end of period	3,000,000	3,000,000		7,000,000
Atlantic City Electric Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income		(100,000,000)		9,000,000
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		40,000,000		43,000,000
Deferred income taxes and amortization of investment tax credits		33,000,000		(5,000,000)
Other non-cash operating activities		132,000,000		8,000,000
Changes in assets and liabilities:
Inventories		(2,000,000)		(1,000,000)
Accounts receivable		5,000,000		(44,000,000)
Change Receivables Payables From Affiliates		20,000,000		2,000,000
Accounts payable and accrued expenses		(19,000,000)		(21,000,000)
Income taxes				0
Pension and non-pension postretirement benefit contributions		168,000,000
Other assets and liabilities		(3,000,000)		20,000,000
Net cash flows provided by operating activities		246,000,000		63,000,000
Cash flows from investing activities
Capital expenditures		(101,000,000)		(54,000,000)
Change in restricted cash		1,000,000		0
Other investing activities		0		1,000,000
Net cash flows used in investing activities		100,000,000		53,000,000
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings		5,000,000		(16,000,000)
Retirement of long-term debt		(11,000,000)		(10,000,000)
Dividends paid on common stock		(11,000,000)		(12,000,000)
Net cash flows provided by financing activities		(27,000,000)		(6,000,000)
Decrease in cash and cash equivalents		119,000,000		4,000,000
Cash and cash equivalents at beginning of period		3,000,000	$ 3,000,000	2,000,000
Cash and cash equivalents at end of period	$ 122,000,000	$ 122,000,000		$ 6,000,000

Consolidated Balance Sheets (Unaudited) - USD ($)

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Mar. 31, 2015

Dec. 31, 2014

$ 111,742,000,000

$ 95,384,000,000

960,000,000

6,502,000,000

$ 1,825,000,000

$ 1,878,000,000

218,000,000

205,000,000

3,594,000,000

3,187,000,000

1,138,000,000

912,000,000

Unamortized energy contract assets

1,185,000,000

1,365,000,000

85,000,000

86,000,000

285,000,000

462,000,000

1,229,000,000

1,104,000,000

1,584,000,000

759,000,000

1,086,000,000

752,000,000

11,364,000,000

15,334,000,000

69,406,000,000

57,439,000,000

10,407,000,000

6,065,000,000

10,526,000,000

10,342,000,000

455,000,000

639,000,000

6,688,000,000

2,672,000,000

841,000,000

758,000,000

474,000,000

484,000,000

183,000,000

206,000,000

1,398,000,000

1,445,000,000

30,972,000,000

22,611,000,000

3,640,000,000

533,000,000

2,058,000,000

1,500,000,000

2,874,000,000

2,883,000,000

2,260,000,000

2,376,000,000

8,000,000

Mark-to-market derivative liabilities (current liabilities)

512,000,000

369,000,000

203,000,000

205,000,000

582,000,000

100,000,000

Energy Marketing Accounts Payable

1,008,000,000

842,000,000

308,000,000

302,000,000

Accounts Payable and Accrued Liabilities, Current

317,000,000

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

19,000,000

28,000,000

13,770,000,000

9,118,000,000

29,314,000,000

23,645,000,000

641,000,000

Deferred income taxes and unamortized investment tax credits

17,474,000,000

13,776,000,000

8,755,000,000

8,585,000,000

3,771,000,000

3,385,000,000

Spent nuclear fuel obligation

1,902,000,000

1,618,000,000

1,022,000,000

1,021,000,000

Mark-to-market derivative liabilities (noncurrent liabilities)

4,378,000,000

4,201,000,000

408,000,000

374,000,000

Payable for Zion Station decommissioning

1,144,000,000

117,000,000

72,000,000

90,000,000

1,886,000,000

1,491,000,000

40,812,000,000

34,658,000,000

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[1]

84,537,000,000

68,062,000,000

19,000,000

28,000,000

Stockholders' Equity Attributable to Parent [Abstract]

193,000,000

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

18,686,000,000

18,676,000,000

(2,327,000,000)

11,954,000,000

12,068,000,000

^[2]

(2,596,000,000)

(2,624,000,000)

(2,673,000,000)

(2,684,000,000)

BGE preference stock not subject to mandatory redemption

25,717,000,000

25,793,000,000

193,000,000

Noncontrolling interest

1,276,000,000

1,308,000,000

27,186,000,000

27,294,000,000

111,742,000,000

95,384,000,000

11,954,000,000

12,068,000,000

Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities

^[2]

(2,596,000,000)

(2,624,000,000)

(2,673,000,000)

(2,684,000,000)

^[3]

262,000,000

147,000,000

Variable Interest Entity, Primary Beneficiary [Member]

8,310,000,000

8,268,000,000

145,000,000

164,000,000

117,000,000

100,000,000

231,000,000

219,000,000

28,000,000

43,000,000

120,000,000

140,000,000

186,000,000

181,000,000

50,000,000

35,000,000

877,000,000

882,000,000

5,141,000,000

5,160,000,000

2,069,000,000

2,036,000,000

47,000,000

41,000,000

53,000,000

135,000,000

90,000,000

265,000,000

111,000,000

164,000,000

216,000,000

Mark-to-market derivative liabilities (current liabilities)

81,000,000

115,000,000

7,000,000

5,000,000

12,000,000

13,000,000

542,000,000

472,000,000

743,000,000

666,000,000

^[4]

2,016,000,000

1,999,000,000

9,000,000

35,000,000

39,000,000

76,000,000

79,000,000

2,879,000,000

2,792,000,000

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

3,421,000,000

3,264,000,000

8,310,000,000

8,268,000,000

47,002,000,000

46,529,000,000

377,000,000

431,000,000

532,000,000

780,000,000

119,000,000

123,000,000

1,963,000,000

2,095,000,000

434,000,000

360,000,000

Unamortized energy contract assets

1,185,000,000

1,365,000,000

85,000,000

86,000,000

154,000,000

83,000,000

251,000,000

384,000,000

884,000,000

880,000,000

719,000,000

535,000,000

6,171,000,000

6,342,000,000

26,166,000,000

25,843,000,000

10,526,000,000

10,342,000,000

250,000,000

210,000,000

47,000,000

799,000,000

733,000,000

Deferred Tax Assets, Net, Noncurrent

473,000,000

484,000,000

12,000,000

6,000,000

183,000,000

206,000,000

650,000,000

627,000,000

1,725,000,000

1,689,000,000

14,665,000,000

14,344,000,000

1,529,000,000

29,000,000

177,000,000

90,000,000

1,290,000,000

1,583,000,000

673,000,000

935,000,000

Exelon Money Pool Borrowing Current

140,000,000

104,000,000

63,000,000

1,252,000,000

Mark-to-market derivative liabilities (current liabilities)

177,000,000

182,000,000

85,000,000

100,000,000

Energy Marketing Accounts Payable

333,000,000

356,000,000

308,000,000

302,000,000

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

19,000,000

28,000,000

4,775,000,000

4,933,000,000

Long-term debt to affiliate

7,945,000,000

7,936,000,000

930,000,000

933,000,000

Deferred income taxes and unamortized investment tax credits

5,872,000,000

5,845,000,000

8,588,000,000

8,431,000,000

Spent nuclear fuel obligation

937,000,000

924,000,000

1,022,000,000

1,021,000,000

Due to Affiliate, Noncurrent

2,600,000,000

2,577,000,000

Mark-to-market derivative liabilities (noncurrent liabilities)

166,000,000

150,000,000

Payable for Zion Station decommissioning

106,000,000

117,000,000

71,000,000

90,000,000

637,000,000

602,000,000

19,999,000,000

19,757,000,000

Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount

^[5]

33,649,000,000

33,559,000,000

19,000,000

28,000,000

Stockholders' Equity Attributable to Parent [Abstract]

2,956,000,000

2,701,000,000

^[2]

(64,000,000)

(63,000,000)

(53,000,000)

(36,000,000)

Noncontrolling interest

1,275,000,000

1,307,000,000

Members' Capital

9,167,000,000

8,997,000,000

2,956,000,000

2,701,000,000

^[2]

(64,000,000)

(63,000,000)

(53,000,000)

(36,000,000)

Total member's equity

12,059,000,000

11,635,000,000

Total liabilities and equity

13,334,000,000

12,942,000,000

47,002,000,000

46,529,000,000

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

8,190,000,000

8,235,000,000

145,000,000

164,000,000

62,000,000

77,000,000

231,000,000

219,000,000

28,000,000

43,000,000

120,000,000

140,000,000

186,000,000

181,000,000

36,000,000

30,000,000

808,000,000

854,000,000

5,141,000,000

5,160,000,000

2,069,000,000

2,036,000,000

47,000,000

41,000,000

53,000,000

84,000,000

85,000,000

128,000,000

27,000,000

164,000,000

216,000,000

Mark-to-market derivative liabilities (current liabilities)

75,000,000

113,000,000

7,000,000

5,000,000

12,000,000

13,000,000

399,000,000

386,000,000

559,000,000

623,000,000

2,016,000,000

1,999,000,000

^[4]

9,000,000

35,000,000

39,000,000

76,000,000

79,000,000

2,695,000,000

2,749,000,000

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

3,094,000,000

3,135,000,000

8,190,000,000

8,235,000,000

3,094,000,000

3,135,000,000

26,887,000,000

26,532,000,000

21,000,000

67,000,000

108,000,000

66,000,000

2,000,000

479,000,000

533,000,000

221,000,000

272,000,000

202,000,000

199,000,000

239,000,000

218,000,000

51,000,000

63,000,000

Inventories, net

157,000,000

164,000,000

1,372,000,000

1,518,000,000

17,971,000,000

17,502,000,000

925,000,000

895,000,000

6,000,000

2,625,000,000

Receivable from affiliate

330,000,000

324,000,000

2,182,000,000

2,172,000,000

1,476,000,000

1,490,000,000

7,544,000,000

7,512,000,000

643,000,000

294,000,000

665,000,000

645,000,000

660,000,000

539,000,000

706,000,000

64,000,000

62,000,000

Mark-to-market derivative liabilities (current liabilities)

150,000,000

155,000,000

26,000,000

23,000,000

76,000,000

70,000,000

130,000,000

131,000,000

2,938,000,000

2,766,000,000

5,845,000,000

5,844,000,000

205,000,000

Deferred income taxes and unamortized investment tax credits

4,985,000,000

4,914,000,000

113,000,000

111,000,000

254,000,000

259,000,000

Mark-to-market derivative liabilities (noncurrent liabilities)

3,489,000,000

3,459,000,000

239,000,000

224,000,000

512,000,000

507,000,000

9,592,000,000

9,474,000,000

18,580,000,000

18,289,000,000

Stockholders' Equity Attributable to Parent [Abstract]

1,588,000,000

1,002,000,000

978,000,000

Other paid-in capital

5,717,000,000

5,677,000,000

8,307,000,000

8,243,000,000

26,887,000,000

26,532,000,000

1,002,000,000

978,000,000

10,462,000,000

10,367,000,000

13,000,000

295,000,000

38,000,000

30,000,000

3,000,000

288,000,000

258,000,000

124,000,000

146,000,000

Receivable from Exelon intercompany money pool

5,000,000

2,000,000

160,000,000

18,000,000

43,000,000

27,000,000

26,000,000

42,000,000

34,000,000

26,000,000

24,000,000

Prepaid utility taxes

110,000,000

11,000,000

816,000,000

842,000,000

7,209,000,000

7,141,000,000

1,605,000,000

1,583,000,000

27,000,000

28,000,000

Receivable from affiliate

20,000,000

21,000,000

417,000,000

405,000,000

368,000,000

347,000,000

2,437,000,000

2,384,000,000

300,000,000

261,000,000

281,000,000

84,000,000

109,000,000

62,000,000

55,000,000

134,000,000

112,000,000

33,000,000

29,000,000

59,000,000

58,000,000

933,000,000

944,000,000

2,281,000,000

2,280,000,000

184,000,000

Deferred income taxes and unamortized investment tax credits

2,849,000,000

2,792,000,000

27,000,000

288,000,000

287,000,000

521,000,000

527,000,000

88,000,000

90,000,000

3,773,000,000

3,723,000,000

7,171,000,000

7,131,000,000

Stockholders' Equity Attributable to Parent [Abstract]

2,455,000,000

835,000,000

780,000,000

^[2]

1,000,000

3,291,000,000

3,236,000,000

10,462,000,000

10,367,000,000

835,000,000

780,000,000

^[2]

1,000,000

8,361,000,000

8,295,000,000

5,000,000

9,000,000

41,000,000

64,000,000

44,000,000

24,000,000

328,000,000

300,000,000

77,000,000

112,000,000

13,000,000

36,000,000

39,000,000

33,000,000

266,000,000

267,000,000

16,000,000

3,000,000

Prepaid utility taxes

31,000,000

61,000,000

819,000,000

845,000,000

6,684,000,000

6,597,000,000

499,000,000

514,000,000

12,000,000

10,000,000

8,000,000

337,000,000

319,000,000

858,000,000

853,000,000

150,000,000

210,000,000

378,000,000

206,000,000

209,000,000

151,000,000

110,000,000

59,000,000

52,000,000

61,000,000

38,000,000

28,000,000

35,000,000

105,000,000

102,000,000

1,138,000,000

1,134,000,000

1,481,000,000

1,480,000,000

252,000,000

Deferred income taxes and unamortized investment tax credits

2,104,000,000

2,081,000,000

15,000,000

17,000,000

205,000,000

209,000,000

151,000,000

184,000,000

71,000,000

61,000,000

2,546,000,000

2,552,000,000

^[6]

5,417,000,000

5,418,000,000

Stockholders' Equity Attributable to Parent [Abstract]

190,000,000

1,381,000,000

1,367,000,000

1,373,000,000

1,320,000,000

BGE preference stock not subject to mandatory redemption

2,754,000,000

2,687,000,000

190,000,000

Total liabilities and shareholders' equity

2,944,000,000

2,877,000,000

8,361,000,000

8,295,000,000

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

1,373,000,000

1,320,000,000

47,000,000

26,000,000

44,000,000

23,000,000

44,000,000

23,000,000

3,000,000

79,000,000

Mark-to-market derivative liabilities (current liabilities)

4,000,000

2,000,000

83,000,000

81,000,000

41,000,000

^[4]

41,000,000

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

124,000,000

122,000,000

47,000,000

26,000,000

Pepco Holdings, LLC [Member]

41,000,000

Stockholders' Equity Attributable to Parent [Abstract]

183,000,000

BGE preference stock not subject to mandatory redemption

$ 183,000,000

Preferred Stock, Par or Stated Value Per Share

$ 0.01

Pepco Holdings, LLC [Member] | Predecessor [Member]

$ 16,184,000,000

$ 319,000,000

26,000,000

142,000,000

15,000,000

14,000,000

581,000,000

316,000,000

18,000,000

9,000,000

122,000,000

305,000,000

81,000,000

1,472,000,000

10,864,000,000

2,277,000,000

Notes and Loans, Noncurrent

80,000,000

4,000,000

1,406,000,000

Deferred Tax Assets, Net, Noncurrent

14,000,000

67,000,000

3,848,000,000

958,000,000

456,000,000

404,000,000

263,000,000

66,000,000

70,000,000

107,000,000

2,324,000,000

4,823,000,000

Deferred income taxes and unamortized investment tax credits

3,406,000,000

8,000,000

466,000,000

215,000,000

147,000,000

199,000,000

4,441,000,000

Preferred Stock, Shares Outstanding

$ 11,588,000,000

18,000

Stockholders' Equity Attributable to Parent [Abstract]

3,000,000

$ 617,000,000

(36,000,000)

4,439,000,000

16,184,000,000

Members' Capital

3,832,000,000

617,000,000

Pepco Holdings, LLC [Member] | Successor [Member]

(36,000,000)

Total member's equity

4,413,000,000

20,932,000,000

151,000,000

$ 319,000,000

12,000,000

536,000,000

284,000,000

16,000,000

4,000,000

122,000,000

801,000,000

75,000,000

2,001,000,000

10,980,000,000

3,202,000,000

Notes and Loans, Noncurrent

131,000,000

(4,000,000)

4,016,000,000

Deferred Tax Assets, Net, Noncurrent

1,000,000

23,000,000

57,000,000

517,000,000

7,951,000,000

1,317,000,000

476,000,000

348,000,000

327,000,000

66,000,000

106,000,000

497,000,000

51,000,000

121,000,000

235,000,000

3,544,000,000

5,656,000,000

Deferred income taxes and unamortized investment tax credits

3,399,000,000

5,000,000

143,000,000

186,000,000

1,038,000,000

289,000,000

5,060,000,000

14,260,000,000

Stockholders' Equity Attributable to Parent [Abstract]

(309,000,000)

BGE preference stock not subject to mandatory redemption

20,932,000,000

Members' Capital

6,981,000,000

(309,000,000)

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

Total member's equity

6,672,000,000

30,000,000

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

172,000,000

68,000,000

200,000,000

6,877,000,000

6,908,000,000

24,000,000

5,000,000

126,000,000

6,000,000

2,000,000

240,000,000

230,000,000

117,000,000

261,000,000

65,000,000

67,000,000

Assets Held-for-sale, Not Part of Disposal Group, Current

133,000,000

140,000,000

4,000,000

22,000,000

21,000,000

605,000,000

726,000,000

5,225,000,000

5,162,000,000

663,000,000

661,000,000

99,000,000

68,000,000

5,000,000

4,000,000

280,000,000

287,000,000

1,047,000,000

1,020,000,000

64,000,000

11,000,000

129,000,000

145,000,000

138,000,000

119,000,000

85,000,000

30,000,000

26,000,000

15,000,000

20,000,000

25,000,000

51,000,000

46,000,000

49,000,000

509,000,000

455,000,000

2,341,000,000

2,340,000,000

Deferred income taxes and unamortized investment tax credits

1,695,000,000

1,723,000,000

49,000,000

29,000,000

161,000,000

72,000,000

1,934,000,000

1,873,000,000

Stockholders' Equity Attributable to Parent [Abstract]

4,784,000,000

4,668,000,000

1,122,000,000

Other paid-in capital

971,000,000

1,118,000,000

2,093,000,000

2,240,000,000

2,093,000,000

2,240,000,000

6,877,000,000

6,908,000,000

3,959,000,000

3,969,000,000

3,000,000

5,000,000

7,000,000

4,000,000

149,000,000

154,000,000

40,000,000

96,000,000

4,000,000

8,000,000

34,000,000

32,000,000

67,000,000

72,000,000

22,000,000

21,000,000

319,000,000

388,000,000

3,132,000,000

3,070,000,000

295,000,000

299,000,000

8,000,000

8,000,000

2,000,000

197,000,000

202,000,000

508,000,000

511,000,000

75,000,000

105,000,000

218,000,000

204,000,000

100,000,000

109,000,000

44,000,000

31,000,000

42,000,000

20,000,000

57,000,000

49,000,000

9,000,000

15,000,000

35,000,000

31,000,000

76,000,000

656,000,000

564,000,000

1,047,000,000

1,061,000,000

Deferred income taxes and unamortized investment tax credits

939,000,000

945,000,000

21,000,000

19,000,000

109,000,000

111,000,000

60,000,000

32,000,000

1,129,000,000

1,107,000,000

Stockholders' Equity Attributable to Parent [Abstract]

2,832,000,000

2,732,000,000

612,000,000

515,000,000

625,000,000

1,127,000,000

1,237,000,000

3,959,000,000

3,969,000,000

515,000,000

625,000,000

3,393,000,000

3,387,000,000

122,000,000

3,000,000

$ 6,000,000

$ 2,000,000

11,000,000

12,000,000

146,000,000

156,000,000

74,000,000

242,000,000

24,000,000

23,000,000

95,000,000

98,000,000

13,000,000

12,000,000

485,000,000

546,000,000

2,384,000,000

2,322,000,000

Notes and Loans, Noncurrent

419,000,000

414,000,000

4,000,000

22,000,000

19,000,000

79,000,000

82,000,000

524,000,000

519,000,000

5,000,000

47,000,000

48,000,000

101,000,000

96,000,000

77,000,000

70,000,000

36,000,000

16,000,000

22,000,000

18,000,000

16,000,000

14,000,000

35,000,000

30,000,000

110,000,000

444,000,000

297,000,000

1,144,000,000

1,153,000,000

Deferred income taxes and unamortized investment tax credits

854,000,000

885,000,000

35,000,000

33,000,000

5,000,000

7,000,000

22,000,000

12,000,000

916,000,000

937,000,000

Stockholders' Equity Attributable to Parent [Abstract]

2,504,000,000

2,387,000,000

773,000,000

116,000,000

227,000,000

889,000,000

1,000,000,000

3,393,000,000

3,387,000,000

Variable Interest Entity, Nonconsolidated, Carrying Amount, Liabilities

116,000,000

227,000,000

161,000,000

172,000,000

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

29,000,000

30,000,000

11,000,000

12,000,000

11,000,000

12,000,000

18,000,000

45,000,000

46,000,000

Mark-to-market derivative liabilities (current liabilities)

2,000,000

47,000,000

48,000,000

114,000,000

124,000,000

^[4]

114,000,000

124,000,000

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

$ 161,000,000

$ 172,000,000

[1]	Exelon’s consolidated assets include $8,310 million and $8,268 million at March 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,421 million and $3,264 million at March 31, 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. 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 $8,190 million and $8,235 million at March 31, 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 $3,094 million and $3,135 million at March 31, 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 March 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $41 million and $41 million at March 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Common Stock, Shares Authorized	2,000,000,000	2,000,000,000
Stockholders' Equity Attributable to Parent [Abstract]
Assets	$ 111,742	$ 95,384
Common Stock, Shares, Outstanding	858,721,507	857,000,000
Treasury Stock, Shares held	35,000,000	35,000,000
Exelon Generation Co L L C [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	$ 47,002	$ 46,529
Commonwealth Edison Co [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	26,887	26,532
PECO Energy Co [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	10,462	10,367
Baltimore Gas and Electric Company [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	8,361	8,295
Potomac Electric Power Company [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	6,877	6,908
Delmarva Power and Light Company [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	3,959	3,969
Atlantic City Electric Company [Member]
Noncontrolling Interest in Variable Interest Entity	29	30
Stockholders' Equity Attributable to Parent [Abstract]
Assets	3,393	$ 3,387
Pepco Holdings, LLC [Member]
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Common Stock, Shares Authorized		400,000,000.00
Stockholders' Equity Attributable to Parent [Abstract]
Common Stock, Shares, Outstanding		254,289,261.00
Common Stock, Par or Stated Value Per Share		$ 0.01
Pepco Holdings, LLC [Member] \| Predecessor [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets		$ 16,184
Pepco Holdings, LLC [Member] \| Successor [Member]
Stockholders' Equity Attributable to Parent [Abstract]
Assets	$ 20,932

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

Total

Common Stock [Member]

Treasury Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

PECO Energy Co [Member]

Common Stock [Member]

PECO Energy Co [Member]

Retained Earnings [Member]

PECO Energy Co [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Exelon Generation Co L L C [Member]

Undistributed Earnings [Member]

Exelon Generation Co L L C [Member]

Membership Interest [Member]

Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Exelon Generation Co L L C [Member]

Noncontrolling Interest [Member]

Baltimore Gas and Electric Company [Member]

Common Stock [Member]

Baltimore Gas and Electric Company [Member]

Nonredeemable Preferred Stock [Member]

Baltimore Gas and Electric Company [Member]

Retained Earnings [Member]

Pepco Holdings, LLC [Member]

Additional Paid-in Capital [Member]

Pepco Holdings, LLC [Member]

Common Stock [Member]

Pepco Holdings, LLC [Member]

Membership Interest [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]

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]

Commonwealth Edison Co [Member]

Common Stock [Member]

Commonwealth Edison Co [Member]

Other Additional Capital [Member]

Commonwealth Edison Co [Member]

Retained Earnings, Unappropriated [Member]

Commonwealth Edison Co [Member]

Retained Earnings, Appropriated [Member]

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

^[1]

$ (2,684)

$ 1

$ (36)

$ 1

Net income | Predecessor [Member]

^[1]

(17)

738

139

485

$ 109

$ 26

$ 32

$ 9

$ 90

Common Stock, Value, Issued | Predecessor [Member]

^[1]

(2,673)

(53)

$ 3

Common Stock, Value, Issued

18,676

2,455

1,367

1,122

612

773

1,588

Retained Earnings (Accumulated Deficit) | Predecessor [Member]

617

$ 617

Accumulated other comprehensive loss, net | Predecessor [Member]

12,068

780

2,701

$ 2,701

1,320

625

227

978

(36)

$ (36)

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

(2,624)

^[1]

(63)

^[1]

$ (63)

$ 1,307

4,413

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

12,942

Additional Paid in Capital | Predecessor [Member]

$ 3,829

Additional Paid in Capital

1,118

5,677

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

$ 758

733

954,668

$ 27,294

$ 18,676

$ (2,327)

$ 12,068

$ (2,624)

$ 1,308

$ 193

2,877

2,240

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

25,793

3,236

$ 2,455

$ 780

$ 1

2,687

$ 1,367

$ 190

$ 1,320

2,240

$ 1,122

$ 1,118

1,237

$ 612

$ 625

1,000

$ 773

$ 227

8,243

$ 1,588

$ 5,677

$ (1,639)

$ 2,617

3,832

$ 3,832

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

8,997

$ 8,997

Stock Issued During Period, Value, Employee Stock Purchase Plan

^[1]

(1)

^[1]

(1)

$ 9

Stock Issued During Period, Shares, Employee Stock Purchase Plans

351

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

$ 123

173

(53)

124

257

310

(53)

101

(108)

(72)

(100)

115

(7)

Noncontrolling Interest, Increase from Sale of Parent Equity Interest

Long-term incentive plan activity (in shares)

1,783

Long-term incentive plan activity

$ 17

Employee stock purchase plan issuances (in shares)

351

Employee stock purchase plan issuances

$ 9

Appropriation of retained earnings for future dividends

(115)

115

Tax benefit on stock compensation

(16)

Common stock dividends

(287)

(3)

(69)

(45)

(91)

Contribution from parent

170

Dividends

(39)

Allocation of tax benefit from parent

Minority Interest Increase From Acquisition

Preferred security dividends

(3)

Temporary Equity, Other Changes

(19)

Other comprehensive loss, net of income taxes of $53

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

$ 27,186

18,686

(2,327)

11,954

(2,596)

1,276

193

2,944

2,093

956,802

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

$ 25,717

3,291

2,455

835

2,754

1,381

190

1,373

2,093

1,122

971

1,127

612

515

889

773

116

8,307

1,588

5,717

(1,639)

2,641

954,668

$ 27,294

18,676

(2,327)

12,068

(2,624)

1,308

193

2,877

2,240

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

25,793

3,236

2,455

780

2,687

1,367

190

1,320

2,240

1,122

1,118

1,237

612

625

1,000

773

227

8,243

1,588

5,677

(1,639)

2,617

3,832

$ 3,832

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

8,997

$ 8,997

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

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

Net income | Predecessor [Member]

Employee stock purchase plan issuances | Predecessor [Member]

Other comprehensive loss, net of income taxes of $53 | Predecessor [Member]

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

4,439

636

(35)

$ 3,838

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

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

Net income | Successor [Member]

(309)

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

$ 27,186

$ 18,686

$ (2,327)

$ 11,954

$ (2,596)

$ 1,276

$ 193

2,944

2,093

956,802

Common Stock, Value, Issued | Predecessor [Member]

$ 25,717

3,291

$ 2,455

$ 835

$ 1

2,754

$ 1,381

$ 190

$ 1,373

2,093

$ 1,122

$ 971

1,127

$ 612

$ 515

889

$ 773

$ 116

8,307

$ 1,588

$ 5,717

$ (1,639)

$ 2,641

$ 3

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

Additional Paid in Capital | Predecessor [Member]

$ 3,835

Common Stock, Value, Issued

18,686

2,455

1,381

1,122

612

773

1,588

Retained Earnings (Accumulated Deficit) | Successor [Member]

(309)

$ (309)

Accumulated other comprehensive loss, net | Successor [Member]

11,954

835

2,956

$ 2,956

$ 1,373

$ 515

$ 116

1,002

$ 0

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

(2,596)

^[1]

$ 1

^[1]

(64)

^[1]

$ (64)

$ 1,275

6,672

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

13,334

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

(235)

Business Combination, Contingent Consideration, Asset

235

Other Additional Capital | Successor [Member]

(29)

Additional Paid in Capital

$ 971

$ 5,717

Business Combination, Separately Recognized Transactions, Assets Recognized | Successor [Member]

$ 45

Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent

Organization, Consolidation and Presentation of Financial Statements [Abstract]

$ 841

$ 799

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

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Income taxes	$ 184
Accumulated Other Comprehensive Income (Loss) [Member]
Income taxes	(154)
Exelon Generation Co L L C [Member]
Income taxes	151
Exelon Generation Co L L C [Member] \| Accumulated Other Comprehensive Income (Loss) [Member]
Income taxes	53
Atlantic City Electric Company [Member]
Income taxes	(33)
PECO Energy Co [Member]
Income taxes	43
Commonwealth Edison Co [Member]
Income taxes	77
Baltimore Gas and Electric Company [Member]
Income taxes	66
Potomac Electric Power Company [Member]
Income taxes	(25)
Constellation Energy Group LLC [Member] \| Accumulated Other Comprehensive Income (Loss) [Member]
Income taxes	77
Constellation Energy Group LLC [Member] \| Exelon Generation Co L L C [Member] \| Accumulated Other Comprehensive Income (Loss) [Member]
Income taxes	$ 77

Basis of Presentation

3 Months Ended

Mar. 31, 2016

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

(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, and engages in natural gas and oil exploration and production activities (Upstream). 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 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 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 by 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 now 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 is an increase of $1 million and $5 million for the three months ended March 31, 2016 and March 31, 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 three months ended March 31, 2016 is less than $1 million for each of PHI Successor, PHI Predecessor and DPL, and $1 million for each of Pepco and ACE. The reclassification in the Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2015 is less than $1 million for PHI, Pepco, DPL and ACE, respectively. 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 March 31, 2016 and 2015 and for the three 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. These notes should be read in conjunction with the Combined Notes to Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2015 Form 10-K Reports.

Variable Interest Entities (All Registrants)

3 Months Ended

Mar. 31, 2016

Variable Interest Entity [Abstract]

Variable Interest Entity Disclosure [Text Block]

Variable Interest Entities (All Registrants)

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

At March 31, 2016, Exelon, Generation, BGE, PHI and ACE collectively consolidated nine VIEs or VIE groups for which the applicable Registrant was the primary beneficiary. At December 31, 2015, Exelon, Generation and BGE collectively had seven consolidated VIEs or VIE groups and PHI and ACE collectively had one consolidated VIE (see Consolidated Variable Interest Entities below). As of March 31, 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 a total of $250 million of equity incrementally from inception through December 2016 in proportion to their ownership interests, which equates to approximately $172 million for the tax equity investor and $78 million for Generation (see Note 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 March 31, 2016 and December 31, 2015, ComEd, PECO, Pepco and DPL do not have any material consolidated VIEs.

As of March 31, 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 March 31, 2016, the remaining obligation is $304 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 March 31, 2016, the remaining obligation is immaterial,


•	Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance,


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


•	Generation and EDF are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to their respective member interests (see Note 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 $14 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 months ended March 31, 2016 and 2015, BGE remitted $20 million and $21 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 months ended March 31, 2016 and 2015, ACE transferred $14 million and $13 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 March 31, 2016 and December 31, 2015 are as follows:



	March 31, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE
Current assets	$	928	$	860	$	44	$	22	$	11	$	909	$	881	$	23	$	12	$	12
Noncurrent assets	8,047		7,996		3		46		18		8,009		8,004		3		18		18
Total assets	$	8,975	$	8,856	$	47	$	68	$	29	$	8,918	$	8,885	$	26	$	30	$	30
Current liabilities	$	544	$	400	$	83	58		$	47	$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities	3,050		2,865		41		142		114		2,927		2,884		41		124		124
Total liabilities	$	3,594	$	3,265	$	124	$	200	$	161	$	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 March 31, 2016 and December 31, 2015, these assets and liabilities primarily consisted of the following:



	March 31, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents	$	145	$	145	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash	117		62		44		11		11		100		77		23		12		12
Accounts receivable, net
Customer	231		231		—		—		—		219		219		—		—		—
Other	28		28		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets	120		120		—		—		—		140		140		—		—		—
Inventory
Materials and supplies	186		186		—		—		—		181		181		—		—		—
Other current assets	50		36		—		11		—		35		30		—		—		—
Total current assets	877		808		44		22		11		882		854		23		12		12
Property, plant and equipment, net	5,141		5,141		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds	2,069		2,069		—		—		—		2,036		2,036		—		—		—
Goodwill	47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets	41		41		—		—		—		53		53		—		—		—
Other noncurrent assets	135		84		3		46		18		90		85		3		18		18
Total noncurrent assets	7,433		7,382		3		46		18		7,386		7,381		3		18		18
Total assets	$	8,310	$	8,190	$	47	$	68	$	29	$	8,268	$	8,235	$	26	$	30	$	30
Long-term debt due within one year	$	265	$	128	$	79	$	56	$	45	$	111	$	27	$	79	$	46	$	46
Accounts payable	164		164		—		—		—		216		216		—		—		—
Accrued expenses	81		75		4		2		2		115		113		2		2		2
Mark-to-market derivative liabilities	7		7		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities	12		12		—		—		—		12		12		—		—		—
Other current liabilities	13		13		—		—		—		13		13		—		—		—
Total current liabilities	542		399		83		58		47		472		386		81		48		48
Long-term debt	743		559		41		142		114		666		623		41		124		124
Asset retirement obligations	2,016		2,016		—		—		—		1,999		1,999		—		—		—
Pension obligation^(c)	9		9		—		—		—		9		9		—		—		—
Unamortized energy contract liabilities	35		35		—		—		—		39		39		—		—		—
Other noncurrent liabilities	76		76		—		—		—		79		79		—		—		—
Total noncurrent liabilities	2,879		2,695		41		142		114		2,792		2,749		41		124		124
Total liabilities	$	3,421	$	3,094	$	124	$	200	$	161	$	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 March 31, 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 $18 million. These immaterial VIEs are equity and debt securities in energy development companies. The maximum exposure to loss related to these securities is limited to the $18 million included in Investments on Exelon’s and Generation’s Consolidated Balance Sheets. The 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 a total of $250 million of equity incrementally from inception through December 2016 in proportion of their ownership interests, which equates to approximately $172 million for the tax equity investor and $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:



March 31, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	264	$	357	$	621
Total liabilities^(a)	15		247		262
Exelon's ownership interest in VIE^(a)	—		75		75
Other ownership interests in VIE^(a)	249		35		284
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		94		94
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	17		—		17



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 $183 million and $206 million as of March 31, 2016 and December 31, 2015, respectively; offset by payables to ZionSolutions LLC of $166 million and $189 million as of March 31, 2016 and December 31, 2015, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

For each 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

3 Months Ended

Mar. 31, 2016

Business Combinations [Abstract]

Mergers, Acquisitions and Dispositions

Merger with Pepco Holdings, Inc. (Exelon)

Description of Transaction

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

Regulatory Matters

On August 27, 2015, the District of Columbia Public Service Commission (DCPSC) issued an Opinion and Order denying approval of the merger, concluding that the merger as presented was not in the public interest. Exelon and PHI filed an Application for Reconsideration with the DCPSC on September 28, 2015. On October 6, 2015, various parties, including Exelon and PHI, entered into a Nonunanimous Full Settlement Agreement and Stipulation (Settlement Agreement) with respect to the merger. Exelon and PHI subsequently filed a motion of joint applicants requesting the DCPSC to reopen the approval application to allow for consideration of the Settlement Agreement and granting additional requested relief.

On October 28, 2015, the DCPSC agreed to reopen the approval application to allow for consideration of the Settlement Agreement. On February 26, 2016, the DCPSC rejected the Settlement Agreement and also voted that the merger would be deemed approved without further DCPSC action if the Settlement Agreement was modified in specific ways (Revised Settlement Agreement), and if such modifications were acceptable to Exelon, PHI, the District of Columbia Government, the Office of People's Counsel, the District of Columbia Water and Sewer Authority, the National Consumer Law Center, National Housing Trust and National Housing Trust-Enterprise Preservation Corporation, and the Apartment and Office Building Association of Metropolitan Washington (collectively, Settling Parties). On March 7, 2016, Exelon and PHI made a filing with the DCPSC requesting approval of the merger through either (1) the adoption of the Settlement Agreement as originally executed by the Settling Parties, (2) the adoption of the Revised Settlement Agreement as a resolution on the merits, or (3) the adoption of a compromise position with modifications to the Revised Settlement Agreement. On March 23, 2016, the DCPSC approved the merger through the adoption of the Revised Settlement Agreement with a minor modification.

Approval of the merger across all jurisdictions 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. Exelon estimates total commitments of approximately $444 million on a net present value basis (excluding charitable contributions and renewable generation commitments) will be provided. The actual cost of commitments may differ by a material amount depending on the result of final negotiations and application of the most favored nation provision. The following pre-tax costs were recognized, including the estimated impacts of applying the most favored nation provision, after the closing of the merger and are included in Operating and maintenance expense in Exelon's, Pepco's, DPL's and ACE's Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2016 and PHI's successor Consolidated Statement of Operations and Comprehensive Income:



								Successor
Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Customer bill credit	2016 - 2017	$	65	$	58	$	62	$	185	$	185
Energy efficiency	2016 - 2021	—		—		—		—		64
Charitable contributions	2016 - 2026	28		12		10		50		50
Customer base rate credit	2016 - 2019	26		—		—		26		26
Delivery system modernization	Q2 2016	—		—		—		—		22
Green sustainability fund	Q2 2016	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		11
Most favored nation		19		32		48		99		129
Other		1		2		—		3		7
Total		$	139	$	104	$	120	$	363	$	508

Pursuant to the orders approving the merger, Exelon expects to make $73 million, $46 million and $49 million 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 32 MWs of new generation in Maryland and the District of Columbia, 27MWs of which are expected to be completed by 2018. These investments are expected to total approximately $130 million. These investments are expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as incurred and recorded on Exelon's and Generation's financial statements. Exelon has also committed to purchase 100MW of wind energy to procure, under certain circumstances, 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 has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. Exelon was also named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve all claims, which is subject to court approval, with a decision not anticipated until the second or third quarter of 2016. Exelon does not believe resolution of these suits will have a material impact on Exelon’s results of operations or cash flows.

On July 21, 2015, the OPC filed a motion to stay the MDPSC order approving the merger and to set a schedule for discovery and presentation of new evidence. On July 29, 2015, Public Citizen, Inc. filed a response supporting OPC’s motion to stay, and on July 31, 2015 the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed a joint motion to stay. In July and August, Exelon, PHI, the MDPSC, Prince George’s County and Montgomery County filed responses opposing the motions to stay. The judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, 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.

On March 25, 2016, Grid 2.0 filed an application for reconsideration of the DCPSC’s March 23, 2016 order approving the merger. On March 30, 2016, Exelon filed a reply to that application. The DCPSC has tolled the date to act upon the application until May 25, 2016 and, therefore, the DCPSC is expected to issue an order ruling on these motions by that date. On April 20, 2016, DC Public Power filed a motion to reconsider the DCPSC's March 23, 2016 order, motion to intervene and motion to consider alternative settlement provisions (namely, that the DCPSC consider requiring the post-merger divestiture of Pepco’s DC-based assets to a not-for-profit independent grid operator). On April 27, 2016, Exelon filed a reply to these motions. The DCPSC is expected to issue an order ruling on these motions by May 20, 2016. On April 22, 2016, (1) the District of Columbia Office of People’s Counsel, (2) the District of Columbia Government, and (3) DC Sun and Public Citizen each filed separate applications for reconsideration of the DCPSC’s March 23, 2016 order. On April 29, 2016, Exelon filed a reply to these applications. The DCPSC is expected to issue an order ruling on these applications by May 23, 2016. These applications for reconsideration generally argue that the DCPSC violated its regulations, utilized improper processes, abused its discretion, acted arbitrarily and capriciously, committed legal error and denied due process in approving the merger under terms that revised the Settlement Agreement offered by the companies and various parties. 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 Sheet.

(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.

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



Preliminary Purchase Price Allocation
Current assets	$	2,107
Property, plant and equipment	11,071
Regulatory assets	5,118
Other assets	656
Goodwill	4,016
Total assets	22,968

Current liabilities	3,425
Unamortized energy contracts	1,550
Regulatory liabilities	297
Long-term debt, including current maturities	6,076
Deferred income taxes	3,441
Pension and OPEB liability	846
Other liabilities	191
Total liabilities	15,826
Total purchase price	$	7,142

On its successor financial statements, PHI has recorded beginning March 24, 2016, Membership interest equity of $7.2 billion, greater than the total $7.1 billion purchase price, reflecting the impacts 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, $1.2 billion and $1.1 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. Of this amount, 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 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 three months ended March 31, 2016 was as follows:



	PHI		Exelon^(a)
Beginning balance	$	—	$	2,672
Goodwill from business combination	4,016		4,016
Ending balance	$	4,016	$	6,688

_____________

(a) As of March 31, 2016, there were no changes to the carrying amount of goodwill for ComEd and Generation, 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 plant, property 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 March 31, 2016. The difference between the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible assets and liabilities was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present value of the underlying cash flows as of the merger date. Amortizations were not significant for the period March 24, 2016 to March 31, 2016 at Exelon or PHI.

The valuations performed in the first quarter of 2016 to assess the fair value of certain assets acquired and liabilities assumed are 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, if not sooner. The significant assets and liabilities for which preliminary valuation amounts are recognized at March 31, 2016 include the fair value of intangible assets and liabilities, uncertain tax positions, deferred income tax assets and liabilities, pension and OPEB plans, long-term debt, and unregulated property, plant and equipment. The preliminary amounts recognized are subject to revision until the valuations are completed and 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.

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 quarter impact of PHI, including its unregulated businesses, on Exelon's Consolidated Statement of Operations and Comprehensive Income includes Operating revenues of $107 million and Net loss of $(315) million during the three months ended March 31, 2016.

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



	Three Months Ended March 31,
Acquisition, Integration and Financing Costs^(a)	2016			2015
Exelon	$	102		$	108
Generation	16			7
ComEd^(b)	(8		)	3
PECO	2			1
BGE	2			1
Pepco	27			1
DPL	16			1
ACE	13			1



	Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	56	$	29	$	8

______________


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


(b)	Excludes acquisition, integration and financing costs of $9 million incurred at ComEd that have been recorded as a regulatory asset.

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 March 31,				Year Ended December 31,
	2016^(a)		2015^(b)		2015^(c)
Total operating revenues	$	8,556	$	10,062	$	33,823
Net income attributable to common shareholders	577		800		2,618

Basic earnings per share	$	0.63	$	0.87	$	2.85
Diluted earnings per share	0.62		0.87		2.84

______________


(a)	The amounts above exclude non-recurring costs directly related to the merger of $639 million and intercompany revenue of $170 million for the three months ended March 31, 2016.


(b)	The amounts above exclude non-recurring costs directly related to the merger of $116 million and intercompany revenue of $122 million for the three months ended March 31, 2015.


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

Asset Divestitures (Exelon, Generation, PHI, Pepco and ACE)

At March 31, 2016, Generation had net liabilities held for sale of $5 million which were reflected within Other current assets and Other current liabilities in the Consolidated Balance Sheet. The assets held for sale at December 31, 2015 were not material. On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in the Boston, Massachusetts, resulting in a pre-tax gain of approximately $32 million to be recorded in the second quarter. In addition, Pepco and ACE had net assets held for sale of $4 million and $1 million, respectively, which were reflected within Other current assets and Other current liabilities in their Consolidated Balance Sheets. The assets held for sale at December 31, 2015 were not material. 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 to be recorded in the second quarter. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain will be 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 (Exelon, Generation, ComEd, PECO and BGE)

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

3 Months Ended

Mar. 31, 2016

Regulated Operations [Abstract]

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. On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. The costs incurred for the project prior to May 21, 2014 were immaterial. ComEd has acquired numerous easements across the project route through voluntary transactions. ComEd is seeking to acquire the remaining rights either through settlement or condemnation proceedings that are currently pending in the relevant circuit courts. ComEd began construction of the line during the second quarter of 2015 with an expected in-service date of the second quarter of 2017.

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, 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 appealed the Court's decision. On April 5, 2016, the PAPUC’s request for appeal was denied. PECO does not have information at this time as to what action it may be required to take following remand to the PAPUC.

On December 4, 2014, the PAPUC approved PECO's third DSP Program. The program has a 24-month term from June 1, 2015 through May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. Under the program, PECO is procuring electric supply through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June 2016, the medium commercial class (101-500 kW) will move to spot market pricing. As of March 31, 2016, PECO entered into contracts with PAPUC-approved bidders, including Generation, resulting from the first three 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. The program has a 24-month term from June 1, 2017 through May 31, 2019, and complies with electric generation procurement guidelines set forth in Act 129. A PAPUC ruling is expected in late 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. The order tentatively established PECO’s five-year cumulative consumption reduction target at 2,080,553 MWh.

Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for the period June 1, 2016 through May 31, 2021. The PAPUC approved PECO’s EE&C Phase III Plan on March 17, 2016, subject to clarification of a few minor issues. PECO refiled its Phase III Plan, with all requested clarifications, on March 31, 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 annual service revenues for electric delivery, based on a requested ROE of 10.6%. Any adjustments to rates approved by the MDPSC are expected to take effect in November 2016. In addition to the proposed $127 million rate increase, Pepco is proposing to continue its Grid Resiliency Charge initially approved in July 2013 in connection with Pepco’s electric distribution rate case filed in November 2012. In connection with the Grid Resiliency Charge, 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 increase the MDPSC will approve or if it will approve Pepco’s Grid Resiliency Charge proposal.

2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC. 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 March 31, 2016, BGE has received approval of its updated surcharge filings three times for rates to be effective in 2014, 2015 and 2016.

In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE's 2013 electric and 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.

Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of March 31, 2016 and December 31, 2015, BGE recorded a regulatory asset of $212 million and $196 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE’s 2014 electric and gas distribution rate case, the cost of the retired non-AMI meters will be amortized over 10 years.

As part of the 2015 electric and gas distribution rate case filed on November 6, 2015, BGE is seeking recovery of its smart grid initiative costs. Of BGE's requested $197 million, $141 million relates to the smart grid initiative. In support of its recovery of smart grid initiative costs, BGE provided evidence demonstrating that the benefits exceed the costs on a present value basis by a ratio of 2.3 to 1.0, on a nominal basis. For further information, see Note 3 - Regulatory Matters of the Exelon 2015 Form 10-K.

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 MW beginning in 2015, in amounts proportional to their relative SOS loads. Under the terms of the order, the winning bidder will 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 will 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. The U.S. Supreme Court decision will likely moot the state court action pending in the Court of Special Appeals of Maryland.

Delaware Regulatory Matters

Gas Cost Rates. (Exelon, PHI and DPL) DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural gas procurement costs through customer rates. In August 2015, DPL made its 2015 GCR filing. The rates proposed in the 2015 GCR filing would result in a GCR decrease of approximately 26%, primarily reflecting lower natural gas prices. On September 22, 2015, the DPSC issued an order allowing DPL to place the new rates into effect on November 1, 2015, subject to refund and pending final DPSC approval. On March 22, 2016, the DPSC approved the Gas Cost Rate as filed.

2013 Electric Distribution Base Rates (Exelon, PHI and DPL). In March 2013, and as amended on September 20, 2013, DPL filed for an electric distribution base rate increase with the DPSC, ultimately requesting an annual increase of $42 million.

In August 2014, the DPSC issued a final order in DPL's 2013 electric distribution rate case for an annual increase of $15 million and an ROE of 9.70%. Rates became effective on May 1, 2014.

In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a prepaid pension expense and other postretirement benefit obligations in base rates. Under the Settlement Agreement related to the Merger, the parties agreed to suspend the appeal and, upon consummation of the Merger, to the withdrawal of the appeal and the cross-appeal with prejudice. In accordance with the settlement, on April 13, 2016, the parties filed a Stipulation of Dismissal with the court to dismiss the appeal and the cross-appeal. The court has not yet acted on this filing.

District of Columbia Regulatory Matters

District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). On May 3, 2014, the Council of the District of Columbia enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provides enabling legislation for the DC PLUG initiative. This $1 billion initiative seeks to selectively place underground some of the District of Columbia’s most outage-prone power lines, which lines and surrounding conduit would be owned and maintained by Pepco.

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 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 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.

On June 17, 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia and recovery of Pepco’s investment through a volumetric surcharge (the Triennial Plan), all in accordance with the Improvement Financing Act. On August 1, 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds and a volumetric surcharge for the District to recover the costs associated with the bond issuance (the DDOT surcharge).

On November 12, 2014, the DCPSC issued an order approving the Triennial Plan and Pepco’s volumetric surcharge, and issued the financing order, including approval of the DDOT surcharge. Together these orders permit (i) Pepco and DDOT to commence proposed construction under the Triennial Plan; (ii) the District of Columbia to issue the necessary bonds to fund the District of Columbia’s portion of the DC PLUG initiative; and (iii) the establishment of the customer surcharges contemplated by the Improvement Financing Act.

In March 2015, a party to the DCPSC proceedings filed with the District of Columbia Court of Appeals a petition for review of the order approving the Triennial Plan and the issuance of the financing order. On January 14, 2016, the District of Columbia Court of Appeals affirmed the orders of the DCPSC. On January 27, 2016, the original petitioning party sought rehearing of the District of Columbia Court of Appeals decision. On March 17, 2016, the District of Columbia Court of Appeals denied the original petitioning party's motion for rehearing.

Separately, 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 delay implementation of the DC PLUG initiative.

New Jersey Regulatory Matters

2016 Electric Distribution Base Rates (Exelon, PHI and ACE). On March 22, 2016, ACE filed an application with the NJBPU requesting an increase of $84 million to its annual service revenues for electric delivery, based on a requested ROE of 10.6%. In addition to the request for base rate relief, ACE has also included a request that the NJBPU approve ACE’s five-year grid resiliency initiative known as “PowerAhead.” As proposed, PowerAhead includes $176 million of 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. A decision is expected in the first half of 2017. ACE cannot predict how much of the requested increase the NJBPU will approve or if it will approve ACE's 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 uncollected 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. ACE has requested that the NJBPU place the new rates into effect by June 1, 2016.

Standard Offer Capacity Agreements (Exelon, PHI and ACE). On April 28, 2011, ACE entered into three SOCAs by order of the NJBPU, each with a different generation company. ACE and the other New Jersey EDCs entered into the SOCAs under protest, arguing that the EDCs were denied due process and that the SOCAs violated certain of the requirements of the New Jersey law under which the SOCAs were established (the NJ SOCA Law). On October 22, 2013, in light of the decision of the U.S. District Court for the District of New Jersey described below, the state appeals of the NJBPU implementation orders filed by the EDCs and generators were dismissed without prejudice, subject to the parties exercising their appellate rights in the Federal courts.

In February 2011, ACE joined other plaintiffs in an action filed in the U.S. District Court for the District of New Jersey challenging the NJ SOCA Law on the grounds that it violates the Commerce Clause and the Supremacy Clause of the U.S. Constitution. In October 2013, the Federal district court issued a ruling that the NJ SOCA Law is preempted by the Federal Power Act (FPA) and violates the Supremacy Clause, and is therefore null and void. On October 11, 2013, the Federal district court issued an order ruling that the SOCAs are void, invalid and unenforceable, which order was affirmed by the U.S. Court of Appeals for the Third Circuit on September 11, 2014.

On November 26, 2014 and December 10, 2014, respectively, one of the generation companies and the NJBPU petitioned the U.S. Supreme Court to consider hearing an appeal of the Third Circuit decision. On April 19, 2016, the U.S. Supreme Court unanimously affirmed the Fourth Circuit decision, discussed above under “MDPSC New Generation Contract Requirement,” holding that the MDPSC’s required contracts are illegal and unenforceable. On April 25, 2016, the U.S. Supreme Court ruled not to review the Third Circuit decision. This denial leaves the Third Circuit decision in place, with the same outcome as the Fourth Circuit decision.

ACE terminated one of the three SOCAs effective July 1, 2013 due to the occurrence of an event of default on the part of the generation company counterparty. ACE terminated the remaining two SOCAs effective November 19, 2013, in response to the October 2013 Federal district court decision.

New York Regulatory Matters

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 New York Public Service Commission (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 will begin recognizing revenue based on the final approved pricing contained in the RSSA. Generation will also recognize 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 non-controlling interest 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.

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.

The approved RSSA requires Ginna to continue operating through the RSSA term. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. 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-Implications of Potential Early 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). The following tables provide information about the net regulatory asset or liabilities associated with the transmission formula rate of the indicated registrants as of March 31, 2016 and December 31, 2015. The regulatory asset associated with the transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.



							Successor
As of March 31, 2016	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)	$	60	$	31	$	17	$	12	$	4	$	7	$	1



							Predecessor
As of December 31, 2015	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)(b)	$	43	$	31	$	12	$	14	$	5	$	7	$	2

_____


(a)	The regulatory assets represent a component of the costs included within the energy and transmission regulatory programs. Refer to Regulatory Assets and Liabilities table for additional information.


(b)	The Exelon consolidated amounts do not include the regulatory assets of PHI, Pepco, DPL, and ACE at December 31, 2015.

On April 13, 2016, ComEd filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by fourth quarter 2016. ComEd's 2016 annual update includes a total increase to the revenue requirement of $94 million, reflecting an increase of $90 million for the initial revenue requirement and an increase of $4 million related to the annual reconciliation. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.47%, inclusive of an allowed ROE of 11.50%, a decrease from the 8.61% average debt and equity return previously authorized.

On April 27, 2016, BGE filed its annual transmission formula rate update based upon the FERC approved formula with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2016, subject to review by the FERC and other parties, which is due by third quarter 2016. BGE's 2016 annual update includes a total increase to the revenue requirement of $15 million, reflecting an increase of $12 million for the initial revenue requirement and a decrease of $3 million related to the annual reconciliation. This increase excludes the $13 million increase in revenue requirement associated with dedicated facilities charges. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.09%, inclusive of an allowed ROE of 10.50% a decrease from the 8.46% average debt and equity return previously authorized.

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.

FERC Transmission Complaint (Exelon, BGE, PHI, Pepco, DPL and ACE). In February 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE, Pepco, DPL and ACE relating to their respective transmission formula rates. BGE’s formula rate included a 10.8% base ROE and a 50 basis point incentive for participating in PJM (and certain additional incentive base points on certain projects). Pepco's, DPL's and ACE's formula rates included, for facilities placed into service after January 1, 2006, a base ROE of 11.3%, and for facilities placed into service prior to January 1, 2006, a base ROE of 10.8% and a 50 basis point incentive for participating in PJM. The parties sought a reduction in the base return on equity to 8.7% and changes to the formula rate process. Under FERC rules, any revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint.

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

On February 23, 2016, FERC approved the settlement filed by the parties on November 6, 2015, covering the ROE issues raised in the complaints. The settlement provides for a 10% base ROE, effective March 8, 2016, which will be augmented by the PJM incentive adder of 50 basis points, and refunds to customers of BGE, Pepco, DPL and ACE of $13.7 million, $14.2 million, $11.9 million and $9.5 million, respectively. The settlement also prohibits any settling party from filing to change the base ROE or any incentives prior to June 1, 2018. The date for filing a request for rehearing has expired without any such requests having been filed. Accordingly, the order is not eligible for appeal and the matter is considered closed.

Operating License Renewals (Exelon and Generation). On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year license for the Conowingo Hydroelectric Project (Conowingo).

Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish habitat, and (3) sediment. On January 30, 2014, Generation filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues. MDE indicated that it believed it did not have sufficient information to process Generation's application. As a result, Generation entered into an agreement with MDE to work with state agencies in Maryland, the U.S. Army Corps of Engineers, the U.S. Geological Survey, the University of Maryland Center for Environmental Science and the U.S. Environmental Protection Agency Chesapeake Bay Program to design, conduct and fund an additional multi-year sediment study. Generation has agreed to contribute up to $3.5 million to fund the additional study. In addition, because of the ongoing sediment and nutrient monitoring study, and because states must act upon water quality certification applications within a year of submission, Exelon agreed with Maryland to coordinate the withdrawal and refiling of the application in accordance with FERC policy that requires an applicant to resubmit its request for a water quality certification within 90 days of the date of withdrawal

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 DOI's preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement resolving all issues between Exelon and Interior relating to fish passage at Conowingo. 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 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 may have a material effect on Exelon's and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.

The FERC license for Conowingo expired on September 1, 2014. Under the Federal Power Act, FERC is required to issue an annual license for a facility until the new license is issued. On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does not issue a new license prior to the expiration of an annual license, the annual license will renew automatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Conowingo. The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of March 31, 2016, $25 million of direct costs associated with the Conowingo licensing effort have been capitalized.

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 $2.5 billion regulatory asset reflecting adjustments recorded as a result of the acquisition method of accounting.

The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE as of March 31, 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
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Regulatory assets
Pension and other postretirement benefits ^(a)	$	4,261	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Deferred income taxes	1,861		65		1,499		80		217		139		35		43
AMI programs ^(r)	687		149		60		212		266		181		85		—
Under-recovered distribution service costs ^(b)	198		198		—		—		—		—		—		—
Debt costs ^(c)	132		45		1		8		86		19		9		7
Fair value of long-term debt ^(d)	896		—		—		—		741		—		—		—
Fair value of PHI's unamortized energy contracts ^(e)	1,535		—		—		—		1,535		—		—		—
Severance	8		—		—		8		—		—		—		—
Asset retirement obligations	113		71		22		19		1		1		—		—
MGP remediation costs	276		246		29		1		—		—		—		—
Under-recovered uncollectible accounts	60		60		—		—		—		—		—		—
Renewable energy	265		265		—		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(m)(n)(o)}	118		56		—		38		24		5		6		13
Deferred storm costs	47		—		—		2		45		19		6		20
Electric generation-related regulatory asset	18		—		—		18		—		—		—		—
Rate stabilization deferral	77		—		—		67		10		9		1		—
Energy efficiency and demand response programs	651		—		1		264		386		277		108		1
Merger integration costs	5		—		—		5		—		—		—		—
Conservation voltage reduction	3		—		—		3		—		—		—		—
Under-recovered revenue decoupling ^(h)	36		—		—		36		—		—		—		—
COPCO acquisition adjustment	12		—		—		—		12		—		12		—
Recoverable workers compensation and long-term disability	31		—		—		—		31		31		—		—
Vacation accrual	43		—		17		—		26		—		15		11
Securitized stranded costs	185		—		—		—		185		—		—		185
CAP arrearage	8		—		8		—		—		—		—		—
Removal costs	397		—		—		—		397		103		73		222
AEC ⁽ⁱ⁾	7		—		—		—		7		—		—		—
Other	61		9		10		4		34		12		12		12
Total regulatory assets	11,991		1,164		1,647		765		4,003		796		362		514
Less: current portion	1,584		239		42		266		801		133		67		95
Total non-current regulatory assets	$	10,407	$	925	$	1,605	$	499	$	3,202	$	663	$	295	$	419



									Successor
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	93	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,599		2,182		417		—		—		—		—		—
Removal costs	1,669		1,334		—		187		148		21		127		—
Deferred rent ^(j)	42								42		—		—		—
Energy efficiency and demand response programs	122		78		43		—		1		—		—		1
DLC program costs	9		—		9		—		—		—		—		—
Electric distribution tax repairs	89		—		89		—		—		—		—		—
Gas distribution tax repairs	25		—		25		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(l)(p)(q)}	187		43		69		15		60		25		25		10
Other	55		2		3		10		41		9		14		16
Total regulatory liabilities	4,890		3,639		655		212		292		55		166		27
Less: current portion	512		150		134		61		106		26		57		22
Total non-current regulatory liabilities	$	4,378	$	3,489	$	521	$	151	$	186	$	29	$	109	$	5



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79		214		137		36		41
AMI programs ^(r)	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(b)	189		189		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(d)	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		—		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(m)(n)(o)}	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		14		10		4		—
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 ^(h)	30		—		—		30		—		—		—		—
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		38		14		10		13
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 ^{(f)(g)(k)(l)(p)(q)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling^(h)	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 March 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes regulatory assets of $1,125 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 March 31, 2016, ComEd’s regulatory asset of $198 million was comprised of $156 million for the 2014 - 2016 annual reconciliations and $42 million related to significant one-time events including $31 million of deferred storm costs, $9 million of Constellation merger and integration related costs and $2 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.


(c)	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.


(d)	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.


(e)	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 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.

(f)

As of March 31, 2016, ComEd’s regulatory asset of $56 million included $18 million related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC approved formulate rate, and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of March 31, 2016, ComEd’s regulatory liability of $43 million included $17 million related to over-recovered energy costs and $26 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 formulate 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.

(g)

As of March 31, 2016, BGE's regulatory asset of $38 million included $5 million of costs associated with transmission costs recoverable through its FERC approved formula rate and $33 million related to under-recovered electric energy costs. As of March 31, 2016, BGE's regulatory liability of $15 million related to $2 million of over-recovered transmission costs and $14 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be recovered upon FERC approval. 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.

(h)

Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2016, BGE had a regulatory asset of $31 million related to under-recovered electric revenue decoupling and a regulatory asset of $5 million related to under-recovered natural gas 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.


(i)	Represents the regulatory asset recorded at Exelon and PHI for the difference between the carrying value and fair value of alternative energy credits at Pepco, DPL and ACE recorded at Exelon and PHI that are recoverable through the rate making process.


(j)	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 which was eliminated at PHI as part of acquisition accounting.

(k)

As of March 31, 2016, PECO's regulatory liability of $69 million included $36 million related to the DSP program, $26 million related to the over-recovered natural gas costs under the PGC, $3 million related to over-recovered electric transmission costs and $4 million related to over-recovered non-bypassable transmission service charges. 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 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.

(l)

As of March 31, 2016, DPL's regulatory liability of $25 million included $6 million related to over-recovered natural gas costs under the GCR mechanism, $7 million of over-recovered electric energy costs, and $12 million of over-recovered transmission 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.

(m)

As of March 31, 2016, Pepco's regulatory asset of $5 million included $4 million of transmission costs recoverable through its FERC approved formula rate and $1 million of under-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.


(n)	As of March 31, 2016, DPL's regulatory asset of $6 million related to transmission costs recoverable through its FERC approved formula rate. 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.

(o)

As of March 31, 2016, ACE's regulatory asset of $13 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $12 million of under-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.


(p)	As of March 31, 2016, Pepco's regulatory liability of $25 million included $15 million of over-recovered transmission costs and $10 million of over-recovered electric energy 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.


(q)	As of March 31, 2016, ACE's regulatory liability of $10 million related to over-recovered transmission costs. As of December 31, 2015, ACE's regulatory liability of $8 million related to over-recovered transmission costs.


(r)	Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

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 and ACE are required to purchase receivables at face value and are permitted to recover uncollectible accounts expense from customers through distribution rates. 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 March 31, 2016 and December 31, 2015.



													Successor
As of March 31, 2016	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(c)	$	343		$	96		$	75		$	66		$	106		$	77		$	11	$	18
Allowance for uncollectible accounts^(a)	(38		)	(16		)	(8		)	(8		)	(6		)	(4		)	—		(2		)
Purchased receivables, net	$	305		$	80		$	67		$	58		$	100		$	73		$	11	$	16



													Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(b)	$	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, DPL and ACE, 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 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.

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)	3 Months Ended
	Mar. 31, 2016
Equity Method Investments and Joint Ventures [Abstract]
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)	Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation) PROPOSED DELETION - OPEN TO DISCUSS WITH EFR As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements, see Note 26 — Related Party Transactions of the Exelon 2015 Form 10-K. As a result of the consolidation of CENG on April 1, 2014, there are several additional transactions included in Exelon’s and Generation’s consolidated financial statements between CENG and Exelon's affiliates that are considered related party transactions to Generation. As further described in Note 26 — Related Party Transactions of the Exelon 2015 Form 10-K, EDF and Generation have a PPA with CENG under which they purchased 15% and 85%, respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs through December 31, 2014. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG not subject to other contractual agreements. Beginning April 1, 2014, sales to Generation have been eliminated in consolidation. For the three months ended March 31, 2016, Generation had sales to EDF of $288 million. See discussion above and Note 3 — Variable Interest Entities for additional information regarding other transactions between CENG and EDF included within Exelon and Generation’s financial statements and for additional information about the Registrants VIEs. Accounting for the Consolidation of CENG Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in earnings of unconsolidated affiliates related to its investment in CENG and $17 million of revenues from CENG. The book value of Generation’s investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million. The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s Consolidated Balance Sheets. Generation and EDFI also entered into a Put Option Agreement on April 1, 2014, pursuant to which EDFI has the option, exercisable beginning on January 1, 2016 and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99% interest in CENG under the Put Option Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation’s rights with respect to any unpaid aggregate preferred distributions and the related return, and the value of Generation’s rights to other distributions. The beginning of the exercise period will be accelerated if Exelon’s affiliates cease to own a majority of CENG and exercise a related right to terminate the NOSA. In addition, under limited circumstances, the period for exercise of the put option may be extended for 18 months. Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interest on the Consolidated Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’s net assets. For the three months ended March 31, 2016, Generation reduced by $4 million and $9 million, respectively, the amount of Net income attributable to noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $109 million and $306 million and CENG’s net (loss) income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $(4) million and $93 million during the three months ended March 31, 2016, respectively.

Impairment of Long-lived Assets (Exelon and Generation)

3 Months Ended

Mar. 31, 2016

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 at March 31, 2016. 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. After reflecting the impairment charges, Generation has $63 million of Upstream assets remaining on its Consolidated Balance Sheets at March 31, 2016. 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.

The fair value analysis was primarily based on the income approach using significant unobservable inputs (Level 3) including commodity prices and production volumes, projected capital and maintenance expenditures and discount rates.

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.

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

3 Months Ended

Mar. 31, 2016

Implications Of Potential Early Retirement Disclosure [Text Block]

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

Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions in New York and Illinois such as the recently proposed Zero Emission Standard element of the Next Generation Energy Plan (NGEP) or Low Carbon Portfolio Standard (LCPS) legislation in Illinois and Clean Energy Standard (CES) in New York, the impact of final rules from the EPA requiring reduction of carbon and other emissions and the efforts of the states to implement those final rules.

In 2015, 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 auction to be 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. The results of the 2019-2020 PJM capacity auction will be available on May 24, 2016.

On May 6, 2016 Exelon and Generation announced intentions to shut down the Clinton nuclear plant on June 1, 2017 and Quad Cities nuclear plant on June 1, 2018 if Illinois does not pass adequate legislation by May 31, 2016 and if Quad Cities does not clear the 2019-2020 PJM capacity auction. Exelon and Generation previously committed to cease operation of the Oyster Creek nuclear plant by the end of 2019. The approved RSSA requires Ginna to continue operating through the RSSA term expiring in March 2017. There remains an increased risk that, for economic reasons, Ginna could be retired before the end of its operating license period in 2029 if an adequate regulatory or legislative solution is not adopted in New York. Refer to Note 5 - Regulatory Matters for additional discussion on the Ginna RSSA.

In response to a decision to early retire one or more nuclear plants, certain changes in accounting treatment would be triggered and Exelon’s and Generation’s results of operations and cash flows could be materially affected by, among other items: accelerated depreciation expense, impairment charges related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, contract termination fees, accelerated amortization of plant specific nuclear fuel costs, employee-related costs (i.e. severance, relocation, retention, etc.), accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of nuclear decommissioning trust funds. In addition, any early plant retirement would also result in reduced operating costs, lower fuel expense, and lower capital expenditures in the periods beyond shutdown.

The following table provides the balance sheet amounts as of March 31, 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 their current economic valuations and other factors.



(in millions)	Quad Cities			Clinton				Ginna			Total
Asset Balances
Materials and supplies inventory	$	47		$	58			$	30		$	135
Nuclear fuel inventory, net	213			95				54			362
Completed plant, net	1,014			574				127			1,715
Construction work in progress	28			11				11			50
Liability Balances
Asset retirement obligation	(706		)	(407		)		(651		)	(1,764		)

NRC License Renewal Term	2032			2046			^(a)	2029

_________


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

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

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

3 Months Ended

Mar. 31, 2016

Fair Value Disclosures [Abstract]

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

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 March 31, 2016 and December 31, 2015:

Exelon



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	3,643	$	3	$	3,640	$	—	$	3,643
Long-term debt (including amounts due within one year)^(a)	31,372		1,132		29,577		2,135		32,844
Long-term debt to financing trusts^(b)	641		—		—		670		670
SNF obligation	1,022		—		817		—		817



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,529	$	—	$	1,529	$	—	$	1,529
Long-term debt (including amounts due within one year)^(a)	9,052		—		7,539		1,549		9,088
SNF obligation	1,022		—		817		—		817



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	643	$	—	$	643	$	—	$	643
Long-term debt (including amounts due within one year)^(a)	6,510		—		7,357		—		7,357
Long-term debt to financing trusts^(b)	205		—		—		207		207



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,581	$	—	$	2,900	$	—	$	2,900
Long-term debt to financing trusts	184		—		—		196		196



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	153	$	3	$	150	$	—	$	153
Long-term debt (including amounts due within one year)^(a)	1,859		—		2,119		—		2,119
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



	March 31, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,317	$	—	$	1,317	$	—	$	1,317
Long-term debt (including amounts due within one year)	6,132		—		5,540		586		6,126



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,352	$	—	$	2,876	$	—	$	2,876



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	75	$	—	$	75	$	—	$	75
Long-term debt (including amounts due within one year)^(a)	1,265		—		1,238		103		1,341



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,191	$	—	$	1,081	$	288	$	1,369



	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 of $179 million, $72 million, $37 million, $14 million, $9 million, $31 million, $10 million, and $6 million for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE, respectively, as of March 31, 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 of $7 million, $1 million, and $6 million for Exelon, ComEd and BGE, respectively, as of March 31, 2016 and December 31, 2015.

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

Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the 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 three months ended March 31, 2016 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due to changes in market liquidity or assumptions for certain commodity contracts.

Generation and Exelon

In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below. See Note 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 March 31, 2016 and December 31, 2015:



	Generation										Exelon
As of March 31, 2016	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents	$	130	$	—	$	—	$	—	$	130	$	721	$	—	$	—	$	—	$	721
NDT fund investments
Cash equivalents^(a)	266		11		—		—		277		266		11		—		—		277
Equities	3,273		21		1		1,875		5,170		3,273		21		1		1,875		5,170
Fixed income
Corporate debt	—		1,868		243		—		2,111		—		1,868		243		—		2,111
U.S. Treasury and agencies	1,402		13		—		—		1,415		1,402		13		—		—		1,415
Foreign governments	—		45		—		—		45		—		45		—		—		45
State and municipal debt	—		285		—		—		285		—		285		—		—		285
Other^(b)	—		64		—		376		440		—		64		—		376		440
Fixed income subtotal	1,402		2,275		243		376		4,296		1,402		2,275		243		376		4,296
Middle market lending	—		—		440		—		440		—		—		440		—		440
Private equity	—		—		—		130		130		—		—		—		130		130
Real estate	—		—		—		40		40		—		—		—		40		40
Other	—		—		—		190		190		—		—		—		190		190
NDT fund investments subtotal^(c)	4,941		2,307		684		2,611		10,543		4,941		2,307		684		2,611		10,543
Pledged assets for Zion Station decommissioning
Cash equivalents	35		—		—		—		35		35		—		—		—		35
Equities	1		7		—		—		8		1		7		—		—		8
Fixed income
U.S. Treasury and agencies	3		2		—		—		5		3		2		—		—		5



	Generation														Exelon
As of March 31, 2016	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Corporate debt	—			25			—			—		25			—			25			—			—		25
Fixed income subtotal	3			27			—			—		30			3			27			—			—		30
Middle market lending	—			—			25			85		110			—			—			25			85		110
Pledged assets for Zion Station decommissioning subtotal^(d)	39			34			25			85		183			39			34			25			85		183
Rabbi trust investments
Cash equivalents	9			—			—			—		9			83			—			—			—		83
Mutual funds	17			—			—			—		17			46			—			—			—		46
Fixed income	—			—			—			—		—			—			14			—			—		14
Life insurance contracts	—			16			—			—		16			—			60			20			—		80
Rabbi trust investments subtotal	26			16			—			—		42			129			74			20			—		223
Commodity derivative assets
Economic hedges	1,591			4,849			1,788			—		8,228			1,591			4,849			1,788			—		8,228
Proprietary trading	31			82			30			—		143			31			82			30			—		143
Effect of netting and allocation of collateral^(e)	(1,739		)	(3,997		)	(675		)	—		(6,411		)	(1,739		)	(3,997		)	(675		)	—		(6,411		)
Commodity derivative assets subtotal	(117		)	934			1,143			—		1,960			(117		)	934			1,143			—		1,960
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			42			—			—		42
Economic hedges	—			20			—			—		20			—			20			—			—		20
Proprietary trading	11			2			—			—		13			11			2			—			—		13
Effect of netting and allocation of collateral	(4		)	(5		)	—			—		(9		)	(4		)	(5		)	—			—		(9		)
Interest rate and foreign currency derivative assets subtotal	7			17			—			—		24			7			59			—			—		66
Other investments	—			—			36			—		36			—			—			36			—		36
Total assets	5,026			3,308			1,888			2,696		12,918			5,720			3,408			1,908			2,696		13,732
Liabilities
Commodity derivative liabilities
Economic hedges	(2,053		)	(4,688		)	(885		)	—		(7,626		)	(2,054		)	(4,688		)	(1,150		)	—		(7,892		)
Proprietary trading	(28		)	(79		)	(37		)	—		(144		)	(28		)	(79		)	(37		)	—		(144		)
Effect of netting and allocation of collateral^(e)	2,089			4,535			826			—		7,450			2,090			4,535			826			—		7,451
Commodity derivative liabilities subtotal	8			(232		)	(96		)	—		(320		)	8			(232		)	(361		)	—		(585		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(20		)	—			—		(20		)	—			(23		)	—			—		(23		)
Economic hedges	—			(8		)	—			—		(8		)	—			(8		)	—			—		(8		)
Proprietary trading	(11		)	—			—			—		(11		)	(11		)	—			—			—		(11		)
Effect of netting and allocation of collateral	11			5			—			—		16			11			5			—			—		16
Interest rate and foreign currency derivative liabilities subtotal	—			(23		)	—			—		(23		)	—			(26		)	—			—		(26		)
Deferred compensation obligation	—			(30		)	—			—		(30		)	—			(131		)	—			—		(131		)
Total liabilities	8			(285		)	(96		)	—		(373		)	8			(389		)	(361		)	—		(742		)
Total net assets	$	5,034		$	3,023		$	1,792		$	2,696	$	12,545		$	5,728		$	3,019		$	1,547		$	2,696	$	12,990



	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	$	104		$	—		$	—		$	—	$	104		$	5,766		$	—		$	—		$	—	$	5,766
NDT fund investments
Cash equivalents^(a)	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^(b)	—			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^(c)	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^(d)	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^(e)	(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^(e)	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)	Includes $38 million and $52 million of cash received from outstanding repurchase agreements at March 31, 2016 and December 31, 2015, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (c) below.

(b)

Includes derivative instruments of $(11) million and $(8) million, which have a total notional amount of $1,155 million and $1,236 million at March 31, 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.

(c)

Excludes net liabilities of $(17) million and $(3) million at March 31, 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.


(d)	Excludes net assets of $0 million and $1 million at March 31, 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.

(e)

Collateral posted to/(received) from counterparties totaled $350 million, $538 million and $151 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 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 March 31, 2016 and December 31, 2015:



	ComEd											PECO										BGE
As of March 31, 2016	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	—	$	—		$	—		$	—		$	3	$	—		$	—	$	3		$	43	$	—		$	—	$	43
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			4		—			—		4
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			4		—			—		4
Total assets	—		—			—			—			11		11			—		22			47		—			—		47
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(12		)	—		(12		)	—		(3		)	—		(3		)
Mark-to-market derivative liabilities^(a)	—		—			(265		)	(265		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(265		)	(273		)	—		(12		)	—		(12		)	—		(3		)	—		(3		)
Total net assets (liabilities)	$	—	$	(8	)	$	(265	)	$	(273	)	$	11	$	(1	)	$	—	$	10		$	47	$	(3	)	$	—	$	44



	ComEd											PECO										BGE
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments
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^(a)	—		—			(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)	The Level 3 balance consists of the current and noncurrent liability of $26 million and $239 million, respectively, at March 31, 2016, and $23 million and $224 million, respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

PHI, Pepco, DPL and ACE

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



	Successor											Predecessor
	As of March 31, 2016											As of December 31, 2015
PHI	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents	$	168		$	—		$	—	$	168		$	42		$	—		$	—	$	42
Derivative asset	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			14			—		14			—			15			—		15
Life insurance contracts	—			22			20		42			—			27			19		46
Rabbi trust investments subtotal	73			36			20		129			12			42			19		73
Total assets	241			36			20		297			54			42			37		133
Liabilities
Deferred compensation obligation	—			(30		)	—		(30		)	—			(30		)	—		(30		)
Mark-to-market derivative liabilities(a)	(1		)	—			—		(1		)	(2		)	—			—		(2		)
Effect of netting and allocation of collateral	1			—			—		1			2			—			—		2
Mark-to-market derivative liabilities subtotal	—			—			—		—			—			—			—		—
Total liabilities	—			(30		)	—		(30		)	—			(30		)	—		(30		)
Total net assets	$	241		$	6		$	20	$	267		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of March 31, 2016	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	19	$	—		$	—	$	19		$	—		$	—		$	—	$	—		$	148	$	—	$	—	$	148
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		14			—		14			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			20		42			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		36			20		99			—			—			—		—			—		—		—		—
Total assets	62		36			20		118			—			—			—		—			148		—		—		148
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities^(a)	—		—			—		—			(1		)	—			—		(1		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	62	$	31		$	20	$	113		$	—		$	(1	)	$	—	$	(1	)	$	148	$	—	$	—	$	148



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

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 months ended March 31, 2016 and 2015:



																			Successor
	Generation															ComEd			PHI^(a)					Exelon
Three Months Ended March 31, 2016	NDT Fund Investments				Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(b)			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				—		(6		)	^(c)	—		(4		)	—			—		—			(4		)
Included in noncurrent payables to affiliates	4				—		—				—		4			—			—		(4		)	—
Included in payable for Zion Station decommissioning	—				2		—				—		2			—			—		—			2
Included in regulatory assets/liabilities	—				—		—				—		—			(18		)	—		4			(14		)
Change in collateral	—				—		(50		)		—		(50		)	—			—		—			(50		)
Purchases, sales, issuances and settlements
Purchases	34				1		59				3		97			—			—		—			97
Sales	—				—		(2		)		—		(2		)	—			—		—			(2		)
Settlements	(26		)		—		—				—		(26		)	—			—		—			(26		)
Transfers into Level 3	—				—		2				—		2			—			—		—			2
Transfers out of Level 3	—				—		(7		)		—		(7		)	—			—		—			(7		)
Balance as of March 31, 2016	$	684			$	25	$	1,047			$	36	$	1,792		$	(265	)	$	20	$	—		$	1,547
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2016	$	1			$	—	$	219			$	—	$	220		$	—		$	—	$	—		$	220



	Generation															ComEd						Exelon
Three Months Ended March 31, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of December 31, 2014	$	605		$	50		$	1,050			$	3	$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income	2			—			(32		)	^(c)	—		(30		)	—			—			(30		)
Included in other comprehensive income	—			—			—				—		—			—			—			—
Included in noncurrent payables to affiliates	10			—			—				—		10			—			(10		)	—
Included in payable for Zion Station decommissioning	—			3			—				—		3			—			—			3
Included in regulatory assets	—			—			—				—		—			(34		)	10			(24		)
Change in collateral	—			—			12				—		12			—			—			12
Purchases, sales, issuances and settlements
Purchases	28			—			41				—		69			—			—			69
Sales	(8		)	(9		)	—				—		(17		)	—			—			(17		)
Settlements	(29		)	—			—				—		(29		)	—			—			(29		)
Transfers into Level 3	4			—			—				—		4			—			—			4
Transfers out of Level 3	—			—			(5		)		—		(5		)	—			—			(5		)
Balance as of March 31, 2015	$	612		$	44		$	1,066			$	3	$	1,725		$	(241	)	$	—		$	1,484
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2015	$	1		$	—		$	180			$	—	$	181		$	—		$	—		$	181

_________


(a)	Successor period represents activity from March 24, 2016 through March 31, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco and DPL for the three months ended March 31, 2016 and 2015.

(b)

Includes $25 million of decreases in fair value and realized losses due to settlements of $7 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2016. Includes $36 million of decreases in fair value and realized losses due to settlements of $2 million for the three months ended March 31, 2015.


(c)	Includes a reduction for the reclassification of $225 million and $212 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2016 and 2015, respectively.



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



	Three Months Ended March 31, 2016				Three Months Ended March 31, 2015
	Pepco		DPL		Pepco		DPL
	Life Insurance Contracts		Life Insurance Contracts		Life Insurance Contracts		Life Insurance Contracts
Balance as of December 31	$	19	$	—	$	18	$	1
Total realized / unrealized gains (losses)
Included in net income	1		—		1		—
Purchases, sales, issuances and settlements
Settlements	—		—		—		(1		)
Balance as of March 31	$	20	$	—	$	19	$	—
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities for the period	$	1	$	—	$	1	$	—

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 months ended March 31, 2016 and 2015:




	Generation				Exelon
	Operating Revenues	Purchased Power and Fuel		Other, net^(b)	Operating Revenues	Purchased Power and Fuel		Other, net^(b)
Total gains (losses) included in net income for the three months ended March 31, 2016	49	(55	)	2	49	(55	)	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2016	254	(35	)	1	254	(35	)	1



	Generation					Exelon
	Operating Revenues		Purchased Power and Fuel		Other, net^(b)	Operating Revenues		Purchased Power and Fuel		Other, net^(b)
Total gains (losses) included in net income for the three months ended March 31, 2015	(10	)	(22	)	2	(10	)	(22	)	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2015	169		11		1	169		11		1



	Predecessor
	PHI					Pepco
	January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015		Three Months Ended March 31, 2016		Three Months Ended March 31, 2015
	Other, net
Total (losses) gains included in net income	$	(17	)	$	1	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held	1			1		1		1

_________


(a)	Successor period represents activity for the period of March 24, 2016 through March 31, 2016.


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

Valuation Techniques Used to Determine Fair Value

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

Cash Equivalents (Exelon, Generation, ComEd, PECO, 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 preferred 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, balanced and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives such as holding short term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For commingled funds and mutual funds, which are not publicly quoted, the 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 March 31, 2016, Generation has outstanding commitments to invest in middle market lending, private equity investments and real estate investments of approximately $142 million, $42 million, and $135 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 March 31, 2016. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of March 31, 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 and DPL). 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 and DPL). 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, PECO, 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 $2.82 and $0.25 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 March 31, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	903		Discounted Cash Flow	Forward power price	$7	-	$88
					Forward gas price	$0.58	-	$7.67
				Option Model	Volatility percentage	5%	-	184%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$9	-	$83
Mark-to-market derivatives (Exelon and ComEd)	$	(265	)	Discounted Cash Flow	Forward heat rate^(b)	9x	-	10x
					Marketability reserve	3.5%	-	7%
					Renewable factor	88%	-	129%

_________


(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 $151 million as of March 31, 2016.



Type of trade	Fair Value at December 31, 2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11	-	$88
					Forward gas price	$1.18	-	$8.95
				Option Model	Volatility percentage	5%	-	152%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13	-	$78
Mark-to-market derivatives (Exelon and ComEd)	$	(247	)	Discounted Cash Flow	Forward heat rate^(b)	9x	-	10x
					Marketability reserve	3.5%	-	7%
					Renewable factor	87%	-	128%

_________


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


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


(c)	The fair values do not include cash collateral held 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, Generation, PECO, PHI, Pepco and DPL) 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 (Exelon, Generation, ComEd, PECO and BGE)

3 Months Ended

Mar. 31, 2016

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

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. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 23 — Commitments and Contingencies of the Exelon 2015 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.

Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies and other factors. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of March 31, 2016, the proportion of expected generation hedged for the major reportable segments is 96%-99%, 69%-72% and 37%-40% 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 2015 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2015 PGC settlement, PECO is required to lock in (i.e. economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.

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

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

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 1,220 GWhs and 1,808 GWhs for the three months ended March 31, 2016 and 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 March 31, 2016, Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $1,287 million and $687 million of notional amounts of floating-to-fixed hedges outstanding, respectively. Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an approximately $1 million decrease in Exelon Consolidated pre-tax income for the three months ended March 31, 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 March 31, 2016.



	Generation															Exelon Corporate			Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments			Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	8		$	(5	)	$	13		$	—		$	13
Mark-to-market derivative assets (noncurrent assets)	—			10			5			(4		)	11			42			53
Total mark-to-market derivative assets	—			20			13			(9		)	24			42			66
Mark-to-market derivative liabilities (current liabilities)	(8		)	(3		)	(6		)	9			(8		)	—			(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(12		)	(5		)	(5		)	7			(15		)	(3		)	(18		)
Total mark-to-market derivative liabilities	(20		)	(8		)	(11		)	16			(23		)	(3		)	(26		)
Total mark-to-market derivative net assets (liabilities)	$	(20	)	$	12		$	2		$	7		$	1		$	39		$	40

_________

(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 March 31,
	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	17		9			(15		)	(7		)

__________


(a)	For the three months ended March 31, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

At March 31, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a derivative asset of $42 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 months ended March 31, 2016 and 2015, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $2 million gain for each period.

Cash Flow Hedges. During the first quarter of 2016, Exelon entered into $600 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated issuance of debt. The swaps are designated as cash flow hedges. At March 31, 2016, Exelon had a $3 million derivative liability related to the swaps.

During the first quarter of 2016, Exelon entered into $100 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 swap is 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. See Note10 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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 $499 million as of March 31, 2016 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At March 31, 2016, the subsidiary had a $17 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 $189 million as of March 31, 2016 and expire in 2020. The swaps are designated as cash flow hedges. At March 31, 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 months ended March 31, 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 March 31, 2016, Generation had immaterial notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $137 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 March 31, 2016 and December 31, 2015, $1 million and $3 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.

ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e. to BB+ or Ba1).

Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.

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

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



																							Successor
	Generation												ComEd			DPL							PHI		Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)			Collateral and Netting^(a)		Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,851		$	113		$	(4,792	)	$	1,172		$	—		$	—		$	—	$	—	$	—	$	1,172
Mark-to-market derivative assets (noncurrent assets)	2,377			30			(1,619		)	788			—			—			—		—		—		788
Total mark-to-market derivative assets	8,228			143			(6,411		)	1,960			—			—			—		—		—		1,960
Mark-to-market derivative liabilities (current liabilities)	(5,570		)	(104		)	5,505			(169		)	(26		)	(1		)	1		—		—		(195		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(2,056		)	(40		)	1,945			(151		)	(239		)	—			—		—		—		(390		)
Total mark-to-market derivative liabilities	(7,626		)	(144		)	7,450			(320		)	(265		)	(1		)	1		—		—		(585		)
Total mark-to-market derivative net assets (liabilities)	$	602		$	(1	)	$	1,039		$	1,640		$	(265	)	$	(1	)	$	1	$	—	$	—	$	1,375

______

(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 $303 million and $146 million, respectively, and current and noncurrent liabilities are shown net of collateral of $410 million and $180 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,039 million at March 31, 2016.


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


(d)	Represents natural gas futures purchased as part 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 as part 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 three months ended March 31, 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 March 31, 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		(8		)		(10		)
Reclassifications from AOCI to net income	Interest Expense	3			^(a)	3			^(a)
Accumulated OCI derivative loss at March 31, 2016		$	(26	)		$	(26	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended March 31, 2015	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2014		$	(18	)	$	(28	)
Effective portion of changes in fair value		(6		)	(11		)
Reclassifications from AOCI to net income	Other, net	—			16			^(b)
Reclassifications from AOCI to net income	Interest Expense	3			3
Reclassifications from AOCI to net income	Operating Revenues	(2		)	(2		)
Accumulated OCI derivative loss at March 31, 2015		$	(23	)	$	(22	)

______


(a)	Amount is net of related income tax expense of $2 million for both the three months ended March 31, 2016.


(b)	Amount is net of related income tax benefit of $10 million for the three months ended March 31, 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 three months ended March 31, 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 months ended March 31, 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 March 31, 2016	Operating Revenues			Purchased Power and Fuel			Total			Total
Change in fair value of commodity positions	$	279		$	(127	)	$	152		$	152
Reclassification to realized at settlement of commodity positions	(211		)	167			(44		)	(44		)
Net commodity mark-to-market gains (losses)	68			40			108			108
Change in fair value of treasury positions	(3		)	—			(3		)	(3		)
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	(2		)
Net treasury mark-to-market gains (losses)	(5		)	—			(5		)	(5		)
Net mark-to-market gains (losses)	$	63		$	40		$	103		$	103



	Generation									Exelon Corporate			Exelon
Three Months Ended March 31, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense			Total
Change in fair value of commodity positions	$	164		$	(79	)	$	85		$	—		$	85
Reclassification to realized at settlement of commodity positions	(21		)	87			66			—			66
Net commodity mark-to-market gains (losses)	143			8			151			—			151
Change in fair value of treasury positions	13			—			13			(78		)	(65		)
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	—			(2		)
Net treasury mark-to-market gains (losses)	11			—			11			(78		)	(67		)
Net mark-to-market gains (losses)	$	154		$	8		$	162		$	(78	)	$	84

Proprietary Trading Activities (Exelon and Generation). For the three months ended March 31, 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.



	Location on Income Statement	Three Months Ended March 31,
	Location on Income Statement	2016			2015
Change in fair value of commodity positions	Operating Revenues	$	7		$	1
Reclassification to realized at settlement of commodity positions	Operating Revenues	(3		)	2
Net commodity mark-to-market gains (losses)	Operating Revenues	4			3
Change in fair value of treasury positions	Operating Revenues	(2		)	4
Reclassification to realized at settlement of treasury positions	Operating Revenues	1			(4		)
Net treasury mark-to-market gains (losses)	Operating Revenues	(1		)	—
Total net mark-to-market gains (losses)	Operating Revenues	$	3		$	3

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 March 31, 2016. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, 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 $19 million, $37 million,$35 million, $36 million, $11 million, and $8 million as of March 31, 2016, respectively.



Rating as of March 31, 2016	Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,276	$	58	$	1,218	1	$	436
Non-investment grade	71		32		39		—	—
No external ratings
Internally rated — investment grade	516		1		515		—	—
Internally rated — non-investment grade	101		4		97		—	—
Total	$	1,964	$	95	$	1,869	1	$	436



Net Credit Exposure by Type of Counterparty	As of March 31, 2016
Financial institutions	$	116
Investor-owned utilities, marketers, power producers	781
Energy cooperatives and municipalities	909
Other	63
Total	$	1,869

_____


(a)	As of March 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $8 million of cash and $87 million of letters of credit.

ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of March 31, 2016, ComEd’s net credit exposure to suppliers was immaterial .

ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters 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 March 31, 2016, PECO had no net credit exposure to suppliers.

PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 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 March 31, 2016, PECO had no 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 March 31, 2016, BGE had no net credit exposure to suppliers.

BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At March 31, 2016, BGE had credit exposure of $2 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 March 31, 2016, Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.

Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy costs through customer rates. See Note 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 March 31, 2016, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.

Collateral and Contingent-Related Features (All Registrants)

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

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



Credit-Risk Related Contingent Feature	March 31, 2016			December 31, 2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(979	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	728			684
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(251	)	$	(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 $1,063 million and letters of credit posted of $519 million and cash collateral held of $16 million and letters of credit held of $96 million as of March 31, 2016 for external counterparties with derivative positions. Generation had cash collateral posted of $1,267 million and letters of credit posted of $497 million and cash collateral held of $21 million and letters of credit held of $78 million at December 31, 2015 for external counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e. to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $1.9 billion and $2.0 billion as of March 31, 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 March 31, 2016, Generation and Exelon's swaps were in an asset position, with a fair value of $1 million and $40 million, respectively.

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 March 31, 2016, ComEd held no collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of March 31, 2016, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. If ComEd lost its investment grade credit rating as of March 31, 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 March 31, 2016, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of March 31, 2016, PECO could have been required to post approximately $22 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 March 31, 2016, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2016, BGE could have been required to post approximately $28 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 derivative contracts contain provisions that could require DPL to post collateral in an amount equal to the unsecured credit threshold if exceeded when the aggregate fair value of the transactions is in a net loss position. The obligations of DPL are standalone obligations without the guaranty of PHI. Exchange-traded contracts are required to be fully collateralized without regard to the credit rating of the holder.

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 (Exelon, Generation, ComEd, PECO and BGE)

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

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

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 commercial paper, 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 March 31, 2016 and December 31, 2015:



Commercial Paper Borrowings	March 31, 2016		December 31, 2015
Generation	$	1,378	$	—
ComEd	643		294
BGE	150		210
PHI Corporate	442		484
Pepco	—		64
DPL	75		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, 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 July 28, 2016. 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%. As of March 31, 2016, $25 million was outstanding under each note. The $25 million note outstanding between Generation and CENG is eliminated in consolidation and therefore not reflected in Exelon's or Generation's Consolidated Balance Sheets. The $25 million note with EDF is reflected in Exelon's and Generation's Consolidated Balance Sheet within Short-term borrowings.

Credit Agreements

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

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

Variable Rate Demand Bonds

As of March 31, 2016 and December 31, 2015, $105 million in variable rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year on Exelon's, PHI's and DPL's Consolidated Balance Sheet. See Note 10 - Debt of the PHI 2015 Form 10-K for additional information.

Long-Term Debt

Issuance of Long-Term Debt

During the three months ended March 31, 2016, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Albany Green Energy Project Financing

LIBOR + 1.25%

November 17, 2017

Albany Green Energy biomass generation development

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.

On April 7, 2016, Exelon issued and sold $1.8 billion in aggregate principal amount of notes consisting of $300 million of 2.45% Notes due 2021, $750 million of 3.40% Notes due 2026 and $750 million of 4.45% Notes due 2046. A portion of the proceeds of the notes will be used to repay commercial paper issued by PHI and for general corporate purposes, which may include the repayment of outstanding indebtedness.

Retirement and Redemptions of Long-Term Debt

During the three months ended March 31, 2016, the following long-term debt was retired and/or redeemed:



Company	Type	Interest Rate	Maturity	Amount
Generation	AVSR DOE Nonrecourse Debt	2.29 - 3.56%	January 5, 2037	$	5
Generation	Continental Wind Nonrecourse Debt	6.00%	February 28, 2033	$	15
Generation	CEU Upstream Nonrecourse Debt	LIBOR + 2.75%	January 14, 2019	$	7
Generation	ExGen Texas Power Nonrecourse Debt	5.00%	September 18, 2021	$	2
Generation	Sacramento PV Energy Nonrecourse Debt	2.58%	December 31, 2030	$	33
Generation	Constellation Solar Horizons Nonrecourse Debt	2.56%	September 7, 2030	$	32
Generation	Kennett Square Capital Lease	7.83%	September 20, 2020	$	1
ACE	ACE Funding Transition Bonds	5.55%	October 20, 2023	$	8
ACE	ACE Funding Transition Bonds	5.05%	October 20, 2020	$	3

On April 1, 2016, BGE paid down $1 million of principal of its 5.72% Rate Stabilization Bonds due 2016 and $38 million of principal of its 5.82% Rate Stabilization Bonds due 2017.

On April 5, 2016, Generation paid down $1 million of principal of its 2.29% - 3.56% AVSR DOE Nonrecourse debt.

On April 15, 2016, Generation paid down $10 million of principal of its 5.25% ExGen Renewables I Nonrecourse debt.

On April 20, 2016, ACE paid down $8 million of principal of its 5.55% ACE Funding Transition Bonds and $3 million of principal of its 5.05% ACE Funding Transition Bonds.

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.

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. CEU Holdings is currently in discussions with the lenders regarding the resolution of the matter. The resolution could include negotiating a forbearance agreement that would provide for the potential sale of Upstream assets in order to wind down the Upstream business of CEU Holdings. Consistent with these discussions, the RBL lenders have not yet accelerated the debt outstanding under the RBL. However, 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. 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. 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 and Note 6 - Impairment of Long-Lived Assets for additional information.

Other Financing Activities

Accounts Receivable Agreement

In February 2016, PES entered into an accounts receivable sales agreement with a financing institution in which PES will borrow approximately $41 million to complete the construction of an energy efficiency project that is expected to be completed in 2018. Pursuant to the assignment of PES' rights to the customer receivables to the financing institution, upon customer acceptance of the energy efficiency project, the customer will pay the financing institution over a 16 year period. At March 31, 2016, PES has borrowed $3 million under the contract which is classified as Long-term debt due within one year on Exelon's and Generation's Consolidated Balance Sheet.

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

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

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

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:



									Successor	Predecessor
	Three Months Ended March 31, 2016								March 24, 2016 to March 31, 2016	January 1, 2016 to March 23, 2016
	Exelon	Generation	ComEd	PECO	BGE	Pepco^(a)	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)	(1.1)	3.7	5.1	1.0	5.2	(2.5)	(2.7)	5.9	5.4	11.9
Qualified nuclear decommissioning trust fund income	5.6	4.2	—	—	—	—	—	—	—	—
Domestic production activities deduction	—	—	—	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.6)	(1.0)	(0.3)	(0.1)	(0.1)	—	0.1	0.2	—	(0.9)
Plant basis differences	(5.5)	—	(0.1)	(9.3)	(0.6)	2.8	0.7	0.6	—	(13.5)
Production tax credits and other credits	(5.1)	(3.9)	—	—	—	—	—	—	—	—
Non-controlling interest	0.5	0.3	—	—	—	—	—	—	—	—
Merger expenses	33.6	—	—	—	—	(16.5)	(22.1)	(17.0)	(15.1)	11.1
Other	(2.0)	(1.6)	0.4	(0.9)	—	—	0.1	0.1	0.2	3.6
Effective income tax rate	59.4%	36.7%	40.1%	25.7%	39.5%	18.8%	11.1%	24.8%	25.5%	47.2%



	Three Months Ended March 31, 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	2.6	2.7	5.0	1.2	5.3	7.2	5.3	5.7	5.9
Qualified nuclear decommissioning trust fund income	1.9	3.0	—	—	—	—	—	—	—
Domestic production activities deduction	(2.2)	(3.4)	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	0.2	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(1.4)	(0.3)	(0.1)	—	(0.5)	(0.1)	(0.2)	(1.4)
Plant basis differences	(1.3)	—	(0.3)	(6.7)	(0.3)	(4.9)	(8.5)	(0.9)	(2.8)
Production tax credits and other credits	(1.8)	(2.8)	—	—	—	—	—	—	—
Non-controlling interest	(0.7)	(1.1)	—	—	—	—	—	—	—
Other	0.4	(0.2)	0.2	—	0.2	(0.7)	(0.1)	—	(1.0)
Effective income tax rate	33.0%	31.8%	39.6%	29.4%	40.4%	36.1%	31.6%	39.6%	35.7%

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

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

Accounting for Uncertainty in Income Taxes

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



												Successor
	Exelon		Generation		ComEd			PECO		BGE		PHI		Pepco		DPL		ACE
March 31, 2016	$	950	$	531	$	(12	)	$	—	$	120	$	168	$	86	$	39	$	24



											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 March 31, 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 $177 million, $146 million, $78 million, $36 million and $24 million, respectively.

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

Like-Kind Exchange

As of March 31, 2016, Exelon and ComEd have approximately $75 million and $(12) million of unrecognized state income tax benefits that could significantly decrease and increase, respectively, within the 12 months after the reporting date as a result of a decision or settlement in the like-kind exchange litigation described below. These unrecognized tax benefits, if recognized, would decrease Exelon’s effective tax rate by $75 million and increase ComEd’s effective tax rate by $12 million.

Settlement of Income Tax Audits and Litigation

As of March 31, 2016, Exelon, Generation, BGE, Pepco, and DPL have approximately $270 million, $67 million, $120 million, $63 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 $67 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefits related to BGE, Pepco, and DPL, 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 has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $90 million for a substantial understatement of tax.

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

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

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

On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on December 13, 2013 to initiate litigation in the United States Tax Court and the trial took place in August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. While the Tax Court could reach its decision as early as 2016, the litigation could take three to five years if an appeal is necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision in Consolidated Edison.

In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, as of March 31, 2016, potential tax of $460 million and after-tax interest of $300 million, exclusive of penalties, could become payable (net of a $65 million deposit made to the IRS in 2015). Of the above amounts, approximately $275 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless. Interest will continue to accrue until such time as payment is made. An appeal of an adverse decision in the Tax Court would necessitate either the posting of a bond or the payment of the tax and interest for the tax years before the court.

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. As a result of the lease terminations, any remaining tax gain related to the LKE position taken in 1999 will no longer be deferred. In the event of a successful outcome in the litigation, Exelon will not be required to pay the after-tax interest described in the preceding paragraph ($300 million as of March 31, 2016) but will be required to report the remaining $460 million of tax due on the transaction in Exelon's 2014 and 2016 tax years. Of that approximately $230 million is attributable to ComEd. The tax liabilities from the terminations will not result in a current year cash outflow due to the utilization of net operating losses and tax credit carryforwards.

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

Exelon and Generation 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 and Generation 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)

3 Months Ended

Mar. 31, 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 generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

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



Nuclear decommissioning ARO at December 31, 2015^(a)	$	8,246
Accretion expense	106
Net increase due to changes in, and timing of, estimated cash flows	60
Nuclear decommissioning ARO at March 31, 2016^(a)	$	8,412

_________


(a)	Includes $6 million and $7 million as the current portion of the ARO at March 31, 2016 and December 31, 2015 which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

During the three months ended March 31, 2016, Generation’s ARO increased by approximately $60 million primarily driven by a number of individually small items, which were included within the estimated costs to decommission the Oyster Creek nuclear unit as a result of the completion of an updated decommissioning cost study received during the first quarter.

The financial statement impact related to the increase in the ARO 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. This increase in cost will be amortized over the remaining useful life of the Oyster Creek nuclear unit, which is set to retire by the end of 2019.

Nuclear Decommissioning Trust Fund Investments

At March 31, 2016 and December 31, 2015, Exelon and Generation had NDT fund investments totaling $10,526 million and $10,342 million, respectively.

The following table provides unrealized gains on NDT funds for the three months ended March 31, 2016 and 2015:



	Exelon and Generation
	Three Months Ended March 31,
	2016		2015
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units^(a)	$	79	$	48
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	52		40

_________


(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 $2 million and $10 million of net unrealized gain related to the Zion Station pledged assets for the three months ended March 31, 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 $85 million which is included within the nuclear decommissioning ARO at March 31, 2016. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at March 31, 2016 and December 31, 2015:



	Exelon and Generation
	March 31, 2016		December 31, 2015
Carrying value of Zion Station pledged assets	$	183	$	206
Payable to Zion Solutions^(a)	166		189
Current portion of payable to Zion Solutions^(b)	95		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)	812		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 Unit 1, Braidwood Unit 2, and Byron Unit 2 did not meet the NRC's minimum funding assurance criteria as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017. On February 4, 2016, Generation submitted 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.

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

3 Months Ended

Mar. 31, 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 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 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. The valuation is considered preliminary and Exelon may update these amounts in future quarters to reflect assumptions at March 23, 2016.

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 4.18% 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 4.00%.

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 months ended March 31, 2016 and 2015.



	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,
	2016^(a)			2015			2016^(a)			2015
Components of net periodic benefit cost:
Service cost	$	78		$	82		$	26		$	30
Interest cost	190			178			43			42
Expected return on assets	(263		)	(257		)	(38		)	(38		)
Amortization of:
Prior service cost (benefit)	3			3			(44		)	(43		)
Actuarial loss	127			143			14			20
Net periodic benefit cost	$	135		$	149		$	1		$	11

_______


(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 March 31, 2015			January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015
Service cost	$	12		$	14		$	1		$	2
Interest cost	26			27			6			6
Expected return on assets	(30		)	(35		)	(5		)	(6		)
Amortization of:
Prior service cost (benefit)	—			—			(3		)	(3		)
Actuarial loss	14			16			2			3
Net periodic benefit cost	$	22		$	22		$	1		$	2

The amounts below represent Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, ACE, BSC 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 months ended March 31, 2016 and 2015.



	Three Months Ended March 31,
Pension and Other Postretirement Benefit Costs	2016		2015
Exelon	$	136	$	160
Generation	54		67
ComEd	41		52
PECO	8		10
BGE	16		17
BSC^(a)	14		14
Pepco^(b)	8		8
DPL^(b)	5		4
ACE^(b)	4		4
PHISCO^(a)(b)	9		8



	Successor		Predecessor
Pension and Other Postretirement Benefit Costs	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	3	$	23	$	24

_________


(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, DPL, ACE and PHISCO's pension and postretirement benefit costs for the three months ended March 31, 2016 include $7 million, $4 million, $3 million and $9 million, respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016. PHI, Pepco, DPL, ACE and PHISCO's predecessor pension and other postretirement benefit costs for the three months ended March 31, 2015 were $24 million, $8 million, $4 million, $4 million and $8 million, respectively. These amounts are not included in Exelon’s net periodic benefit cost for the three months ended March 31, 2015 shown in the components of net periodic cost table of the Defined Benefit Pension and Other Postretirement Benefits section above.

Defined Contribution Savings Plans

The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax 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 months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
Savings Plan Matching Contributions	2016		2015
Exelon	$	26	$	22
Generation	12		13
ComEd	6		5
PECO	2		1
BGE	1		2
BSC^(a)	5		1
Pepco^(b)	1		1
DPL^(b)	1		—
PHISCO^(a)(b)	1		2



	Successor		Predecessor
Savings Plan Matching Contributions	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	—	$	3	$	3

_________


(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 three months ended March 31, 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 three months ended March 31, 2016.

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

3 Months Ended

Mar. 31, 2016

Restructuring Charges [Abstract]

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

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.

Exelon and Generation recorded $2 million and $20 million of severance costs associated with these ongoing severance benefits for the three months ended March 31, 2016 and 2015, respectively, within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. For Generation, the amount includes $1 million for amounts billed by BSC through intercompany allocations for the three months ended March 31, 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. The final amount of the charge will ultimately depend on the specific employees severed.

For the three months ended March 31, 2016, the Registrants recorded the following severance costs related to the cost management program within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:



	Exelon		Generation		ComEd		PECO		BGE
Severance benefits^(a)	$	17	$	12	$	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 three months ended March 31, 2016.

Severance Costs Related to the PHI Merger

Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration.

For the three months ended March 31, 2016, the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the authoritative guidance for ongoing severance plans:



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Severance benefits^(a)	$	52	$	10	$	2	$	1	$	1	$	37	$	18	$	11	$	8

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $9 million, $2 million, $1 million, $1 million, $18 million, $11 million and $8 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the three months ended March 31, 2016.

Cash payments under the plan begin in May 2016 and will continue through 2020.

Severance Liability

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:



													Successor
Severance Liability	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2015	$	35		$	23		$	3	$	—	$	1	$	—	$	—	$	—	$	—
Severance charges^(a)(b)	71			7			—		—		—		51		—		—		—
Payments	(4		)	(3		)	—		—		—		—		—		—		—
Balance at March 31, 2016	$	102		$	27		$	3	$	—	$	1	$	51	$	—	$	—	$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.


(b)	Represents activity from March 24, 2016 to March 31, 2016 for PHI, Pepco, DPL and ACE.

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

3 Months Ended

Mar. 31, 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 three months ended March 31, 2016 and 2015:



Three Months Ended March 31, 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	(10		)	(1		)	67			6			(3		)	59
Amounts reclassified from AOCI^(b)	3			—			(34		)	—			—			(31		)
Net current-period OCI	(7		)	(1		)	33			6			(3		)	28
Ending balance	$	(26	)	$	2		$	(2,532	)	$	(34	)	$	(6	)	$	(2,596	)
Generation^(a)
Beginning balance	$	(21	)	$	1		$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	(8		)	—			—			6			(2		)	(4		)
Amounts reclassified from AOCI^(b)	3			—			—			—			—			3
Net current-period OCI	(5		)	—			—			6			(2		)	(1		)
Ending balance	$	(26	)	$	1		$	—		$	(34	)	$	(5	)	$	(64	)
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	—			—			2			—			—			2
Amounts reclassified from AOCI^(b)	—			—			(1		)	—			—			(1		)
Net current-period OCI	—			—			1			—			—			1
Ending balance March 23, 2016^(c)	$	(8	)	$	—		$	(27	)	$	—		$	—		$	(35	)



Three Months Ended March 31, 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	(11		)	—		(26		)	(12		)	—		(49		)
Amounts reclassified from AOCI^(b)	17			—		43			—			—		60
Net current-period OCI	6			—		17			(12		)	—		11
Ending balance	$	(22	)	$	3	$	(2,623	)	$	(31	)	$	—	$	(2,673	)
Generation^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—	$	(36	)
OCI before reclassifications	(6		)	—		—			(12		)	—		(18		)
Amounts reclassified from AOCI^(b)	1			—		—			—			—		1
Net current-period OCI	(5		)	—		—			(12		)	—		(17		)
Ending balance	$	(23	)	$	1	$	—		$	(31	)	$	—	$	(53	)
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			—			—		1
Net current-period OCI	—			—		1			—			—		1
Ending balance	$	(9	)	$	—	$	(36	)	$	—		$	—	$	(45	)

________


(a)	All amounts are net of tax. 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 months ended March 31, 2016 and 2015. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during the three months ended March 31, 2016 and 2015.

Three Months Ended March 31, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)								Affected line item in the Statement of Operations and Comprehensive Income

							Predecessor
	Three Months Ended March 31, 2016			Three Months Ended March 31, 2016			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)	$	(20	)	$	—		$	—
Actuarial losses^(b)	76			—			1
Total before tax	56			—			1
Tax benefit	(22		)	—			—
Net of tax	$	34		$	—		$	1

Total Reclassifications	$	31		$	(3	)	$	1	Comprehensive income

Three Months Ended March 31, 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	(3		)	(3		)	—			Interest expense
Total before tax	(27		)	(1		)	—
Tax benefit	10			—			—
Net of tax	$	(17	)	$	(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 benefit	28			—			1
Net of tax	$	(43	)	$	—		$	(1	)

Total Reclassifications	$	(60	)	$	(1	)	$	(1	)	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 months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
	2016			2015
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	7		$	8
Actuarial loss reclassified to periodic cost	(30		)	(35		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			17
Change in unrealized gain/(loss) on cash flow hedges	3			(2		)
Change in unrealized loss on equity investments	2			—
Change in unrealized gain on marketable securities	1			—
Total	$	(17	)	$	(12	)

Generation
Change in unrealized gain on cash flow hedges	$	2		$	5
Change in unrealized loss on equity investments	2			—
Total	$	4		$	5



	Predecessor
PHI	January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost	$	—	$	(1	)

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.

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Noncontrolling Interest Disclosure [Text Block]

Mezzanine Equity Mezzanine Equity (Exelon, Generation)

3 Months Ended

Mar. 31, 2016

Noncontrolling Interest [Abstract]

16. Mezzanine Equity (Exelon, Generation and PHI)

Contingently Redeemable Noncontrolling Interest (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 interest holder could be contingently redeemable. These circumstances are outside of the control of Generation and the noncontrolling interest holder resulting in a portion of the noncontrolling interest being considered contingently redeemable and thus presented in mezzanine equity on the consolidated balance sheet.

The following table summarizes the changes in the contingently redeemable noncontrolling interest for the three months ended March 31, 2016:



Balance at December 31, 2015	$	28
Cash received from noncontrolling interest	10
Release of contingency	(19		)
Balance at March 31, 2016	$	19

Preferred Stock (PHI)

In connection with the PHI Merger Agreement, Exelon purchased 18,000 originally issued shares of PHI preferred stock for a purchase price of $180 million. PHI excluded the preferred stock from equity at December 31, 2015 since the preferred stock contained conditions for redemption that were not solely within the control of PHI. Management determined that the preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any issued and outstanding preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the preferred stock in the event of such a termination were separately accounted for as derivatives. As of December 31, 2015, the fair value of the derivative related to the preferred stock was estimated to be $18 million based on PHI’s updated assessment and was included in current assets with a corresponding increase in preferred stock on the Consolidated Balance Sheet. Immediately prior to the merger date, PHI updated its assessment of the fair value of the derivative and reduced the fair value to zero, recording the $18 million decrease in fair value as a reduction of Other, net in the predecessor period January 1, 2016 to March 23, 2016.

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.

Common Stock (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
Common Stock (Exelon, Generation, ComEd, PECO and BGE)	Mar. 31, 2016
Common Stock [Abstract]
Common Stock (Exelon, Generation, ComEd, PECO and BGE)	. Shareholder's Equity (Exelon) Equity Securities Offering In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreements by the issuance of 57.5 million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion, which was calculated based on a forward price of $32.48 per share as specified in the forward sale agreements. Use of net proceeds will be to fund the pending acquisition of PHI and related costs and expenses, and for general corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included within the calculation of dilutes EPS using the treasury stock method. Concurrent with the June 2014 forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. See Note 10 — Debt and Credit Agreements for further information on the equity units.

Earnings Per Share and Equity (Exelon)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Earnings Per Share and Equity (Exelon)

Earnings Per Share (Exelon)

Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, 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 March 31,
Exelon	2016		2015
Net income attributable to common shareholders	$	173	$	693
Weighted average common shares outstanding — basic	923		862
Assumed exercise and/or distributions of stock-based awards	2		5
Weighted average common shares outstanding — diluted	925		867

The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 13 million and 15 million for the three months ended March 31, 2016 and 2015, respectively. 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 4 million for the three months ended March 31, 2016 and less than 1 million for the three months ended March 31, 2015. 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 March 31, 2016. In 2008, Exelon management decided to defer indefinitely any share repurchases.

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

3 Months Ended

Mar. 31, 2016

Commitments and Contingencies Disclosure [Abstract]

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

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 $500 million to $600 million relating to Exelon and Generation’s development or assistance in the development of 275 — 300 MWs of new generation in Maryland, which is expected to be completed over a period of 10 years. As of March 31, 2016, Exelon and Generation have incurred $398 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 commitment includes approximately $20 million of in-kind services and 100% of 2015 ESA Investco, LLC's equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 3 - Variable Interest Entities for additional details). As of March 31, 2016, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



	Total
2016^(a)	$	271
2017	21
2018	7
Total	$	299

________


(a)	The noncontrolling interest holder of 2015 ESA Investco, LLC will contribute up to $132 million in support of a portion of the remaining equity commitment.

Commercial Commitments (All Registrants)

The Registrants’ commercial commitments as of March 31, 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)	$	1,628	$	1,560	$	16	$	22	$	2	$	1	$	—	$	—	$	—
Surety bonds^(b)	950		852		10		9		10		16		9		4		3
Financing trust guarantees	628		—		200		178		250		—		—		—		—
Nuclear insurance premiums^(c)	3,056		3,056		—		—		—		—		—		—		—
Guaranteed lease residual values^(d)	20		—		—		—		—		20		6		8		5
Total commercial commitments	$	6,282	$	5,468	$	226	$	209	$	262	$	37	$	15	$	12	$	8

________


(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 $53 million, $13 million of which is a guarantee by Pepco, $17 million by DPL and $14 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 March 31, 2016, the current liability limit per incident is $13.5 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of March 31, 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 103 reactors) resulting in an additional $13.1 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG's related liability.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.5 billion limit for a single incident.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5— Investment in Constellation Energy Nuclear Group, LLC 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 2020.


•	PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2021.

•

BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. 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, 1 of which the remediation has been completed and approved by the MDE. Remediation work at the remaining site has been completed and an application has been submitted to the Delaware Department of Natural Resources and Environmental Control for approval.

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 March 31, 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:



March 31, 2016	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)
Exelon	$	399	$	298
Generation	68		—
ComEd	263		261
PECO	36		34
BGE	3		2
PHI (Successor)	29		1
Pepco	25		—
DPL	3		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.

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 $11 million at March 31, 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 has been 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. While the amount of civil penalties is not known at this time, and Pepco does not expect the amount of such penalties to have a material adverse effect on Exelon’s, PHI’s and Pepco’s consolidated financial condition, results of operations or cash flows, Pepco has established what it believes is an appropriate reserve for this matter.

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 May 16, 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.

Potomac River Mineral Oil Release. In January 2011, there was a release of 4,500 gallons of non-toxic mineral oil at Pepco's Potomac River substation in Alexandria, Virginia into the Potomac River.

In March 2014, Pepco and the District of Columbia Department of Energy and Environment (DOEE) (formerly The District of Columbia Department of the Environment) entered into a consent decree to resolve a threatened DOEE enforcement action, the terms of which include a combination of a civil penalty and a Supplemental Environmental Project (SEP) with a total cost to Pepco of $875,000. The consent decree was approved and entered by the District of Columbia Superior Court on April 4, 2014. Pepco has paid the $250,000 civil penalty imposed under the consent decree and, pursuant to the consent decree, has made a one-time donation in the amount of $25,000 to the Northeast Environmental Enforcement Training Fund, Inc., a non-profit organization that funds scholarships for environmental enforcement training. The consent decree confirmed that no further actions are required by Pepco to investigate, assess or remediate impacts to the river from the mineral oil release. To implement the SEP, Pepco has entered into an agreement with Living Classrooms Foundation, Inc., a non-profit educational organization, pursuant to which Pepco will provide $600,000 to fund the design, installation and operation of a trash collection system at a storm water outfall that drains to the Anacostia River. DOEE approved the design for the trash collection system and efforts to secure necessary permits are in progress. Pepco expects that this system will be constructed and placed into operation by the end of 2016, which will satisfy Pepco’s obligations under the consent decree. On September 11, 2015, Pepco and DOEE filed a joint report with the D.C. Superior Court on the status of the trash cage project and other elements of the consent decree. The court accepted that report and scheduled the next status hearing in this matter for September 23, 2016.

The consent decree did not resolve potential claims under federal law for natural resource damages resulting from the mineral oil release. Pepco has engaged in separate discussions with DOEE and the federal resource trustees regarding the settlement of a possible natural resource damages claim under federal law. In July 2013, Pepco submitted a natural resource damage assessment to DOEE and the federal trustees that proposed monetary compensation for such damages in the range of $106,000 to $161,000. By letter dated September 16, 2015, the U.S. Department of Interior, on behalf of the trustees, made a confidential counter-proposal for settlement of the natural resource damage claim. Pepco has engaged in subsequent discussions with the trustees and believes that the parties are close to reaching an agreement to settle the claims. Based on the discussions to date, Exelon, PHI and Pepco do not believe that the resolution of the natural resource damages claim will have a material adverse effect on their respective financial condition, results of operations or cash flows.

As a result of the mineral oil release, Pepco implemented certain interim operational changes to the secondary containment systems at the facility, which involve pumping accumulated storm water to an above-ground holding tank for off-site disposal. Pepco is continuing to use the above-ground holding tank to manage storm water from the secondary containment system while it evaluates other technical and regulatory options.

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. 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 final 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 mid-2016 to enable the EPA to propose a remedy for public comment by the end of 2016. Thereafter the EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the EPA would require a complete excavation is remote. The EPA is also reviewing a partial excavation remedy; however, until the current sampling is concluded there is no basis to determine the likelihood and estimate of a partial excavation remedy. The current estimated cost of the landfill cover remediation for the site is approximately $60 million, which will be allocated among all PRPs. Recent investigation has identified a number of other parties who may be PRPs and could be liable to contribute to the final remedy. Further investigation is underway. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability.

During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at the landfill. The first involved installation of a non-combustible 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 2016 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.

Commencing in February 2012, 41 lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, and Cotter, which remains a defendant. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to Cotter's negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. The court has dismissed the lawsuits filed by 30 of the plaintiffs. Pre-trial motions and discovery are proceeding in the remaining cases and a proposed pre-trial scheduling order has been filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.

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 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. Exelon currently estimates the cost to close the site to be approximately $9 million which has been fully reserved as of March 31, 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, an estimate of the range of BGE’s reasonably possible loss, if any, cannot be determined.

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 of three specific areas of the site, and a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field investigation was completed in January 2015, and a final report was provided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this time. Upon completion of the investigation to date, BGE has established what it believes is an appropriate reserve. As the investigation and potential remediation proceed, it is possible that additional reserves could be established, in amounts that could be material to BGE.

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 second 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.

DOEE, Pepco and Pepco Energy Services must submit their next joint status report to the court regarding progress on the RI/FS by May 24, 2016. 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 have estimated that the costs of remediation are in the range of approximately $9 million to $13 million. An estimated liability for this issue has been accrued.

Anacostia River Tidal Reach. Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, DOEE has 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 has 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 site resulting from the Benning RI/FS. Pepco will review the draft river-wide RI report and consider its response to this request during the second quarter of 2016. At this time, it is not possible to predict the nature or extent of Pepco’s possible 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.

In September 2011, PHI received a request for data from the EPA regarding operations at the Deepwater generating facility in New Jersey (which was included in the sale to Calpine) between February 2004 and July 1, 2010, to demonstrate compliance with the Clean Air Act’s new source review permitting program. PHI responded to the data request. Under the terms of the Calpine sale, PHI is obligated to indemnify Calpine for any failure of PHI, on or prior to the closing date of the sale, to comply with environmental laws attributable to the construction of new, or modification of existing, sources of air emissions. At this time, Exelon and PHI do not expect this inquiry to have a material adverse effect on their consolidated financial condition, results of operations or cash flows.

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

At March 31, 2016 and December 31, 2015, Generation had reserved approximately $93 million and $95 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2016, approximately $21 million of this amount related to 234 open claims presented to Generation, while the remaining $72 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary.

On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than two 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. Exelon, Generation, and ComEd have not recorded an increase to the asbestos-related bodily injury liability as of March 31, 2016.

There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued and the increases could have a material adverse effect on Exelon's, Generation's, BGE's, and PECO's future results of operations and cash flows.

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

Approximately 452 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.

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


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


•	the names of the plaintiffs’ employers;


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


•	the facts and circumstances relating to the alleged exposure.

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

Continuous Power Interruption (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 March 31, 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.

General (All Registrants)

The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

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

See Note 15 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)

3 Months Ended

Mar. 31, 2016

Supplemental Financial Information [Abstract]

Additional Financial Information Disclosure [Text Block]

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 months ended March 31, 2016 and 2015:



																				Successor		Predecessor
	Three Months Ended March 31, 2016																			March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd		PECO		BGE			Pepco		DPL		ACE		PHI		PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	34		$	34		$	—	$	—	$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	21			21			—		—		—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	79			79			—		—		—			—		—		—		—		—
Non-regulatory agreement units	52			52			—		—		—			—		—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning	2			2			—		—		—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(95		)	(95		)	—		—		—			—		—		—		—		—
Total decommissioning-related activities	93			93			—		—		—			—		—		—		—		—
Investment income	6			1			—		—		1		^(c)	—		—		—		—		—
Long-term lease income	4			—			—		—		—			—		—		—		—		—
Interest income related to uncertain income tax positions	1			—			—		—		—			1		—		1		—		—
AFUDC — Equity	8			—			2		2		3			4		1		2		1		7
Loss on debt extinguishment	(2		)	(2		)	—		—		—			—		—		—		—		—
Other	4			1			2		—		—			4		2		1		1		(11		)
Other, net	$	114		$	93		$	4	$	2	$	4		$	9	$	3	$	4	$	2	$	(4	)



	Three Months Ended March 31, 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	$	71		$	71		$	—	$	—	$	—		$	—	$	—	$	—	$	—
Non-regulatory agreement units	29			29			—		—		—			—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	48			48			—		—		—			—		—		—		—
Non-regulatory agreement units	40			40			—		—		—			—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning	10			10			—		—		—			—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(106		)	(106		)	—		—		—			—		—		—		—
Total decommissioning-related activities	92			92			—		—		—			—		—		—		—
Investment income	1			1			—		—		1		^(c)	—		—		—		—
Long-term lease income	4			—			—		—		—			—		—		—		—
Interest income related to uncertain income tax positions	—			1			—		—		—			—		—		—		—
AFUDC — Equity	5			—			—		2		3			4		3		—		1
Terminated interest rate swaps^(d)	(23		)	3			—		—		—			—		—		—		—
Other	1			(3		)	3		—		—			5		2		2		—
Other, net	$	80		$	94		$	3	$	2	$	4		$	9	$	5	$	2	$	1

____


(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)	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.

(d)

In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments 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.

The following utility taxes are included in revenues and expenses for the three months ended March 31, 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.



																	Successor		Predecessor
	Three Months Ended March 31, 2016																March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016
	Exelon		Generation		ComEd		PECO		BGE		Pepco		DPL		ACE		PHI		PHI
Utility taxes	$	153	$	28	$	59	$	35	$	24	$	79	$	5	$	—	$	7	$	77



	Three Months Ended March 31, 2015
											Predecessor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Utility taxes	$	148	$	27	$	62	$	35	$	24	$	85	$	80	$	5	$	—

Supplemental Cash Flow Information

The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015:



																			Successor		Predecessor
	Three Months Ended March 31, 2016																		March 24, 2016 to March 31, 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	$	606		$	278		$	170	$	60	$	75	$	42	$	27	$	20	$	9	$	94
Amortization of regulatory assets	65			—			19		7		34		33		12		20		5		58
Amortization of intangible assets, net	14			11			—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	(14		)	(14		)	—		—		—		—		—		—		—		—
Nuclear fuel^(b)	283			283			—		—		—		—		—		—		—		—
ARO accretion^(c)	109			109			—		—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	1,063		$	667		$	189	$	67	$	109	$	75	$	39	$	40	$	14	$	152



	Three Months Ended March 31, 2015
													Predecessor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	540		$	242		$	154	$	58	$	71	$	96	$	40	$	25	$	19
Amortization of regulatory assets	58			—			21		4		35		59		22		14		24
Amortization of intangible assets, net	12			12			—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	(31		)	(32		)	—		—		—		—		—		—		—
Nuclear fuel^(b)	272			272			—		—		—		—		—		—		—
ARO accretion^(c)	97			97			—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	948		$	591		$	175	$	62	$	106	$	155	$	62	$	39	$	43

________


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


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


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



																									Successor			Predecessor
	Three Months Ended March 31, 2016																								March 24, 2016 to March 31, 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	$	136		$	54		$	41		$	8		$	16		$	8		$	5		$	4		$	3		$	23
Loss from equity method investments	3			3			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	41			6			9			16			12			5			5			7			(2		)	16
Stock-based compensation costs	44			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(55		)	(55		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(9		)	(9		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	1			—			1			—			—			1			—			—			—			1
Amortization of rate stabilization deferral	20			—			—			—			20			1			4			—			—			5
Amortization of debt fair value adjustment	(3		)	(3		)	—			—			—			—			—			—			—			—
Discrete impacts from EIMA^(c)	(14		)	—			(14		)	—			—			—			—			—			—			—
Amortization of debt costs	8			4			1			1			1			—			—			—			—			—
Provision for excess and obsolete inventory	1			1			—			—			—			1			1			1			—			1
Merger-related commitments^(d)(e)	503			3			—			—			—			138			100			120			358			—
Severance costs	69			4			—			—			—			—			—			—			52			—
Asset retirement costs	—			—			—			—			—			—			4			2			—			—
Lower of cost or market inventory adjustment	36			36			—			—			—			—			—			—			—			—
Other	23			7			(6		)	(1		)	(5		)	(1		)	(1		)	(2		)	(1		)	(3		)
Total other non-cash operating activities	$	804		$	51		$	32		$	24		$	44		$	153		$	118		$	132		$	410		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(290	)	$	(234	)	$	25		$	(65	)	$	(4	)	$	9		$	8		$	(9	)	$	(7	)	$	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)	—			—			—			—			—			—			—			—			127			—
Fair value of pension obligation transferred in connection with the PHI Merger	—			—			—			—			—			—			—			—			45			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Change in PPE related to ARO update	62			62			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			1			—			—			—			—			—			—			—
Non-cash financing of capital projects	31			31			—			—			—			—			—			—			—			—



	Three Months Ended March 31, 2015
															Predecessor
	Exelon			Generation			ComEd		PECO			BGE			PHI		Pepco		DPL		ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	159		$	67		$	52	$	10		$	16		$	24	$	8	$	4	$	4
Provision for uncollectible accounts	84			4			22		33			25			16		4		7		5
Stock-based compensation costs	39			—			—		—			—			3		—		—		—
Other decommissioning-related activity^(a)	(44		)	(44		)	—		—			—			—		—		—		—
Energy-related options^(b)	9			9			—		—			—			—		—		—		—
Amortization of regulatory asset related to debt costs	3			—			2		1			—			1		1		—		—
Amortization of rate stabilization deferral	25			—			—		—			25			11		10		1		—
Amortization of debt fair value adjustment	(9		)	(4		)	—		—			—			—		—		—		—
Discrete impacts from EIMA^(c)	46			—			46		—			—			—		—		—		—
Amortization of debt costs	18			4			1		1			1			—		—		—		—
Lower of cost or market inventory adjustment	10			10			—		—			—			—		—		—		—
Other	4			(1		)	3		(1		)	(3		)	2		—		—		(1		)
Total other non-cash operating activities	$	344		$	45		$	126	$	44		$	64		$	57	$	23	$	12	$	8
Non-cash investing and financing activities:
Change in PPE related to ARO update	56			56			—		—			—			—		—		—		—
Indemnification of like-kind exchange position^(g)	—			—			2		—			—			—		—		—		—

________

(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 to results of operations.


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


(d)	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 March 31, 2016 and December 31, 2015.



													Successor
March 31, 2016	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	16,776	^(a)	$	8,950	^(a)	$	3,716	$	3,139	$	3,069	$	4	$	2,960	$	1,140	$	983
Accounts receivable:
Allowance for uncollectible accounts	$	351		$	73		$	82	$	90	$	53	$	53	$	16	$	19	$	18



													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 $3,008 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 $14 million and $15 million as of March 31, 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 March 31, 2016 of $13 million consists of $1 million, $3 million and $9 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance 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 March 31, 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 (Exelon, Generation, ComEd, PECO and BGE)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Segment Information (Exelon, Generation, ComEd, PECO and BGE)

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 months ended March 31, 2016 and 2015 is as follows:

Three Months Ended March 31, 2016 and 2015



									Successor
	Generation^(a)		ComEd		PECO		BGE		PHI^(b)			Other^(c)			Intersegment Eliminations			Exelon
Operating revenues^(d):
2016
Competitive businesses electric revenues	$	3,695	$	—	$	—	$	—	$	—		$	—		$	(266	)	$	3,429
Competitive businesses natural gas revenues	822		—		—		—		—			—			—			822
Competitive businesses other revenues	222		—		—		—		—			—			—			222
Rate-regulated electric revenues	—		1,249		644		680		90			—			(6		)	2,657
Rate-regulated natural gas revenues	—		—		197		249		3			—			(5		)	444
Shared service and other revenues	—		—		—		—		12			405			(418		)	(1		)
2015
Competitive businesses electric revenues	$	4,397	$	—	$	—	$	—	$	—		$	—		$	(209	)	$	4,188
Competitive businesses natural gas revenues	1,124		—		—		—		—			—			—			1,124
Competitive businesses other revenues	319		—		—		—		—			—			(1		)	318
Rate-regulated electric revenues	—		1,185		677		713		—			—			(1		)	2,574
Rate-regulated natural gas revenues	—		—		308		323		—			—			(7		)	624
Shared service and other revenues	—		—		—		—		—			318			(316		)	2
Intersegment revenues^(e):
2016	$	266	$	5	$	1	$	5	$	12		$	405		$	(695	)	$	(1	)
2015	210		1		—		7		—			317			(533		)	2
Net income (loss):
2016	$	257	$	115	$	124	$	101	$	(309	)	$	(164	)	$	(1	)	$	123
2015	485		90		139		109		—			(84		)	(1		)	738
Total assets:
March 31, 2016	$	47,002	$	26,887	$	10,462	$	8,361	$	20,932		$	9,751		$	(11,653	)	$	111,742
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 March 31, 2016 include revenue from sales to PECO of $79 million and sales to BGE of $173 million in the Mid-Atlantic region, and sales to ComEd of $5 million in the Midwest region. For the three months ended March 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $63 million and sales to BGE of $138 million in the Mid-Atlantic region, and sales to ComEd of $9 million in the Midwest region. For the Successor period of March 24, 2016 to March 31, 2016, intersegment revenues for Generation include revenue from sales to Pepco of $6 million, sales to DPL of $4 million, and sales to ACE of $1 million in the Mid-Atlantic region.


(b)	Amounts included represent activity for the PHI's successor period, March 24, 2016 through March 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the three months ended March 31, 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 March 31, 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 March 31, 2016							Three Months Ended March 31, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	1,532	$	(12	)	$	1,520	$	1,556	$	(43	)	$	1,513
Midwest	1,089		6			1,095		1,276		—			1,276
New England	471		(1		)	470		865		(6		)	859
New York	218		(15		)	203		307		3			310
ERCOT	163		—			163		181		(1		)	180
Other Power Regions	222		1			223		212		2			214
Total Revenues for Reportable Segments	3,695		(21		)	3,674		4,397		(45		)	4,352
Other^(b)	1,044		21			1,065		1,443		45			1,488
Total Generation Consolidated Operating Revenues	$	4,739	$	—		$	4,739	$	5,840	$	—		$	5,840

__________


(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. Also includes a $20 million and $40 million increase to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the three months ended March 31, 2016 and 2015, respectively, unrealized mark-to-market gains of $63 million and $154 million for the three months ended March 31, 2016 and 2015, respectively, and elimination of intersegment revenues.

(c)

Exelon corrected an error in the March 31, 2015 balances within Intersegment Revenue and Revenue from external customers for an overstatement of $43 million of Intersegment Revenue for Reportable Segments for the three months ended March 31, 2015, an understatement of Revenue from external customers for Reportable Segments of $43 million for the three months ended March 31, 2015, an understatement of $43 million of Intersegment Revenue for Other for the three months ended March 31, 2015, and an overstatement of Revenue from external customers for Other of $43 million for the three months ended March 31, 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 March 31, 2016							Three Months Ended March 31, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)		Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	832	$	9		$	841	$	808	$	(21	)	$	787
Midwest	715		3			718		709		(6		)	703
New England	86		(5		)	81		182		(24		)	158
New York	141		(11		)	130		169		20			189
ERCOT	81		(20		)	61		88		(33		)	55
Other Power Regions	86		(10		)	76		72		(26		)	46
Total Revenues net of purchased power and fuel expense for Reportable Segments	1,941		(34		)	1,907		2,028		(90		)	1,938
Other^(b)	356		34			390		379		90			469
Total Generation Revenues net of purchased power and fuel expense	$	2,297	$	—		$	2,297	$	2,407	$	—		$	2,407

__________


(a)	Includes purchases and sales from 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. Also includes a $19 million and $38 million increase to RNF for the amortization of intangible assets related to commodity contracts for the three months ended March 31, 2016 and 2015, respectively, unrealized mark-to-market gains of $103 million and $162 million for the three months ended March 31, 2016 and 2015, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

(c)

Exelon corrected an error in the March 31, 2015 balances within Intersegment RNF and RNF from external customers for an understatement of $4 million of Intersegment RNF for Reportable Segments for the three months ended March 31, 2015, an understatement of RNF from external customers for Reportable Segments of $5 million for the three months ended March 31, 2015, an overstatement of $4 million of Intersegment RNF for Other for the three months ended March 31, 2015, and an overstatement of RNF from external customers for Other of $5 million for the three months ended March 31, 2015. This also included an understatement of total RNF for Reportable Segments and an overstatement of total RNF for Other of $9 million for the three months ended March 31, 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 March 31, 2016 - Successor
Rate-regulated electric revenues	$	40		$	24		$	23		$	3		$	—		$	90
Rate-regulated natural gas revenues	—			3			—			—			—			3
Shared service and other revenues	—			—			—			12			—			12
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	—			—			—			—			—			—
Three months ended - March 31, 2015 - Predecessor
Rate-regulated electric revenues	$	545		$	335		$	334		$	58		$	(4	)	$	1,268
Rate-regulated natural gas revenues	—			86			—			—			—			86
Shared service and other revenues	—			—			—			—			—			—
Intersegment revenues:
March 24, 2016 to March 31, 2016 - Successor	$	—		$	—		$	—		$	12		$	—		$	12
January 1, 2016 to March 23, 2016 - Predecessor	1			2			1			—			(4		)	—
Three months ended - March 31, 2015 - Predecessor	1			2			1			—			(4		)	—
Net income (loss):
March 24, 2016 to March 31, 2016 - Successor	$	(140	)	$	(98	)	$	(105	)	$	22		$	12		$	(309	)
January 1, 2016 to March 23, 2016 - Predecessor	32			26			5			(44		)	—			19
Three months ended - March 31, 2015 - Predecessor	26			32			9			(14		)	—			53
Total assets:
March 31, 2016 - Successor	$	6,877		$	3,959		$	3,393		$	11,077		$	(4,374	)	$	20,932
December 31, 2015 - Predecessor	6,908			3,969			3,387			7,158			(5,238		)	16,184

_________


(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 March 31, 2016 and 2015.


(b)	Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities. For the predecessor periods presented, Other includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.

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]

Subsequent Events (Exelon and Generation)	3 Months Ended
Subsequent Events (Exelon and Generation)	Mar. 31, 2016
Subsequent Events [Abstract]
Subsequent Events (Exelon and Generation)	Subsequent Events (Exelon and Generation) On October 24, 2014, Generation entered into a sale agreement to divest its proportional ownership interests in the Keystone and Conemaugh generating facilities and related fuel supply entities in Pennsylvania for total sales proceeds of approximately $475 million, including approximately $60 million of working capital. The transaction, which is subject to customary closing conditions and approvals, is expected to be completed in the fourth quarter of 2014 or first quarter of 2015. The sales price, less costs to complete the sale, is less than the carrying value of the net assets. As a result, Exelon and Generation anticipate recording a pre-tax impairment loss ranging from approximately $350 million to $400 million during the fourth quarter of 2014, which will be recorded within Operating and maintenance expense on Exelon’s and Generation’s Statement of Operations and Comprehensive Income. The estimated net after-tax cash proceeds of $418 million, excluding estimated working capital, are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes.

Basis of Presentation Significant Accounting Policies

3 Months Ended

Mar. 31, 2016

Fair Value Assets Measured On Recurring Basis Investments Valuation Techniques

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




	Generation				Exelon
	Operating Revenues	Purchased Power and Fuel		Other, net^(b)	Operating Revenues	Purchased Power and Fuel		Other, net^(b)
Total gains (losses) included in net income for the three months ended March 31, 2016	49	(55	)	2	49	(55	)	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2016	254	(35	)	1	254	(35	)	1



	Generation					Exelon
	Operating Revenues		Purchased Power and Fuel		Other, net^(b)	Operating Revenues		Purchased Power and Fuel		Other, net^(b)
Total gains (losses) included in net income for the three months ended March 31, 2015	(10	)	(22	)	2	(10	)	(22	)	2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2015	169		11		1	169		11		1



	Predecessor
	PHI					Pepco
	January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015		Three Months Ended March 31, 2016		Three Months Ended March 31, 2015
	Other, net
Total (losses) gains included in net income	$	(17	)	$	1	$	1	$	1
Change in the unrealized gains (losses) relating to assets and liabilities held	1			1		1		1

_________


(a)	Successor period represents activity for the period of March 24, 2016 through March 31, 2016.


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

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

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]

Earnings Per Share Policy, Diluted

<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;text-align:justify;text-indent:32px;font-size:10pt;"><font style="font-family:Arial;font-size:10pt;">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.</font></div></div>

New Accounting Pronouncements (Policies)	3 Months Ended
New Accounting Pronouncements (Policies)	Mar. 31, 2016
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	Exelon has identified the following new accounting standards that have been recently adopted. 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. In August 2015, the FASB issued an amendment to provide a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017, as well as an option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not plan to early adopt the standard. In March 2016, the FASB issued final amendments to clarify the implementation guidance for principal versus agent considerations, identifying performance obligations and the accounting for licenses of intellectual property. In May 2016, the FASB issued a final amendment regarding narrow scope improvements and practical expedients. The Registrants are currently assessing the impact of these updates. 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. 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. Based on the analysis completed, additional entities were considered VIEs. See Note 3 - Variable Interest Entities for the disclosure impacts. The following recently issued accounting standards are not yet required to be reflected in the consolidated financial statements of the Registrants. 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 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. 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)

3 Months Ended

Mar. 31, 2016

Variable Interest Entity [Abstract]

Schedule of Variable Interest Entities



	March 31, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon ^(a)		Generation		BGE		PHI		ACE
Cash and cash equivalents	$	145	$	145	$	—	$	—	$	—	$	164	$	164	$	—	$	—	$	—
Restricted cash	117		62		44		11		11		100		77		23		12		12
Accounts receivable, net
Customer	231		231		—		—		—		219		219		—		—		—
Other	28		28		—		—		—		43		43		—		—		—
Mark-to-market derivatives assets	120		120		—		—		—		140		140		—		—		—
Inventory
Materials and supplies	186		186		—		—		—		181		181		—		—		—
Other current assets	50		36		—		11		—		35		30		—		—		—
Total current assets	877		808		44		22		11		882		854		23		12		12
Property, plant and equipment, net	5,141		5,141		—		—		—		5,160		5,160		—		—		—
Nuclear decommissioning trust funds	2,069		2,069		—		—		—		2,036		2,036		—		—		—
Goodwill	47		47		—		—		—		47		47		—		—		—
Mark-to-market derivatives assets	41		41		—		—		—		53		53		—		—		—
Other noncurrent assets	135		84		3		46		18		90		85		3		18		18
Total noncurrent assets	7,433		7,382		3		46		18		7,386		7,381		3		18		18
Total assets	$	8,310	$	8,190	$	47	$	68	$	29	$	8,268	$	8,235	$	26	$	30	$	30
Long-term debt due within one year	$	265	$	128	$	79	$	56	$	45	$	111	$	27	$	79	$	46	$	46
Accounts payable	164		164		—		—		—		216		216		—		—		—
Accrued expenses	81		75		4		2		2		115		113		2		2		2
Mark-to-market derivative liabilities	7		7		—		—		—		5		5		—		—		—
Unamortized energy contract liabilities	12		12		—		—		—		12		12		—		—		—
Other current liabilities	13		13		—		—		—		13		13		—		—		—
Total current liabilities	542		399		83		58		47		472		386		81		48		48
Long-term debt	743		559		41		142		114		666		623		41		124		124
Asset retirement obligations	2,016		2,016		—		—		—		1,999		1,999		—		—		—
Pension obligation^(c)	9		9		—		—		—		9		9		—		—		—
Unamortized energy contract liabilities	35		35		—		—		—		39		39		—		—		—
Other noncurrent liabilities	76		76		—		—		—		79		79		—		—		—
Total noncurrent liabilities	2,879		2,695		41		142		114		2,792		2,749		41		124		124
Total liabilities	$	3,421	$	3,094	$	124	$	200	$	161	$	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.



March 31, 2016	Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets^(a)	$	264	$	357	$	621
Total liabilities^(a)	15		247		262
Exelon's ownership interest in VIE^(a)	—		75		75
Other ownership interests in VIE^(a)	249		35		284
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—		94		94
Contract intangible asset	9		—		9
Debt and payment guarantees	—		3		3
Net assets pledged for Zion Station decommissioning^(b)	17		—		17



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)



	March 31, 2016										December 31, 2015
							Successor										Predecessor
	Exelon^(a)(b)		Generation		BGE		PHI^(b)		ACE		Exelon^(a)		Generation		BGE		PHI		ACE
Current assets	$	928	$	860	$	44	$	22	$	11	$	909	$	881	$	23	$	12	$	12
Noncurrent assets	8,047		7,996		3		46		18		8,009		8,004		3		18		18
Total assets	$	8,975	$	8,856	$	47	$	68	$	29	$	8,918	$	8,885	$	26	$	30	$	30
Current liabilities	$	544	$	400	$	83	58		$	47	$	473	$	387	$	81	$	48	$	48
Noncurrent liabilities	3,050		2,865		41		142		114		2,927		2,884		41		124		124
Total liabilities	$	3,594	$	3,265	$	124	$	200	$	161	$	3,400	$	3,271	$	122	$	172	$	172

_______


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

Finite-Lived and Indefinite-Lived Intangible Assets Acquired as Part of Business Combination [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)

3 Months Ended

Mar. 31, 2016

Business Combinations [Abstract]



	PHI		Exelon^(a)
Beginning balance	$	—	$	2,672
Goodwill from business combination	4,016		4,016
Ending balance	$	4,016	$	6,688

_____________

(a) As of March 31, 2016, there were no changes to the carrying amount of goodwill for ComEd and Generation, see Note 11— Intangible Assets of the Exelon 2015 Form 10-K for further information.

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



	Three Months Ended March 31,				Year Ended December 31,
	2016^(a)		2015^(b)		2015^(c)
Total operating revenues	$	8,556	$	10,062	$	33,823
Net income attributable to common shareholders	577		800		2,618

Basic earnings per share	$	0.63	$	0.87	$	2.85
Diluted earnings per share	0.62		0.87		2.84

______________


(a)	The amounts above exclude non-recurring costs directly related to the merger of $639 million and intercompany revenue of $170 million for the three months ended March 31, 2016.


(b)	The amounts above exclude non-recurring costs directly related to the merger of $116 million and intercompany revenue of $122 million for the three months ended March 31, 2015.


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

Business Combination, Separately Recognized Transactions [Table Text Block]



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

_____________


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

(b)



								Successor
Description	Expected Payment Period	Pepco		DPL		ACE		PHI		Exelon
Customer bill credit	2016 - 2017	$	65	$	58	$	62	$	185	$	185
Energy efficiency	2016 - 2021	—		—		—		—		64
Charitable contributions	2016 - 2026	28		12		10		50		50
Customer base rate credit	2016 - 2019	26		—		—		26		26
Delivery system modernization	Q2 2016	—		—		—		—		22
Green sustainability fund	Q2 2016	—		—		—		—		14
Workforce development	2016 - 2020	—		—		—		—		11
Most favored nation		19		32		48		99		129
Other		1		2		—		3		7
Total		$	139	$	104	$	120	$	363	$	508

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]



Preliminary Purchase Price Allocation
Current assets	$	2,107
Property, plant and equipment	11,071
Regulatory assets	5,118
Other assets	656
Goodwill	4,016
Total assets	22,968

Current liabilities	3,425
Unamortized energy contracts	1,550
Regulatory liabilities	297
Long-term debt, including current maturities	6,076
Deferred income taxes	3,441
Pension and OPEB liability	846
Other liabilities	191
Total liabilities	15,826
Total purchase price	$	7,142

Restructuring and Related Costs



	Three Months Ended March 31,
Acquisition, Integration and Financing Costs^(a)	2016			2015
Exelon	$	102		$	108
Generation	16			7
ComEd^(b)	(8		)	3
PECO	2			1
BGE	2			1
Pepco	27			1
DPL	16			1
ACE	13			1



	Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	56	$	29	$	8

______________


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


(b)	Excludes acquisition, integration and financing costs of $9 million incurred at ComEd that have been recorded as a regulatory asset.



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Severance benefits^(a)	$	52	$	10	$	2	$	1	$	1	$	37	$	18	$	11	$	8

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $9 million, $2 million, $1 million, $1 million, $18 million, $11 million and $8 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the three months ended March 31, 2016.

Regulatory Matters (Tables)

3 Months Ended

Mar. 31, 2016

Regulated Operations [Abstract]

Schedule of Regulatory Assets



									Successor
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	93	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,599		2,182		417		—		—		—		—		—
Removal costs	1,669		1,334		—		187		148		21		127		—
Deferred rent ^(j)	42								42		—		—		—
Energy efficiency and demand response programs	122		78		43		—		1		—		—		1
DLC program costs	9		—		9		—		—		—		—		—
Electric distribution tax repairs	89		—		89		—		—		—		—		—
Gas distribution tax repairs	25		—		25		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(l)(p)(q)}	187		43		69		15		60		25		25		10
Other	55		2		3		10		41		9		14		16
Total regulatory liabilities	4,890		3,639		655		212		292		55		166		27
Less: current portion	512		150		134		61		106		26		57		22
Total non-current regulatory liabilities	$	4,378	$	3,489	$	521	$	151	$	186	$	29	$	109	$	5



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79		214		137		36		41
AMI programs ^(r)	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(b)	189		189		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(d)	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		—		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(m)(n)(o)}	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		14		10		4		—
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 ^(h)	30		—		—		30		—		—		—		—
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		38		14		10		13
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 ^{(f)(g)(k)(l)(p)(q)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling^(h)	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)	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.


(d)	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.


(e)	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 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.

(f)

(g)

(h)


(i)	Represents the regulatory asset recorded at Exelon and PHI for the difference between the carrying value and fair value of alternative energy credits at Pepco, DPL and ACE recorded at Exelon and PHI that are recoverable through the rate making process.


(j)	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 which was eliminated at PHI as part of acquisition accounting.

(k)

(l)

(m)


(n)	As of March 31, 2016, DPL's regulatory asset of $6 million related to transmission costs recoverable through its FERC approved formula rate. 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.

(o)


(p)	As of March 31, 2016, Pepco's regulatory liability of $25 million included $15 million of over-recovered transmission costs and $10 million of over-recovered electric energy 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.


(q)	As of March 31, 2016, ACE's regulatory liability of $10 million related to over-recovered transmission costs. As of December 31, 2015, ACE's regulatory liability of $8 million related to over-recovered transmission costs.


(r)	Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

Schedule of Regulatory Liabilities



									Successor
March 31, 2016	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory liabilities
Other postretirement benefits	$	93	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Nuclear decommissioning	2,599		2,182		417		—		—		—		—		—
Removal costs	1,669		1,334		—		187		148		21		127		—
Deferred rent ^(j)	42								42		—		—		—
Energy efficiency and demand response programs	122		78		43		—		1		—		—		1
DLC program costs	9		—		9		—		—		—		—		—
Electric distribution tax repairs	89		—		89		—		—		—		—		—
Gas distribution tax repairs	25		—		25		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(l)(p)(q)}	187		43		69		15		60		25		25		10
Other	55		2		3		10		41		9		14		16
Total regulatory liabilities	4,890		3,639		655		212		292		55		166		27
Less: current portion	512		150		134		61		106		26		57		22
Total non-current regulatory liabilities	$	4,378	$	3,489	$	521	$	151	$	186	$	29	$	109	$	5



									Predecessor
December 31, 2015	Exelon		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE

Regulatory assets
Pension and other postretirement benefits	$	3,156	$	—	$	—	$	—	$	910	$	—	$	—	$	—
Deferred income taxes	1,616		64		1,473		79		214		137		36		41
AMI programs ^(r)	399		140		63		196		267		180		87		—
Under-recovered distribution service costs ^(b)	189		189		—		—		—
Debt costs	47		46		1		8		36		19		10		7
Fair value of long-term debt ^(d)	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		—		—		—		—		—		—
Energy and transmission programs ^{(f)(g)(k)(m)(n)(o)}	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		14		10		4		—
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 ^(h)	30		—		—		30		—		—		—		—
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		38		14		10		13
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 ^{(f)(g)(k)(l)(p)(q)}	131		53		60		18		27		16		19		8
Over-recovered revenue decoupling^(h)	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)	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.


(d)	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.


(e)	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 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.

(f)

(g)

(h)


(i)	Represents the regulatory asset recorded at Exelon and PHI for the difference between the carrying value and fair value of alternative energy credits at Pepco, DPL and ACE recorded at Exelon and PHI that are recoverable through the rate making process.


(j)	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 which was eliminated at PHI as part of acquisition accounting.

(k)

(l)

(m)


(n)	As of March 31, 2016, DPL's regulatory asset of $6 million related to transmission costs recoverable through its FERC approved formula rate. 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.

(o)


(p)	As of March 31, 2016, Pepco's regulatory liability of $25 million included $15 million of over-recovered transmission costs and $10 million of over-recovered electric energy 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.


(q)	As of March 31, 2016, ACE's regulatory liability of $10 million related to over-recovered transmission costs. As of December 31, 2015, ACE's regulatory liability of $8 million related to over-recovered transmission costs.


(r)	Represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout Pepco’s and DPL’s service territories that are recoverable from customers. AMI has not been approved by the NJBPU for ACE in New Jersey. PHI generally is deferring carrying charges on these regulatory assets.

Purchase Of Receivables



													Predecessor
As of December 31, 2015	Exelon			ComEd			PECO			BGE			PHI			Pepco			DPL		ACE
Purchased receivables^(b)	$	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, DPL and ACE, 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 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.

Public Utilities General Disclosures [Table Text Block]



							Successor
As of March 31, 2016	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)	$	60	$	31	$	17	$	12	$	4	$	7	$	1



							Predecessor
As of December 31, 2015	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)(b)	$	43	$	31	$	12	$	14	$	5	$	7	$	2

_____


(a)	The regulatory assets represent a component of the costs included within the energy and transmission regulatory programs. Refer to Regulatory Assets and Liabilities table for additional information.


(b)	The Exelon consolidated amounts do not include the regulatory assets of PHI, Pepco, DPL, and ACE at December 31, 2015.

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.



							Successor
As of March 31, 2016	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)	$	60	$	31	$	17	$	12	$	4	$	7	$	1



							Predecessor
As of December 31, 2015	Exelon		ComEd		BGE		PHI		Pepco		DPL		ACE
Regulatory Assets^(a)(b)	$	43	$	31	$	12	$	14	$	5	$	7	$	2

_____


(a)	The regulatory assets represent a component of the costs included within the energy and transmission regulatory programs. Refer to Regulatory Assets and Liabilities table for additional information.

Investment in Constellation Energy Nuclear Group, LLC (Tables)	3 Months Ended
	Mar. 31, 2016
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Schedule of total equity in earnings of investment in CENG	March 31, 2016

Impairment of Long-lived Assets (Tables)

3 Months Ended

Mar. 31, 2016

Schedule of Capital Leased Assets

Implications of Potential Early Plant Retirements Implications of Potential Early Plant Retirements (Tables)

3 Months Ended

Mar. 31, 2016

ImplicationsofPotentialEarlyPlantRetirement [Table Text Block]



(in millions)	Quad Cities			Clinton				Ginna			Total
Asset Balances
Materials and supplies inventory	$	47		$	58			$	30		$	135
Nuclear fuel inventory, net	213			95				54			362
Completed plant, net	1,014			574				127			1,715
Construction work in progress	28			11				11			50
Liability Balances
Asset retirement obligation	(706		)	(407		)		(651		)	(1,764		)

NRC License Renewal Term	2032			2046			^(a)	2029

_________


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

Fair Value of Financial Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2016

Fair value of financial liabilities recorded at the carrying amount

Exelon



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	3,643	$	3	$	3,640	$	—	$	3,643
Long-term debt (including amounts due within one year)^(a)	31,372		1,132		29,577		2,135		32,844
Long-term debt to financing trusts^(b)	641		—		—		670		670
SNF obligation	1,022		—		817		—		817



	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

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

PHI, Pepco, DPL and ACE



	Successor											Predecessor
	As of March 31, 2016											As of December 31, 2015
PHI	Level 1			Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total
Assets
Cash equivalents	$	168		$	—		$	—	$	168		$	42		$	—		$	—	$	42
Derivative asset	—			—			—		—			—			—			18		18
Rabbi trust investments
Cash equivalents	73			—			—		73			12			—			—		12
Fixed income	—			14			—		14			—			15			—		15
Life insurance contracts	—			22			20		42			—			27			19		46
Rabbi trust investments subtotal	73			36			20		129			12			42			19		73
Total assets	241			36			20		297			54			42			37		133
Liabilities
Deferred compensation obligation	—			(30		)	—		(30		)	—			(30		)	—		(30		)
Mark-to-market derivative liabilities(a)	(1		)	—			—		(1		)	(2		)	—			—		(2		)
Effect of netting and allocation of collateral	1			—			—		1			2			—			—		2
Mark-to-market derivative liabilities subtotal	—			—			—		—			—			—			—		—
Total liabilities	—			(30		)	—		(30		)	—			(30		)	—		(30		)
Total net assets	$	241		$	6		$	20	$	267		$	54		$	12		$	37	$	103



	Pepco										DPL											ACE
As of March 31, 2016	Level 1		Level 2			Level 3		Total			Level 1			Level 2			Level 3		Total			Level 1		Level 2		Level 3		Total
Assets
Cash equivalents	$	19	$	—		$	—	$	19		$	—		$	—		$	—	$	—		$	148	$	—	$	—	$	148
Rabbi trust investments
Cash equivalents	43		—			—		43			—			—			—		—			—		—		—		—
Fixed income	—		14			—		14			—			—			—		—			—		—		—		—
Life insurance contracts	—		22			20		42			—			—			—		—			—		—		—		—
Rabbi trust investments subtotal	43		36			20		99			—			—			—		—			—		—		—		—
Total assets	62		36			20		118			—			—			—		—			148		—		—		148
Liabilities
Deferred compensation obligation	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Mark-to-market derivative liabilities^(a)	—		—			—		—			(1		)	—			—		(1		)	—		—		—		—
Effect of netting and allocation of collateral	—		—			—		—			1			—			—		1			—		—		—		—
Mark-to-market derivative liabilities subtotal	—		—			—		—			—			—			—		—			—		—		—		—
Total liabilities	—		(5		)	—		(5		)	—			(1		)	—		(1		)	—		—		—		—
Total net assets (liabilities)	$	62	$	31		$	20	$	113		$	—		$	(1	)	$	—	$	(1	)	$	148	$	—	$	—	$	148



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



	Generation										Exelon
As of March 31, 2016	Level 1		Level 2		Level 3		Not subject to leveling		Total		Level 1		Level 2		Level 3		Not subject to leveling		Total
Assets
Cash equivalents	$	130	$	—	$	—	$	—	$	130	$	721	$	—	$	—	$	—	$	721
NDT fund investments
Cash equivalents^(a)	266		11		—		—		277		266		11		—		—		277
Equities	3,273		21		1		1,875		5,170		3,273		21		1		1,875		5,170
Fixed income
Corporate debt	—		1,868		243		—		2,111		—		1,868		243		—		2,111
U.S. Treasury and agencies	1,402		13		—		—		1,415		1,402		13		—		—		1,415
Foreign governments	—		45		—		—		45		—		45		—		—		45
State and municipal debt	—		285		—		—		285		—		285		—		—		285
Other^(b)	—		64		—		376		440		—		64		—		376		440
Fixed income subtotal	1,402		2,275		243		376		4,296		1,402		2,275		243		376		4,296
Middle market lending	—		—		440		—		440		—		—		440		—		440
Private equity	—		—		—		130		130		—		—		—		130		130
Real estate	—		—		—		40		40		—		—		—		40		40
Other	—		—		—		190		190		—		—		—		190		190
NDT fund investments subtotal^(c)	4,941		2,307		684		2,611		10,543		4,941		2,307		684		2,611		10,543
Pledged assets for Zion Station decommissioning
Cash equivalents	35		—		—		—		35		35		—		—		—		35
Equities	1		7		—		—		8		1		7		—		—		8
Fixed income
U.S. Treasury and agencies	3		2		—		—		5		3		2		—		—		5



	Generation														Exelon
As of March 31, 2016	Level 1			Level 2			Level 3			Not subject to leveling		Total			Level 1			Level 2			Level 3			Not subject to leveling		Total
Corporate debt	—			25			—			—		25			—			25			—			—		25
Fixed income subtotal	3			27			—			—		30			3			27			—			—		30
Middle market lending	—			—			25			85		110			—			—			25			85		110
Pledged assets for Zion Station decommissioning subtotal^(d)	39			34			25			85		183			39			34			25			85		183
Rabbi trust investments
Cash equivalents	9			—			—			—		9			83			—			—			—		83
Mutual funds	17			—			—			—		17			46			—			—			—		46
Fixed income	—			—			—			—		—			—			14			—			—		14
Life insurance contracts	—			16			—			—		16			—			60			20			—		80
Rabbi trust investments subtotal	26			16			—			—		42			129			74			20			—		223
Commodity derivative assets
Economic hedges	1,591			4,849			1,788			—		8,228			1,591			4,849			1,788			—		8,228
Proprietary trading	31			82			30			—		143			31			82			30			—		143
Effect of netting and allocation of collateral^(e)	(1,739		)	(3,997		)	(675		)	—		(6,411		)	(1,739		)	(3,997		)	(675		)	—		(6,411		)
Commodity derivative assets subtotal	(117		)	934			1,143			—		1,960			(117		)	934			1,143			—		1,960
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments	—			—			—			—		—			—			42			—			—		42
Economic hedges	—			20			—			—		20			—			20			—			—		20
Proprietary trading	11			2			—			—		13			11			2			—			—		13
Effect of netting and allocation of collateral	(4		)	(5		)	—			—		(9		)	(4		)	(5		)	—			—		(9		)
Interest rate and foreign currency derivative assets subtotal	7			17			—			—		24			7			59			—			—		66
Other investments	—			—			36			—		36			—			—			36			—		36
Total assets	5,026			3,308			1,888			2,696		12,918			5,720			3,408			1,908			2,696		13,732
Liabilities
Commodity derivative liabilities
Economic hedges	(2,053		)	(4,688		)	(885		)	—		(7,626		)	(2,054		)	(4,688		)	(1,150		)	—		(7,892		)
Proprietary trading	(28		)	(79		)	(37		)	—		(144		)	(28		)	(79		)	(37		)	—		(144		)
Effect of netting and allocation of collateral^(e)	2,089			4,535			826			—		7,450			2,090			4,535			826			—		7,451
Commodity derivative liabilities subtotal	8			(232		)	(96		)	—		(320		)	8			(232		)	(361		)	—		(585		)
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments	—			(20		)	—			—		(20		)	—			(23		)	—			—		(23		)
Economic hedges	—			(8		)	—			—		(8		)	—			(8		)	—			—		(8		)
Proprietary trading	(11		)	—			—			—		(11		)	(11		)	—			—			—		(11		)
Effect of netting and allocation of collateral	11			5			—			—		16			11			5			—			—		16
Interest rate and foreign currency derivative liabilities subtotal	—			(23		)	—			—		(23		)	—			(26		)	—			—		(26		)
Deferred compensation obligation	—			(30		)	—			—		(30		)	—			(131		)	—			—		(131		)
Total liabilities	8			(285		)	(96		)	—		(373		)	8			(389		)	(361		)	—		(742		)
Total net assets	$	5,034		$	3,023		$	1,792		$	2,696	$	12,545		$	5,728		$	3,019		$	1,547		$	2,696	$	12,990



	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	$	104		$	—		$	—		$	—	$	104		$	5,766		$	—		$	—		$	—	$	5,766
NDT fund investments
Cash equivalents^(a)	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^(b)	—			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^(c)	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^(d)	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^(e)	(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^(e)	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)	Includes $38 million and $52 million of cash received from outstanding repurchase agreements at March 31, 2016 and December 31, 2015, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (c) below.

(b)

(c)


(d)	Excludes net assets of $0 million and $1 million at March 31, 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.

(e)

ComEd, PECO and BGE



	ComEd											PECO										BGE
As of March 31, 2016	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	—	$	—		$	—		$	—		$	3	$	—		$	—	$	3		$	43	$	—		$	—	$	43
Rabbi trust investments
Mutual funds	—		—			—			—			8		—			—		8			4		—			—		4
Life insurance contracts	—		—			—			—			—		11			—		11			—		—			—		—
Rabbi trust investments subtotal	—		—			—			—			8		11			—		19			4		—			—		4
Total assets	—		—			—			—			11		11			—		22			47		—			—		47
Liabilities
Deferred compensation obligation	—		(8		)	—			(8		)	—		(12		)	—		(12		)	—		(3		)	—		(3		)
Mark-to-market derivative liabilities^(a)	—		—			(265		)	(265		)	—		—			—		—			—		—			—		—
Total liabilities	—		(8		)	(265		)	(273		)	—		(12		)	—		(12		)	—		(3		)	—		(3		)
Total net assets (liabilities)	$	—	$	(8	)	$	(265	)	$	(273	)	$	11	$	(1	)	$	—	$	10		$	47	$	(3	)	$	—	$	44



	ComEd											PECO										BGE
As of December 31, 2015	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3		Total			Level 1		Level 2			Level 3		Total
Assets
Cash equivalents	$	29	$	—		$	—		$	29		$	271	$	—		$	—	$	271		$	25	$	—		$	—	$	25
Rabbi trust investments
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^(a)	—		—			(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)	The Level 3 balance consists of the current and noncurrent liability of $26 million and $239 million, respectively, at March 31, 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

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 months ended March 31, 2016 and 2015:



																			Successor
	Generation															ComEd			PHI^(a)					Exelon
Three Months Ended March 31, 2016	NDT Fund Investments				Pledged Assets for Zion Station Decommissioning		Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(b)			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				—		(6		)	^(c)	—		(4		)	—			—		—			(4		)
Included in noncurrent payables to affiliates	4				—		—				—		4			—			—		(4		)	—
Included in payable for Zion Station decommissioning	—				2		—				—		2			—			—		—			2
Included in regulatory assets/liabilities	—				—		—				—		—			(18		)	—		4			(14		)
Change in collateral	—				—		(50		)		—		(50		)	—			—		—			(50		)
Purchases, sales, issuances and settlements
Purchases	34				1		59				3		97			—			—		—			97
Sales	—				—		(2		)		—		(2		)	—			—		—			(2		)
Settlements	(26		)		—		—				—		(26		)	—			—		—			(26		)
Transfers into Level 3	—				—		2				—		2			—			—		—			2
Transfers out of Level 3	—				—		(7		)		—		(7		)	—			—		—			(7		)
Balance as of March 31, 2016	$	684			$	25	$	1,047			$	36	$	1,792		$	(265	)	$	20	$	—		$	1,547
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2016	$	1			$	—	$	219			$	—	$	220		$	—		$	—	$	—		$	220



	Generation															ComEd						Exelon
Three Months Ended March 31, 2015	NDT Fund Investments			Pledged Assets for Zion Station Decommissioning			Mark-to-Market Derivatives				Other Investments		Total Generation			Mark-to-Market Derivatives^(b)			Eliminated in Consolidation			Total
Balance as of December 31, 2014	$	605		$	50		$	1,050			$	3	$	1,708		$	(207	)	$	—		$	1,501
Total realized / unrealized gains (losses)
Included in net income	2			—			(32		)	^(c)	—		(30		)	—			—			(30		)
Included in other comprehensive income	—			—			—				—		—			—			—			—
Included in noncurrent payables to affiliates	10			—			—				—		10			—			(10		)	—
Included in payable for Zion Station decommissioning	—			3			—				—		3			—			—			3
Included in regulatory assets	—			—			—				—		—			(34		)	10			(24		)
Change in collateral	—			—			12				—		12			—			—			12
Purchases, sales, issuances and settlements
Purchases	28			—			41				—		69			—			—			69
Sales	(8		)	(9		)	—				—		(17		)	—			—			(17		)
Settlements	(29		)	—			—				—		(29		)	—			—			(29		)
Transfers into Level 3	4			—			—				—		4			—			—			4
Transfers out of Level 3	—			—			(5		)		—		(5		)	—			—			(5		)
Balance as of March 31, 2015	$	612		$	44		$	1,066			$	3	$	1,725		$	(241	)	$	—		$	1,484
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities as of March 31, 2015	$	1		$	—		$	180			$	—	$	181		$	—		$	—		$	181

_________


(a)	Successor period represents activity from March 24, 2016 through March 31, 2016. See tables below for PHI's predecessor periods, as well as activity for Pepco and DPL for the three months ended March 31, 2016 and 2015.

(b)


(c)	Includes a reduction for the reclassification of $225 million and $212 million of realized gains due to the settlement of derivative contracts recorded in results of operations for the three months ended March 31, 2016 and 2015, respectively.

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

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



Type of trade	Fair Value at March 31, 2016			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	903		Discounted Cash Flow	Forward power price	$7	-	$88
					Forward gas price	$0.58	-	$7.67
				Option Model	Volatility percentage	5%	-	184%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$9	-	$83
Mark-to-market derivatives (Exelon and ComEd)	$	(265	)	Discounted Cash Flow	Forward heat rate^(b)	9x	-	10x
					Marketability reserve	3.5%	-	7%
					Renewable factor	88%	-	129%

_________


(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 $151 million as of March 31, 2016.



Type of trade	Fair Value at December 31, 2015			Valuation Technique	Unobservable Input	Range
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)^(a)(c)	$	857		Discounted Cash Flow	Forward power price	$11	-	$88
					Forward gas price	$1.18	-	$8.95
				Option Model	Volatility percentage	5%	-	152%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)^(a)(c)	$	(7	)	Discounted Cash Flow	Forward power price	$13	-	$78
Mark-to-market derivatives (Exelon and ComEd)	$	(247	)	Discounted Cash Flow	Forward heat rate^(b)	9x	-	10x
					Marketability reserve	3.5%	-	7%
					Renewable factor	87%	-	128%

_________


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


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


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

Fair value of financial liabilities recorded at the carrying amount

Generation



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,529	$	—	$	1,529	$	—	$	1,529
Long-term debt (including amounts due within one year)^(a)	9,052		—		7,539		1,549		9,088
SNF obligation	1,022		—		817		—		817



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	643	$	—	$	643	$	—	$	643
Long-term debt (including amounts due within one year)^(a)	6,510		—		7,357		—		7,357
Long-term debt to financing trusts^(b)	205		—		—		207		207



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,581	$	—	$	2,900	$	—	$	2,900
Long-term debt to financing trusts	184		—		—		196		196



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	153	$	3	$	150	$	—	$	153
Long-term debt (including amounts due within one year)^(a)	1,859		—		2,119		—		2,119
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

Fair value of financial liabilities recorded at the carrying amount

PHI



	March 31, 2016
	Carrying Amount		Fair Value
Successor	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	1,317	$	—	$	1,317	$	—	$	1,317
Long-term debt (including amounts due within one year)	6,132		—		5,540		586		6,126



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	2,352	$	—	$	2,876	$	—	$	2,876



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Short-term liabilities	$	75	$	—	$	75	$	—	$	75
Long-term debt (including amounts due within one year)^(a)	1,265		—		1,238		103		1,341



	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



	March 31, 2016
	Carrying Amount		Fair Value
	Carrying Amount		Level 1		Level 2		Level 3		Total
Long-term debt (including amounts due within one year)^(a)	$	1,191	$	—	$	1,081	$	288	$	1,369



	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)

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the derivative fair value

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 March 31,
	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	17		9			(15		)	(7		)

__________


(a)	For the three months ended March 31, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.

March 31, 2016.



	Generation															Exelon Corporate			Exelon
Description	Derivatives Designated as Hedging Instruments			Economic Hedges			Proprietary Trading^(a)			Collateral and Netting^(b)			Subtotal			Derivatives Designated as Hedging Instruments			Total
Mark-to-market derivative assets (current assets)	$	—		$	10		$	8		$	(5	)	$	13		$	—		$	13
Mark-to-market derivative assets (noncurrent assets)	—			10			5			(4		)	11			42			53
Total mark-to-market derivative assets	—			20			13			(9		)	24			42			66
Mark-to-market derivative liabilities (current liabilities)	(8		)	(3		)	(6		)	9			(8		)	—			(8		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(12		)	(5		)	(5		)	7			(15		)	(3		)	(18		)
Total mark-to-market derivative liabilities	(20		)	(8		)	(11		)	16			(23		)	(3		)	(26		)
Total mark-to-market derivative net assets (liabilities)	$	(20	)	$	12		$	2		$	7		$	1		$	39		$	40

_________

(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 March 31, 2016:



																							Successor
	Generation												ComEd			DPL							PHI		Exelon
Derivatives	Economic Hedges			Proprietary Trading			Collateral and Netting^(a)			Subtotal^(b)			Economic Hedges^(c)			Economic Hedges^(d)			Collateral and Netting^(a)		Subtotal		Subtotal		Total Derivatives
Mark-to-market derivative assets (current assets)	$	5,851		$	113		$	(4,792	)	$	1,172		$	—		$	—		$	—	$	—	$	—	$	1,172
Mark-to-market derivative assets (noncurrent assets)	2,377			30			(1,619		)	788			—			—			—		—		—		788
Total mark-to-market derivative assets	8,228			143			(6,411		)	1,960			—			—			—		—		—		1,960
Mark-to-market derivative liabilities (current liabilities)	(5,570		)	(104		)	5,505			(169		)	(26		)	(1		)	1		—		—		(195		)
Mark-to-market derivative liabilities (noncurrent liabilities)	(2,056		)	(40		)	1,945			(151		)	(239		)	—			—		—		—		(390		)
Total mark-to-market derivative liabilities	(7,626		)	(144		)	7,450			(320		)	(265		)	(1		)	1		—		—		(585		)
Total mark-to-market derivative net assets (liabilities)	$	602		$	(1	)	$	1,039		$	1,640		$	(265	)	$	(1	)	$	1	$	—	$	—	$	1,375

______

(a)


(b)	Current and noncurrent assets are shown net of collateral of $303 million and $146 million, respectively, and current and noncurrent liabilities are shown net of collateral of $410 million and $180 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,039 million at March 31, 2016.


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


(d)	Represents natural gas futures purchased as part 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.

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 March 31, 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		(8		)		(10		)
Reclassifications from AOCI to net income	Interest Expense	3			^(a)	3			^(a)
Accumulated OCI derivative loss at March 31, 2016		$	(26	)		$	(26	)



		Total Cash Flow Hedge OCI Activity, Net of Income Tax
		Generation			Exelon
Three Months Ended March 31, 2015	Income Statement Location	Total Cash Flow Hedges			Total Cash Flow Hedges
Accumulated OCI derivative loss at December 31, 2014		$	(18	)	$	(28	)
Effective portion of changes in fair value		(6		)	(11		)
Reclassifications from AOCI to net income	Other, net	—			16			^(b)
Reclassifications from AOCI to net income	Interest Expense	3			3
Reclassifications from AOCI to net income	Operating Revenues	(2		)	(2		)
Accumulated OCI derivative loss at March 31, 2015		$	(23	)	$	(22	)

Other Derivatives - Gain (loss) and reclassification

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



	Location on Income Statement	Three Months Ended March 31,
	Location on Income Statement	2016			2015
Change in fair value of commodity positions	Operating Revenues	$	7		$	1
Reclassification to realized at settlement of commodity positions	Operating Revenues	(3		)	2
Net commodity mark-to-market gains (losses)	Operating Revenues	4			3
Change in fair value of treasury positions	Operating Revenues	(2		)	4
Reclassification to realized at settlement of treasury positions	Operating Revenues	1			(4		)
Net treasury mark-to-market gains (losses)	Operating Revenues	(1		)	—
Total net mark-to-market gains (losses)	Operating Revenues	$	3		$	3



	Generation									Exelon
Three Months Ended March 31, 2016	Operating Revenues			Purchased Power and Fuel			Total			Total
Change in fair value of commodity positions	$	279		$	(127	)	$	152		$	152
Reclassification to realized at settlement of commodity positions	(211		)	167			(44		)	(44		)
Net commodity mark-to-market gains (losses)	68			40			108			108
Change in fair value of treasury positions	(3		)	—			(3		)	(3		)
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	(2		)
Net treasury mark-to-market gains (losses)	(5		)	—			(5		)	(5		)
Net mark-to-market gains (losses)	$	63		$	40		$	103		$	103



	Generation									Exelon Corporate			Exelon
Three Months Ended March 31, 2015	Operating Revenues			Purchased Power and Fuel			Total			Interest Expense			Total
Change in fair value of commodity positions	$	164		$	(79	)	$	85		$	—		$	85
Reclassification to realized at settlement of commodity positions	(21		)	87			66			—			66
Net commodity mark-to-market gains (losses)	143			8			151			—			151
Change in fair value of treasury positions	13			—			13			(78		)	(65		)
Reclassification to realized at settlement of treasury positions	(2		)	—			(2		)	—			(2		)
Net treasury mark-to-market gains (losses)	11			—			11			(78		)	(67		)
Net mark-to-market gains (losses)	$	154		$	8		$	162		$	(78	)	$	84

Prop

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

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	March 31, 2016			December 31, 2015
Gross Fair Value of Derivative Contracts Containing this Feature^(a)	$	(979	)	$	(932	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements^(b)	728			684
Net Fair Value of Derivative Contracts Containing This Feature^(c)	$	(251	)	$	(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.

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 March 31, 2016. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, 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 $19 million, $37 million,$35 million, $36 million, $11 million, and $8 million as of March 31, 2016, respectively.



Rating as of March 31, 2016	Total Exposure Before Credit Collateral		Credit Collateral^(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	1,276	$	58	$	1,218	1	$	436
Non-investment grade	71		32		39		—	—
No external ratings
Internally rated — investment grade	516		1		515		—	—
Internally rated — non-investment grade	101		4		97		—	—
Total	$	1,964	$	95	$	1,869	1	$	436



Net Credit Exposure by Type of Counterparty	As of March 31, 2016
Financial institutions	$	116
Investor-owned utilities, marketers, power producers	781
Energy cooperatives and municipalities	909
Other	63
Total	$	1,869

_____


(a)	As of March 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $8 million of cash and $87 million of letters of credit.

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
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-Name Accounting Standards Codification
-Topic 815
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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
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-Name Accounting Standards Codification
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Reference 4: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Reference 5: http://www.xbrl.org/2003/role/presentationRef
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Reference 6: http://www.xbrl.org/2003/role/presentationRef
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Reference 7: http://www.xbrl.org/2003/role/presentationRef
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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Reference 9: http://www.xbrl.org/2003/role/presentationRef
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Reference 10: http://www.xbrl.org/2003/role/presentationRef
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Reference 11: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
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Schedule of Short-term Debt

Debt and Credit Agreements (Tables)

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]



Commercial Paper Borrowings	March 31, 2016		December 31, 2015
Generation	$	1,378	$	—
ComEd	643		294
BGE	150		210
PHI Corporate	442		484
Pepco	—		64
DPL	75		105
ACE	—		5

Schedule Of Issuance Of Long Term Debt

During the three months ended March 31, 2016, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Albany Green Energy Project Financing

LIBOR + 1.25%

November 17, 2017

Albany Green Energy biomass generation development

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.

Retirement and Redemptions of Current and Long-Term Debt

During the three months ended March 31, 2016, the following long-term debt was retired and/or redeemed:



Company	Type	Interest Rate	Maturity	Amount
Generation	AVSR DOE Nonrecourse Debt	2.29 - 3.56%	January 5, 2037	$	5
Generation	Continental Wind Nonrecourse Debt	6.00%	February 28, 2033	$	15
Generation	CEU Upstream Nonrecourse Debt	LIBOR + 2.75%	January 14, 2019	$	7
Generation	ExGen Texas Power Nonrecourse Debt	5.00%	September 18, 2021	$	2
Generation	Sacramento PV Energy Nonrecourse Debt	2.58%	December 31, 2030	$	33
Generation	Constellation Solar Horizons Nonrecourse Debt	2.56%	September 7, 2030	$	32
Generation	Kennett Square Capital Lease	7.83%	September 20, 2020	$	1
ACE	ACE Funding Transition Bonds	5.55%	October 20, 2023	$	8
ACE	ACE Funding Transition Bonds	5.05%	October 20, 2020	$	3

Income Taxes (Tables)

3 Months Ended

Mar. 31, 2016

Income Tax Disclosure [Abstract]

Effective Income Tax Rate Reconciliation



									Successor	Predecessor
	Three Months Ended March 31, 2016								March 24, 2016 to March 31, 2016	January 1, 2016 to March 23, 2016
	Exelon	Generation	ComEd	PECO	BGE	Pepco^(a)	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)	(1.1)	3.7	5.1	1.0	5.2	(2.5)	(2.7)	5.9	5.4	11.9
Qualified nuclear decommissioning trust fund income	5.6	4.2	—	—	—	—	—	—	—	—
Domestic production activities deduction	—	—	—	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	—	—	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(1.6)	(1.0)	(0.3)	(0.1)	(0.1)	—	0.1	0.2	—	(0.9)
Plant basis differences	(5.5)	—	(0.1)	(9.3)	(0.6)	2.8	0.7	0.6	—	(13.5)
Production tax credits and other credits	(5.1)	(3.9)	—	—	—	—	—	—	—	—
Non-controlling interest	0.5	0.3	—	—	—	—	—	—	—	—
Merger expenses	33.6	—	—	—	—	(16.5)	(22.1)	(17.0)	(15.1)	11.1
Other	(2.0)	(1.6)	0.4	(0.9)	—	—	0.1	0.1	0.2	3.6
Effective income tax rate	59.4%	36.7%	40.1%	25.7%	39.5%	18.8%	11.1%	24.8%	25.5%	47.2%



	Three Months Ended March 31, 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	2.6	2.7	5.0	1.2	5.3	7.2	5.3	5.7	5.9
Qualified nuclear decommissioning trust fund income	1.9	3.0	—	—	—	—	—	—	—
Domestic production activities deduction	(2.2)	(3.4)	—	—	—	—	—	—	—
Health care reform legislation	—	—	—	—	0.2	—	—	—	—
Amortization of investment tax credit, including deferred taxes on basis difference	(0.9)	(1.4)	(0.3)	(0.1)	—	(0.5)	(0.1)	(0.2)	(1.4)
Plant basis differences	(1.3)	—	(0.3)	(6.7)	(0.3)	(4.9)	(8.5)	(0.9)	(2.8)
Production tax credits and other credits	(1.8)	(2.8)	—	—	—	—	—	—	—
Non-controlling interest	(0.7)	(1.1)	—	—	—	—	—	—	—
Other	0.4	(0.2)	0.2	—	0.2	(0.7)	(0.1)	—	(1.0)
Effective income tax rate	33.0%	31.8%	39.6%	29.4%	40.4%	36.1%	31.6%	39.6%	35.7%

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

3 Months Ended

Mar. 31, 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 March 31, 2016:



Nuclear decommissioning ARO at December 31, 2015^(a)	$	8,246
Accretion expense	106
Net increase due to changes in, and timing of, estimated cash flows	60
Nuclear decommissioning ARO at March 31, 2016^(a)	$	8,412

_________


(a)	Includes $6 million and $7 million as the current portion of the ARO at March 31, 2016 and December 31, 2015 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 months ended March 31, 2016 and 2015:



	Exelon and Generation
	Three Months Ended March 31,
	2016		2015
Net unrealized gains on decommissioning trust funds — Regulatory Agreement Units^(a)	$	79	$	48
Net unrealized gains on decommissioning trust funds — Non-Regulatory Agreement Units^(b)(c)	52		40

_________


(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 $2 million and $10 million of net unrealized gain related to the Zion Station pledged assets for the three months ended March 31, 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.

Zion Station pledged assets

March 31, 2016 and December 31, 2015:



	Exelon and Generation
	March 31, 2016		December 31, 2015
Carrying value of Zion Station pledged assets	$	183	$	206
Payable to Zion Solutions^(a)	166		189
Current portion of payable to Zion Solutions^(b)	95		99
Cumulative withdrawals by Zion Solutions to pay decommissioning costs^(c)	812		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)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Schedule Of Pension And Other Postretirement Benefit Costs



	Three Months Ended March 31,
Pension and Other Postretirement Benefit Costs	2016		2015
Exelon	$	136	$	160
Generation	54		67
ComEd	41		52
PECO	8		10
BGE	16		17
BSC^(a)	14		14
Pepco^(b)	8		8
DPL^(b)	5		4
ACE^(b)	4		4
PHISCO^(a)(b)	9		8



	Successor		Predecessor
Pension and Other Postretirement Benefit Costs	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	3	$	23	$	24

_________


(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 months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
Savings Plan Matching Contributions	2016		2015
Exelon	$	26	$	22
Generation	12		13
ComEd	6		5
PECO	2		1
BGE	1		2
BSC^(a)	5		1
Pepco^(b)	1		1
DPL^(b)	1		—
PHISCO^(a)(b)	1		2



	Successor		Predecessor
Savings Plan Matching Contributions	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	—	$	3	$	3

_________


(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.

Schedule of Net Benefit Costs [Table Text Block]



	Pension Benefits Three Months Ended March 31,						Other Postretirement Benefits Three Months Ended March 31,
	2016^(a)			2015			2016^(a)			2015
Components of net periodic benefit cost:
Service cost	$	78		$	82		$	26		$	30
Interest cost	190			178			43			42
Expected return on assets	(263		)	(257		)	(38		)	(38		)
Amortization of:
Prior service cost (benefit)	3			3			(44		)	(43		)
Actuarial loss	127			143			14			20
Net periodic benefit cost	$	135		$	149		$	1		$	11

_______


(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 March 31, 2015			January 1, 2016 to March 23, 2016			Three Months Ended March 31, 2015
Service cost	$	12		$	14		$	1		$	2
Interest cost	26			27			6			6
Expected return on assets	(30		)	(35		)	(5		)	(6		)
Amortization of:
Prior service cost (benefit)	—			—			(3		)	(3		)
Actuarial loss	14			16			2			3
Net periodic benefit cost	$	22		$	22		$	1		$	2

Severance (Tables)

3 Months Ended

Mar. 31, 2016

Restructuring and Related Activities [Abstract]

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

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:



													Successor
Severance Liability	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2015	$	35		$	23		$	3	$	—	$	1	$	—	$	—	$	—	$	—
Severance charges^(a)(b)	71			7			—		—		—		51		—		—		—
Payments	(4		)	(3		)	—		—		—		—		—		—		—
Balance at March 31, 2016	$	102		$	27		$	3	$	—	$	1	$	51	$	—	$	—	$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.


(b)	Represents activity from March 24, 2016 to March 31, 2016 for PHI, Pepco, DPL and ACE.



	Exelon		Generation		ComEd		PECO		BGE
Severance benefits^(a)	$	17	$	12	$	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 three months ended March 31, 2016.

Restructuring and Related Costs



	Three Months Ended March 31,
Acquisition, Integration and Financing Costs^(a)	2016			2015
Exelon	$	102		$	108
Generation	16			7
ComEd^(b)	(8		)	3
PECO	2			1
BGE	2			1
Pepco	27			1
DPL	16			1
ACE	13			1



	Successor		Predecessor
Acquisition, Integration and Financing Costs^(a)	March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016		Three Months Ended March 31, 2015
PHI	$	56	$	29	$	8

______________


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


(b)	Excludes acquisition, integration and financing costs of $9 million incurred at ComEd that have been recorded as a regulatory asset.



											Successor
	Exelon		Generation		ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Severance benefits^(a)	$	52	$	10	$	2	$	1	$	1	$	37	$	18	$	11	$	8

______________


(a)	The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE include $9 million, $2 million, $1 million, $1 million, $18 million, $11 million and $8 million, respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations for the three months ended March 31, 2016.

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

Amounts included in the table below represent the severance liability recorded for employees of each Registrant and exclude amounts included at Exelon and billed through intercompany allocations:



													Successor
Severance Liability	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Balance at December 31, 2015	$	35		$	23		$	3	$	—	$	1	$	—	$	—	$	—	$	—
Severance charges^(a)(b)	71			7			—		—		—		51		—		—		—
Payments	(4		)	(3		)	—		—		—		—		—		—		—
Balance at March 31, 2016	$	102		$	27		$	3	$	—	$	1	$	51	$	—	$	—	$	—

______________


(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost management program.


(b)	Represents activity from March 24, 2016 to March 31, 2016 for PHI, Pepco, DPL and ACE.



	Exelon		Generation		ComEd		PECO		BGE
Severance benefits^(a)	$	17	$	12	$	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 three months ended March 31, 2016.

Changes in Accumulated Other Comprehensive Income (Tables)

3 Months Ended

Mar. 31, 2016

Changes in Accumulated Other Comprehensive Income [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

three months ended March 31, 2016 and 2015:



Three Months Ended March 31, 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	(10		)	(1		)	67			6			(3		)	59
Amounts reclassified from AOCI^(b)	3			—			(34		)	—			—			(31		)
Net current-period OCI	(7		)	(1		)	33			6			(3		)	28
Ending balance	$	(26	)	$	2		$	(2,532	)	$	(34	)	$	(6	)	$	(2,596	)
Generation^(a)
Beginning balance	$	(21	)	$	1		$	—		$	(40	)	$	(3	)	$	(63	)
OCI before reclassifications	(8		)	—			—			6			(2		)	(4		)
Amounts reclassified from AOCI^(b)	3			—			—			—			—			3
Net current-period OCI	(5		)	—			—			6			(2		)	(1		)
Ending balance	$	(26	)	$	1		$	—		$	(34	)	$	(5	)	$	(64	)
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	—			—			2			—			—			2
Amounts reclassified from AOCI^(b)	—			—			(1		)	—			—			(1		)
Net current-period OCI	—			—			1			—			—			1
Ending balance March 23, 2016^(c)	$	(8	)	$	—		$	(27	)	$	—		$	—		$	(35	)



Three Months Ended March 31, 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	(11		)	—		(26		)	(12		)	—		(49		)
Amounts reclassified from AOCI^(b)	17			—		43			—			—		60
Net current-period OCI	6			—		17			(12		)	—		11
Ending balance	$	(22	)	$	3	$	(2,623	)	$	(31	)	$	—	$	(2,673	)
Generation^(a)
Beginning balance	$	(18	)	$	1	$	—		$	(19	)	$	—	$	(36	)
OCI before reclassifications	(6		)	—		—			(12		)	—		(18		)
Amounts reclassified from AOCI^(b)	1			—		—			—			—		1
Net current-period OCI	(5		)	—		—			(12		)	—		(17		)
Ending balance	$	(23	)	$	1	$	—		$	(31	)	$	—	$	(53	)
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			—			—		1
Net current-period OCI	—			—		1			—			—		1
Ending balance	$	(9	)	$	—	$	(36	)	$	—		$	—	$	(45	)

________


(a)	All amounts are net of tax. 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 months ended March 31, 2016 and 2015.

Three Months Ended March 31, 2016



Details about AOCI components	Items reclassified out of AOCI^(a)								Affected line item in the Statement of Operations and Comprehensive Income

							Predecessor
	Three Months Ended March 31, 2016			Three Months Ended March 31, 2016			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)	$	(20	)	$	—		$	—
Actuarial losses^(b)	76			—			1
Total before tax	56			—			1
Tax benefit	(22		)	—			—
Net of tax	$	34		$	—		$	1

Total Reclassifications	$	31		$	(3	)	$	1	Comprehensive income

Three Months Ended March 31, 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	(3		)	(3		)	—			Interest expense
Total before tax	(27		)	(1		)	—
Tax benefit	10			—			—
Net of tax	$	(17	)	$	(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 benefit	28			—			1
Net of tax	$	(43	)	$	—		$	(1	)

Total Reclassifications	$	(60	)	$	(1	)	$	(1	)	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 months ended March 31, 2016 and 2015:



	Three Months Ended March 31,
	2016			2015
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	7		$	8
Actuarial loss reclassified to periodic cost	(30		)	(35		)
Pension and non-pension postretirement benefit plans valuation adjustment	—			17
Change in unrealized gain/(loss) on cash flow hedges	3			(2		)
Change in unrealized loss on equity investments	2			—
Change in unrealized gain on marketable securities	1			—
Total	$	(17	)	$	(12	)

Generation
Change in unrealized gain on cash flow hedges	$	2		$	5
Change in unrealized loss on equity investments	2			—
Total	$	4		$	5

Mezzanine Equity Mezzanine Equity (Tables)

3 Months Ended

Mar. 31, 2016

Noncontrolling Interest [Abstract]

Redeemable Noncontrolling Interest [Table Text Block]

The following table summarizes the changes in the contingently redeemable noncontrolling interest for the three months ended March 31, 2016:



Balance at December 31, 2015	$	28
Cash received from noncontrolling interest	10
Release of contingency	(19		)
Balance at March 31, 2016	$	19

Earnings Per Share and Equity (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Reconciliation of basic and diluted earnings per share



	Three Months Ended March 31,
Exelon	2016		2015
Net income attributable to common shareholders	$	173	$	693
Weighted average common shares outstanding — basic	923		862
Assumed exercise and/or distributions of stock-based awards	2		5
Weighted average common shares outstanding — diluted	925		867

Commitments and Contingencies (Tables)

3 Months Ended

Mar. 31, 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 March 31, 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)	$	1,628	$	1,560	$	16	$	22	$	2	$	1	$	—	$	—	$	—
Surety bonds^(b)	950		852		10		9		10		16		9		4		3
Financing trust guarantees	628		—		200		178		250		—		—		—		—
Nuclear insurance premiums^(c)	3,056		3,056		—		—		—		—		—		—		—
Guaranteed lease residual values^(d)	20		—		—		—		—		20		6		8		5
Total commercial commitments	$	6,282	$	5,468	$	226	$	209	$	262	$	37	$	15	$	12	$	8

________


(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 March 31, 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:



March 31, 2016	Total Environmental Investigation and Remediation Reserve		Portion of Total Related to MGP Investigation and Remediation^(a)
Exelon	$	399	$	298
Generation	68		—
ComEd	263		261
PECO	36		34
BGE	3		2
PHI (Successor)	29		1
Pepco	25		—
DPL	3		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 commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



	Total
2016^(a)	$	271
2017	21
2018	7
Total	$	299

Supplemental Financial Information (Tables)

3 Months Ended

Mar. 31, 2016

Supplemental Financial Information [Abstract]

Components of non-operating income and expenses

The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2016 and 2015:



																				Successor		Predecessor
	Three Months Ended March 31, 2016																			March 24, 2016 to March 31, 2016		January 1, 2016 to March 23, 2016
	Exelon			Generation			ComEd		PECO		BGE			Pepco		DPL		ACE		PHI		PHI
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds^(a)
Regulatory agreement units	$	34		$	34		$	—	$	—	$	—		$	—	$	—	$	—	$	—	$	—
Non-regulatory agreement units	21			21			—		—		—			—		—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	79			79			—		—		—			—		—		—		—		—
Non-regulatory agreement units	52			52			—		—		—			—		—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning	2			2			—		—		—			—		—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(95		)	(95		)	—		—		—			—		—		—		—		—
Total decommissioning-related activities	93			93			—		—		—			—		—		—		—		—
Investment income	6			1			—		—		1		^(c)	—		—		—		—		—
Long-term lease income	4			—			—		—		—			—		—		—		—		—
Interest income related to uncertain income tax positions	1			—			—		—		—			1		—		1		—		—
AFUDC — Equity	8			—			2		2		3			4		1		2		1		7
Loss on debt extinguishment	(2		)	(2		)	—		—		—			—		—		—		—		—
Other	4			1			2		—		—			4		2		1		1		(11		)
Other, net	$	114		$	93		$	4	$	2	$	4		$	9	$	3	$	4	$	2	$	(4	)



	Three Months Ended March 31, 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	$	71		$	71		$	—	$	—	$	—		$	—	$	—	$	—	$	—
Non-regulatory agreement units	29			29			—		—		—			—		—		—		—
Net unrealized gains on decommissioning trust funds
Regulatory agreement units	48			48			—		—		—			—		—		—		—
Non-regulatory agreement units	40			40			—		—		—			—		—		—		—
Net unrealized gains on pledged assets
Zion Station decommissioning	10			10			—		—		—			—		—		—		—
Regulatory offset to decommissioning trust fund-related activities^(b)	(106		)	(106		)	—		—		—			—		—		—		—
Total decommissioning-related activities	92			92			—		—		—			—		—		—		—
Investment income	1			1			—		—		1		^(c)	—		—		—		—
Long-term lease income	4			—			—		—		—			—		—		—		—
Interest income related to uncertain income tax positions	—			1			—		—		—			—		—		—		—
AFUDC — Equity	5			—			—		2		3			4		3		—		1
Terminated interest rate swaps^(d)	(23		)	3			—		—		—			—		—		—		—
Other	1			(3		)	3		—		—			5		2		2		—
Other, net	$	80		$	94		$	3	$	2	$	4		$	9	$	5	$	2	$	1

____


(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)	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.

(d)

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 three months ended March 31, 2016 and 2015:



																			Successor		Predecessor
	Three Months Ended March 31, 2016																		March 24, 2016 to March 31, 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	$	606		$	278		$	170	$	60	$	75	$	42	$	27	$	20	$	9	$	94
Amortization of regulatory assets	65			—			19		7		34		33		12		20		5		58
Amortization of intangible assets, net	14			11			—		—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	(14		)	(14		)	—		—		—		—		—		—		—		—
Nuclear fuel^(b)	283			283			—		—		—		—		—		—		—		—
ARO accretion^(c)	109			109			—		—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	1,063		$	667		$	189	$	67	$	109	$	75	$	39	$	40	$	14	$	152



	Three Months Ended March 31, 2015
													Predecessor
	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	540		$	242		$	154	$	58	$	71	$	96	$	40	$	25	$	19
Amortization of regulatory assets	58			—			21		4		35		59		22		14		24
Amortization of intangible assets, net	12			12			—		—		—		—		—		—		—
Amortization of energy contract assets and liabilities^(a)	(31		)	(32		)	—		—		—		—		—		—		—
Nuclear fuel^(b)	272			272			—		—		—		—		—		—		—
ARO accretion^(c)	97			97			—		—		—		—		—		—		—
Total depreciation, amortization, accretion and depletion	$	948		$	591		$	175	$	62	$	106	$	155	$	62	$	39	$	43

________


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


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


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

Cash Flow Supplemental Disclosures



																									Successor			Predecessor
	Three Months Ended March 31, 2016																								March 24, 2016 to March 31, 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	$	136		$	54		$	41		$	8		$	16		$	8		$	5		$	4		$	3		$	23
Loss from equity method investments	3			3			—			—			—			—			—			—			—			—
Provision for uncollectible accounts	41			6			9			16			12			5			5			7			(2		)	16
Stock-based compensation costs	44			—			—			—			—			—			—			—			—			3
Other decommissioning-related activity^(a)	(55		)	(55		)	—			—			—			—			—			—			—			—
Energy-related options^(b)	(9		)	(9		)	—			—			—			—			—			—			—			—
Amortization of regulatory asset related to debt costs	1			—			1			—			—			1			—			—			—			1
Amortization of rate stabilization deferral	20			—			—			—			20			1			4			—			—			5
Amortization of debt fair value adjustment	(3		)	(3		)	—			—			—			—			—			—			—			—
Discrete impacts from EIMA^(c)	(14		)	—			(14		)	—			—			—			—			—			—			—
Amortization of debt costs	8			4			1			1			1			—			—			—			—			—
Provision for excess and obsolete inventory	1			1			—			—			—			1			1			1			—			1
Merger-related commitments^(d)(e)	503			3			—			—			—			138			100			120			358			—
Severance costs	69			4			—			—			—			—			—			—			52			—
Asset retirement costs	—			—			—			—			—			—			4			2			—			—
Lower of cost or market inventory adjustment	36			36			—			—			—			—			—			—			—			—
Other	23			7			(6		)	(1		)	(5		)	(1		)	(1		)	(2		)	(1		)	(3		)
Total other non-cash operating activities	$	804		$	51		$	32		$	24		$	44		$	153		$	118		$	132		$	410		$	46
Non-cash investing and financing activities:
Change in capital expenditures not paid	$	(290	)	$	(234	)	$	25		$	(65	)	$	(4	)	$	9		$	8		$	(9	)	$	(7	)	$	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)	—			—			—			—			—			—			—			—			127			—
Fair value of pension obligation transferred in connection with the PHI Merger	—			—			—			—			—			—			—			—			45			—
Assumption of member purchase liability	—			—			—			—			—			—			—			—			29			—
Change in PPE related to ARO update	62			62			—			—			—			—			—			—			—			—
Indemnification of like-kind exchange position^(g)	—			—			1			—			—			—			—			—			—			—
Non-cash financing of capital projects	31			31			—			—			—			—			—			—			—			—



	Three Months Ended March 31, 2015
															Predecessor
	Exelon			Generation			ComEd		PECO			BGE			PHI		Pepco		DPL		ACE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	159		$	67		$	52	$	10		$	16		$	24	$	8	$	4	$	4
Provision for uncollectible accounts	84			4			22		33			25			16		4		7		5
Stock-based compensation costs	39			—			—		—			—			3		—		—		—
Other decommissioning-related activity^(a)	(44		)	(44		)	—		—			—			—		—		—		—
Energy-related options^(b)	9			9			—		—			—			—		—		—		—
Amortization of regulatory asset related to debt costs	3			—			2		1			—			1		1		—		—
Amortization of rate stabilization deferral	25			—			—		—			25			11		10		1		—
Amortization of debt fair value adjustment	(9		)	(4		)	—		—			—			—		—		—		—
Discrete impacts from EIMA^(c)	46			—			46		—			—			—		—		—		—
Amortization of debt costs	18			4			1		1			1			—		—		—		—
Lower of cost or market inventory adjustment	10			10			—		—			—			—		—		—		—
Other	4			(1		)	3		(1		)	(3		)	2		—		—		(1		)
Total other non-cash operating activities	$	344		$	45		$	126	$	44		$	64		$	57	$	23	$	12	$	8
Non-cash investing and financing activities:
Change in PPE related to ARO update	56			56			—		—			—			—		—		—		—
Indemnification of like-kind exchange position^(g)	—			—			2		—			—			—		—		—		—

________

(a)


(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


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


(d)	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 March 31, 2016 and December 31, 2015.



													Successor
March 31, 2016	Exelon			Generation			ComEd		PECO		BGE		PHI		Pepco		DPL		ACE
Property, plant and equipment:
Accumulated depreciation and amortization	$	16,776	^(a)	$	8,950	^(a)	$	3,716	$	3,139	$	3,069	$	4	$	2,960	$	1,140	$	983
Accounts receivable:
Allowance for uncollectible accounts	$	351		$	73		$	82	$	90	$	53	$	53	$	16	$	19	$	18



													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 $3,008 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]

The

Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Analysis and reconciliation of reportable segment information

Analysis and reconciliation of reportable segment revenues for Generation

_________

(a)


(b)	Amounts included represent activity for the PHI's successor period, March 24, 2016 through March 31, 2016. PHI includes the three reportable segments: Pepco, DPL and ACE. See tables below for PHI's predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the three months ended March 31, 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 March 31, 2016 and 2015.

(e)

Generation total revenues:



	Three Months Ended March 31, 2016							Three Months Ended March 31, 2015
	Revenues from external customers^(a)		Intersegment revenues			Total Revenues		Revenues from external customers^(a)(c)		Intersegment revenues^(c)			Total Revenues^(c)
Mid-Atlantic	$	1,532	$	(12	)	$	1,520	$	1,556	$	(43	)	$	1,513
Midwest	1,089		6			1,095		1,276		—			1,276
New England	471		(1		)	470		865		(6		)	859
New York	218		(15		)	203		307		3			310
ERCOT	163		—			163		181		(1		)	180
Other Power Regions	222		1			223		212		2			214
Total Revenues for Reportable Segments	3,695		(21		)	3,674		4,397		(45		)	4,352
Other^(b)	1,044		21			1,065		1,443		45			1,488
Total Generation Consolidated Operating Revenues	$	4,739	$	—		$	4,739	$	5,840	$	—		$	5,840

__________


(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:



	Three Months Ended March 31, 2016							Three Months Ended March 31, 2015
	RNF from external customers^(a)		Intersegment RNF			Total RNF		RNF from external customers^(a)(c)		Intersegment RNF^(c)			Total RNF^(c)
Mid-Atlantic	$	832	$	9		$	841	$	808	$	(21	)	$	787
Midwest	715		3			718		709		(6		)	703
New England	86		(5		)	81		182		(24		)	158
New York	141		(11		)	130		169		20			189
ERCOT	81		(20		)	61		88		(33		)	55
Other Power Regions	86		(10		)	76		72		(26		)	46
Total Revenues net of purchased power and fuel expense for Reportable Segments	1,941		(34		)	1,907		2,028		(90		)	1,938
Other^(b)	356		34			390		379		90			469
Total Generation Revenues net of purchased power and fuel expense	$	2,297	$	—		$	2,297	$	2,407	$	—		$	2,407

Analysis and reconciliation of reportable segment revenues for Generation

Basis of Presentation - Narrative (Details) - USD ($)		3 Months Ended
Basis of Presentation - Narrative (Details) - USD ($)	Mar. 31, 2016	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015	Jan. 01, 2014
Pepco Holdings, LLC [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		$ 1,000,000
Pepco Holdings, LLC [Member] \| Predecessor [Member]
Error Corrections and Prior Period Adjustments Restatement [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Interest			$ 1,000,000
Pepco Holdings, LLC [Member] \| Successor [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
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
Delmarva Power and Light 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
Atlantic City Electric 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		1
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		$ 1,000,000		$ 5,000,000

Variable Interest Entities - Narrative (Details)	3 Months Ended			9 Months Ended
Variable Interest Entities - Narrative (Details)	Mar. 31, 2016 USD ($) VIE	Dec. 31, 2015 USD ($) VIE	Mar. 31, 2015 USD ($)	Sep. 30, 2015 USD ($)	Jul. 31, 2014 USD ($)	Apr. 01, 2014 USD ($)
Variable Interest Entity [Line Items]
Other Commitment	$ 6,282,000,000
Variable Interest Entity, Financial or Other Support, Amount	$ 14,000,000
Number of Variable Interest Entities not consolidated by equity holders \| VIE	9	8
Number Of Variable Interest Entities Consolidated \| VIE	9	7
Guarantor Obligations, Current Carrying Value	$ 75,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	53,000,000
Payments for Restructuring	(4,000,000)
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	$ 172,000,000
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	275,000,000
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Other Commitment	$ 5,468,000,000				$ 91,000,000
Equity Method Investment, Ownership Percentage	50.01%
Related Party Transaction Required Purchase Of Power Percentage	85.00%
Related Party Purchase Of Nuclear Output By Third Party Percentage	49.99%
Payments for Restructuring	$ (3,000,000)
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
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	7,000,000
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Other Commitment	262,000,000
Baltimore Gas and Electric Company [Member] \| RSB Bond Co LLC [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE	20,000,000	$ 21,000,000
Atlantic City Electric Company [Member]
Variable Interest Entity [Line Items]
Other Commitment	8,000,000
Number Of Variable Interest Entities Consolidated \| VIE		1
Guarantor Obligations, Maximum Exposure, Undiscounted	14,000,000
Payments for Restructuring	0
Atlantic City Electric Company [Member] \| ATF [Member]
Variable Interest Entity [Line Items]
Cash Remitted To VIE	14,000,000		$ 13,000,000
Constellation Energy Nuclear Group [Member] \| Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Due from Affiliates	304,000,000					$ 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

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

Mar. 31, 2016

Dec. 31, 2015

Current Assets

^[2]

$ 928

^[1]

$ 909

Non Current Assets

^[2]

8,047

^[1]

8,009

Total Assets

^[2]

8,975

^[1]

8,918

Current Liabilities

^[2]

544

^[1]

473

^[2]

3,050

^[1]

2,927

^[2]

3,594

^[1]

3,400

111,742

95,384

Variable Interest Entity, Primary Beneficiary [Member]

^[3]

84,537

68,062

8,310

8,268

3,421

3,264

Current Assets

860

^[1]

881

Non Current Assets

7,996

^[1]

8,004

Total Assets

8,856

^[1]

8,885

Current Liabilities

400

^[1]

387

2,865

^[1]

2,884

3,265

^[1]

3,271

47,002

46,529

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

^[4]

33,649

33,559

8,190

8,235

3,094

3,135

124

122

8,361

8,295

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

^[5]

5,417

5,418

Pepco Holdings, LLC [Member] | Predecessor [Member]

124

122

16,184

Pepco Holdings, LLC [Member] | Successor [Member]

11,588

20,932

14,260

124

172

142

PEPCO Holdings Inc [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Predecessor [Member]

200

PEPCO Holdings Inc [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Successor [Member]

172

200

114

124

161

172

3,393

3,387

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

2,504

2,387

$ 161

$ 172

[1]	.
[2]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[3]	Exelon’s consolidated assets include $8,310 million and $8,268 million at March 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,421 million and $3,264 million at March 31, 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 $8,190 million and $8,235 million at March 31, 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 $3,094 million and $3,135 million at March 31, 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 March 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $41 million and $41 million at March 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

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

Mar. 31, 2016

Dec. 31, 2015

Mar. 31, 2015

Dec. 31, 2014

$ 960

$ 6,502

$ 1,825

$ 1,878

218

205

3,594

3,187

1,138

912

1,185

1,365

Inventory

1,229

1,104

1,086

752

11,364

15,334

69,406

57,439

10,526

10,342

6,688

2,672

841

758

1,398

1,445

111,742

95,384

3,640

533

2,058

1,500

2,874

2,883

Mark-to-market derivative liabilities (current liabilities)

2,260

2,376

203

205

582

100

1,008

842

13,770

9,118

29,314

23,645

8,755

8,585

3,771

3,385

1,144

117

1,886

1,491

40,812

34,658

Variable Interest Entity, Primary Beneficiary [Member]

^[1]

84,537

68,062

145

164

117

100

231

219

120

140

Inventory

186

181

877

882

5,141

5,160

2,069

2,036

135

7,433

7,386

8,310

8,268

265

111

164

216

Mark-to-market derivative liabilities (current liabilities)

115

542

472

743

666

^[2]

2,016

1,999

2,879

2,792

3,421

3,264

377

431

532

780

119

123

1,963

2,095

434

360

1,185

1,365

Inventory

884

880

719

535

6,171

6,342

26,166

25,843

10,526

10,342

799

733

650

627

47,002

46,529

1,529

177

1,290

1,583

Mark-to-market derivative liabilities (current liabilities)

673

935

177

182

100

333

356

4,775

4,933

7,945

7,936

8,588

8,431

106

117

637

602

19,999

19,757

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

^[3]

33,649

33,559

145

164

231

219

120

140

Inventory

186

181

808

854

5,141

5,160

2,069

2,036

7,382

7,381

8,190

8,235

128

164

216

Mark-to-market derivative liabilities (current liabilities)

113

399

386

559

623

2,016

1,999

^[2]

2,695

2,749

3,094

3,135

328

300

112

Inventory

819

845

6,684

6,597

8,361

8,295

150

210

378

206

209

151

110

1,138

1,134

1,481

1,480

2,546

2,552

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

^[4]

5,417

5,418

Inventory

Mark-to-market derivative liabilities (current liabilities)

^[2]

124

122

Inventory

Mark-to-market derivative liabilities (current liabilities)

PEPCO Holdings Inc [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Predecessor [Member]

Inventory

Mark-to-market derivative liabilities (current liabilities)

124

^[2]

124

PEPCO Holdings Inc [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Successor [Member]

172

Inventory

Mark-to-market derivative liabilities (current liabilities)

142

^[2]

142

200

122

$ 6

$ 2

146

156

242

Inventory

485

546

2,384

2,322

3,393

3,387

101

444

297

1,144

1,153

916

937

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

2,504

2,387

Inventory

Mark-to-market derivative liabilities (current liabilities)

114

124

^[2]

114

124

$ 161

$ 172

[1]	Exelon’s consolidated assets include $8,310 million and $8,268 million at March 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,421 million and $3,264 million at March 31, 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 $8,190 million and $8,235 million at March 31, 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 $3,094 million and $3,135 million at March 31, 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 March 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $41 million and $41 million at March 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Mar. 31, 2016

Dec. 31, 2015

^[1]

$ 621

$ 427

Exelon's ownership interest in VIE

^[1]

262

147

^[1]

Other ownership interests in VIE

^[1]

284

269

Assets Held-in-trust, Noncurrent

183

206

Commercial Agreement Variable Interest Entities [Member]

^[1]

264

263

Exelon's ownership interest in VIE

^[1]

^[1]

Other ownership interests in VIE

^[1]

249

241

Equity Method Investment Variable Interest Entities [Member]

^[1]

357

164

Exelon's ownership interest in VIE

^[1]

247

125

^[1]

Other ownership interests in VIE

^[1]

Investments [Member]

Investments [Member] | Maximum [Member]

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]

Contract Intangible Asset [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]

Payment Guarantee [Member]

Payment Guarantee [Member] | Maximum [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]

^[2]

Assets Held-in-trust, Noncurrent

183

206

Payable to Zion Solutions

^[3]

166

$ 189

Exelon Generation Co L L C [Member] | Investments [Member] | Maximum [Member]

Schedule of Equity Method Investments [Line Items]

$ 18

[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 $183 million and $206 million as of March 31, 2016 and December 31, 2015, respectively; offset by payables to ZionSolutions LLC of $166 million and $189 million as of March 31, 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 ($)	3 Months Ended
	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015	Dec. 31, 2015	Jul. 31, 2014
Business Acquisition [Line Items]
Revenues	$ 7,573,000,000		$ 8,830,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross	6,645,000,000		15,000,000
Business Combination, Integration Related Costs	102,000,000		108,000,000
Investments	$ 455,000,000			$ 639,000,000
Cash offered in exchange for each share of PHI stock	$ 27.25
Other noncurrent assets	$ 1,398,000,000			1,445,000,000
Other Commitment	6,282,000,000
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent	59,000,000
Business Combination, Contingent Consideration, Asset	235,000,000
Net income	123,000,000		738,000,000
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	130,000,000
Pepco Holdings, LLC [Member]
Business Acquisition [Line Items]
Revenues	107,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment	508,000,000
Net income	(315,000,000)
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 Inc [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross	7,142,000,000
Other Commitment	444,000,000
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Revenues	4,739,000,000		5,840,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross	1,000,000		15,000,000
Business Combination, Integration Related Costs	16,000,000		7,000,000
Investments	$ 250,000,000			210,000,000
Equity Method Investment, Ownership Percentage	50.01%
Other noncurrent assets	$ 650,000,000			627,000,000
Total liabilities held for sale (b)	5,000,000
Gain (Loss) on Disposition of Property Plant Equipment	32,000,000
Other Commitment	5,468,000,000				$ 91,000,000
Net income	257,000,000		485,000,000
Atlantic City Electric Company [Member]
Business Acquisition [Line Items]
Revenues	291,000,000		334,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs	13,000,000		1,000,000
Other noncurrent assets	22,000,000			19,000,000
Total assets held for sale	1,000,000
Other Commitment	8,000,000
Net income	(100,000,000)		9,000,000
Atlantic City Electric Company [Member] \| Pepco Holdings, LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment	120,000,000
Equity Contribution	49,000,000
Potomac Electric Power Company [Member]
Business Acquisition [Line Items]
Revenues	551,000,000		545,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Investments	99,000,000			68,000,000
Other noncurrent assets	5,000,000			4,000,000
Total assets held for sale	4,000,000
Gain (Loss) on Disposition of Property Plant Equipment	8,000,000
Other Commitment	15,000,000
Net income	(108,000,000)		26,000,000
Potomac Electric Power Company [Member] \| Pepco Holdings, LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment	139,000,000
Equity Contribution	73,000,000
Delmarva Power and Light Company [Member]
Business Acquisition [Line Items]
Revenues	362,000,000		421,000,000
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Combination, Integration Related Costs	16,000,000		1,000,000
Other noncurrent assets	8,000,000			$ 2,000,000
Other Commitment	12,000,000
Net income	(72,000,000)		$ 32,000,000
Delmarva Power and Light Company [Member] \| Pepco Holdings, LLC [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Other Commitment	104,000,000
Equity Contribution	$ 46,000,000

Mergers, Acquisitions, and Dispositions - Assets Disposition Table (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Assets Disposition Table [Line Items]
Payments to Acquire Businesses, Gross	$ 6,645	$ 15
Other current liabilities	$ 1,008		$ 842

Mergers, Acquisitions, and Dispositions Merger Transaction Table (Details) - USD ($) $ / shares in Units, shares in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015	Dec. 31, 2015
Business Acquisition, Share Price	$ 27.25
Investments	$ 455,000,000			$ 639,000,000
Shares, Issued	956,802			954,668
Payments to Acquire Businesses, Gross	$ 6,645,000,000		$ 15,000,000
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	Mar. 31, 2016 USD ($)
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets	$ 2,107
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	11,071
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedAssets	5,118
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Assets	656
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	22,968
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	3,425
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	1,550
BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRegulatedLiabilities	297
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Long-term Debt	6,076
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	191
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	15,826
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	4,016
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	3,441
_BusinessCombinationRecognizedIdentifiableAssetsAcquiredAndLiabilitiesAssumedRetirmentObligations	846
Potomac Electric Power Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	1,695
Delmarva Power and Light Company [Member]
Business Acquisition [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	$ 1,182

Mergers, Acquisitions, and Dispositions Goodwill Amortization Schedule (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	$ 4,016
Goodwill, Gross	6,688	$ 2,672
Goodwill, Acquired During Period	4,016
Atlantic City Electric Company [Member]
Goodwill [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	1,140
Pepco Holdings, LLC [Member]
Goodwill [Line Items]
Goodwill, Gross	4,016
Goodwill, Acquired During Period	$ 4,016

Mergers, Acquisitions, and Dispositions ProForma Impact of Merger (Details) - USD ($) $ / shares in Thousands, $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Business Combination Proforma Non recurring Cost	$ 639	$ 116	$ 92
BusinessCombinationProformaIntercompanyRevenue	170	122	559
Business Acquisition, Pro Forma Revenue	8,556	10,062	33,823
Business Acquisition, Pro Forma Net Income (Loss)	$ 577	$ 800	$ 2,618
Business Acquisition, Pro Forma Earnings Per Share, Basic	$ 630	$ 870	$ 2,850
Business Acquisition, Pro Forma Earnings Per Share, Diluted	$ 620	$ 870	$ 2,840

Mergers, Acquisitions, and Dispositions Merger Integration Related Costs Table (Details) - USD ($) $ in Millions		3 Months Ended
	Mar. 31, 2016	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015
Business Combination, Integration Related Costs		$ 102		$ 108
Exelon Generation Co L L C [Member]
Business Combination, Integration Related Costs		16		7
Commonwealth Edison Co [Member]
Business Combination, Integration Related Costs		(8)		3
PECO Energy Co [Member]
Business Combination, Integration Related Costs		2		1
Baltimore Gas and Electric Company [Member]
Business Combination, Integration Related Costs		2		1
Pepco Holdings, LLC [Member]
Business Combination, Integration Related Costs		27		1
Delmarva Power and Light Company [Member]
Business Combination, Integration Related Costs		16		1
Atlantic City Electric Company [Member]
Business Combination, Integration Related Costs		13		1
Successor [Member] \| Pepco Holdings, LLC [Member]
Business Combination, Integration Related Costs	$ 56
Predecessor [Member] \| Pepco Holdings, LLC [Member]
Business Combination, Integration Related Costs			$ 29	$ 8
Regulatory Assets [Member] \| Commonwealth Edison Co [Member]
Business Combination, Integration Related Costs		$ 9

Regulatory Matters - Narrative (Details)					1 Months Ended				3 Months Ended				12 Months Ended
Regulatory Matters - Narrative (Details)	Mar. 31, 2016 USD ($)	Dec. 08, 2014	Feb. 27, 2013	Apr. 30, 2012 MW	Aug. 31, 2015 USD ($)	Aug. 31, 2014 USD ($)	May 31, 2014 USD ($)	Mar. 31, 2013 USD ($)	Mar. 31, 2016 USD ($)	Mar. 23, 2016 USD ($)	Dec. 31, 2015 USD ($)	Mar. 31, 2015	Dec. 31, 2015 USD ($)	Jul. 31, 2014 USD ($)	Aug. 31, 2010 USD ($)
Regulatory Matters Additional Narrative Information [Line Items]
Capital Expenditures Incurred but Not yet Paid									$ (290,000,000)
Regulatory Liabilities	$ 4,890,000,000								4,890,000,000		$ 4,570,000,000		$ 4,570,000,000
Regulatory assets	10,407,000,000								$ 10,407,000,000		6,065,000,000		6,065,000,000
Transmission Rate Formula, First Basis Points Credited									0.50%
Regulatory Liability, Current	512,000,000								$ 512,000,000		369,000,000		369,000,000
Other Commitment	$ 6,282,000,000								$ 6,282,000,000
Rate of Return on Common Equity, Incentive Basis Points	0.50%								0.50%
Fair Value, Net Asset (Liability)	$ 2,500,000,000								$ 2,500,000,000
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Capital Expenditures Incurred but Not yet Paid									25,000,000
Regulatory Liabilities	$ 3,639,000,000								3,639,000,000		$ 3,614,000,000		$ 3,614,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 138,000,000
Requested Debt and Equity Return on Distribution									6.71%			6.69%
Weighted Average Debt And Equity Return	8.47%								8.47%		8.61%		8.61%
Gross transmission revenue requirement									$ 90,000,000
Transmission revenue true up									4,000,000
Net transmission revenue requirement									$ 94,000,000
Public Utilities, Requested Rate Increase (Decrease), Percentage									8.64%			8.59%
Regulatory assets	$ 925,000,000								$ 925,000,000		$ 895,000,000		$ 895,000,000
Rate Of Return On Common Equity									11.50%
Regulatory Liability, Current	150,000,000								$ 150,000,000		155,000,000		155,000,000
Other Commitment	226,000,000								226,000,000
Prior Year Revenue Adjustment													1,000,000
Current Year Revenue Adjustment									139,000,000
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Capital Expenditures Incurred but Not yet Paid									(65,000,000)
Regulatory Liabilities	655,000,000								655,000,000		639,000,000		639,000,000
Regulatory assets	1,605,000,000								1,605,000,000		1,583,000,000		1,583,000,000
Regulatory Liability, Current	134,000,000								134,000,000		112,000,000		112,000,000
Other Commitment	209,000,000								209,000,000
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Customer Refund Liability, Noncurrent											13,700,000		13,700,000
Capital Expenditures Incurred but Not yet Paid									(4,000,000)
Regulatory Liabilities	$ 212,000,000								$ 212,000,000		222,000,000		$ 222,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount											$ 197,000,000
Requested ROE			8.70%
Weighted Average Debt And Equity Return	8.09%								8.09%		8.46%		8.46%
Proposed Capital Expenditure									$ 13,000,000
Gross transmission revenue requirement									12,000,000
Transmission revenue true up									3,000,000
Net transmission revenue requirement									15,000,000
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
Regulatory assets	$ 499,000,000								$ 499,000,000		$ 514,000,000		$ 514,000,000
Customer Refund											13,700,000		13,700,000
Rate Of Return On Common Equity									10.50%
Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint			10.80%
Regulatory Liability, Current	61,000,000								$ 61,000,000		38,000,000		38,000,000
Other Commitment	262,000,000								262,000,000
Projected Investment In Smartmeters											141,000,000		141,000,000
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Unregulated Operating Revenue									101,000,000
Customer Refund Liability, Noncurrent	20,000,000								20,000,000
Capital Expenditures Incurred but Not yet Paid									(234,000,000)
Customer Refund	20,000,000								20,000,000
License Costs									25,000,000
Other Commitment	5,468,000,000								5,468,000,000					$ 91,000,000
Exelon Generation Co L L C [Member] \| Reserve for Environmental Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Other Commitment	3,500,000								3,500,000
Exelon Generation Co L L C [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Minimum Purchase Obligation	3,000,000								3,000,000
Exelon Generation Co L L C [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maximum Purchase Obligation	7,000,000								7,000,000
PEPCO Holdings Inc [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Capital Expenditures Incurred but Not yet Paid	(7,000,000)									$ 11,000,000
Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint		11.30%
Other Commitment	37,000,000								37,000,000
Potomac Electric Power Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Customer Refund Liability, Noncurrent											14,200,000		14,200,000
Capital Expenditures Incurred but Not yet Paid									9,000,000
Regulatory Liabilities	55,000,000								$ 55,000,000		44,000,000		44,000,000
Requested Debt and Equity Return on Distribution									10.60%
Requested increase in electric revenues	127,000,000								$ 127,000,000
Proposed Capital Expenditure									16,000,000
Regulatory assets	663,000,000								663,000,000		661,000,000		661,000,000
Customer Refund											14,200,000		14,200,000
Power Plant Output \| MW				661,000,000
CapitalProjectFundedByEntity							$ 500,000,000
Capital ProjectFundedByBonds							375,000,000
CapitalProjectFundedByAgency							125
Regulatory Liability, Current	26,000,000								26,000,000		15,000,000		15,000,000
Other Commitment	15,000,000								15,000,000
Projected Capital Expenditures							$ 1,000,000,000		32,000,000
Potomac Electric Power Company [Member] \| Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Power Plant Output \| MW				650,000,000
Potomac Electric Power Company [Member] \| Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Power Plant Output \| MW				700,000,000
Delmarva Power and Light Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Customer Refund Liability, Noncurrent											11,900,000		11,900,000
Capital Expenditures Incurred but Not yet Paid									8,000,000
Regulatory Liabilities	166,000,000								166,000,000		160,000,000		160,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount								$ 42,000,000
Public Utilities, Approved Rate Increase (Decrease), Amount						$ 15,000,000
Approved ROE						9.70%
ICC Approved Rate Increase (Decrease), Amount						$ 15,000,000
Regulatory assets	295,000,000								295,000,000		299,000,000		299,000,000
Customer Refund											11,900,000		11,900,000
Regulatory Liability, Current	57,000,000								57,000,000		49,000,000		49,000,000
Other Commitment	12,000,000								12,000,000
Prior Year Revenue Adjustment					$ 0.26
Atlantic City Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Customer Refund Liability, Noncurrent											9,500,000		9,500,000
Capital Expenditures Incurred but Not yet Paid									(9,000,000)
Regulatory Liabilities	27,000,000								27,000,000		25,000,000		25,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount									19
Public Utilities, Interim Rate Increase (Decrease), Amount									9
Requested increase in electric revenues	0								$ 0
Requested Rate Of Return Common Equity Electric Distribution									0.106
Regulatory assets	419,000,000								$ 419,000,000		414,000,000		414,000,000
Customer Refund											9,500,000		9,500,000
Regulatory Liability, Current	22,000,000								22,000,000		18,000,000		18,000,000
Other Commitment	8,000,000								8,000,000
Adjustment To Electric Revenues Increase Requested									176
AMI Expenses [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets	$ 212,000,000								$ 212,000,000		$ 196,000,000		$ 196,000,000
FERC Transmission Complaint [Member] \| Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Approved ROE									10.00%

Regulatory Matters Regulatory Matters - Purchase of Receivables Programs (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Purchase Of Receivables [Line Items]
Purchased receivables	$ 343	$ 229
Allowance for uncollectible accounts	(38)	(31)
Purchased receivables, net	$ 305	198
Discount rate	1.00%
Commonwealth Edison Co [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	$ 96	103
Allowance for uncollectible accounts	(16)	(16)
Purchased receivables, net	80	87
PECO Energy Co [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	75	67
Allowance for uncollectible accounts	(8)	(7)
Purchased receivables, net	67	60
Baltimore Gas and Electric Company [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	66	59
Allowance for uncollectible accounts	(8)	(8)
Purchased receivables, net	58	51
PEPCO Holdings Inc [Member] \| Predecessor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables		100
Allowance for uncollectible accounts		(6)
Purchased receivables, net		94
PEPCO Holdings Inc [Member] \| Successor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	106
Allowance for uncollectible accounts	(6)
Purchased receivables, net	100
Potomac Electric Power Company [Member] \| Predecessor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables		70
Allowance for uncollectible accounts		(4)
Purchased receivables, net		66
Potomac Electric Power Company [Member] \| Successor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	77
Allowance for uncollectible accounts	(4)
Purchased receivables, net	73
Delmarva Power and Light Company [Member] \| Predecessor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables		11
Allowance for uncollectible accounts		0
Purchased receivables, net		11
Delmarva Power and Light Company [Member] \| Successor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	11
Allowance for uncollectible accounts	0
Purchased receivables, net	11
Atlantic City Electric Company [Member] \| Predecessor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables		19
Allowance for uncollectible accounts		(2)
Purchased receivables, net		$ 17
Atlantic City Electric Company [Member] \| Successor [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	18
Allowance for uncollectible accounts	(2)
Purchased receivables, net	$ 16

Regulatory Matters Net Regulatory Asset or Liability (Details) (Details) - Federal Energy Regulatory Commission [Member] - Electric Transmission [Member] - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	$ 60	$ 43
Commonwealth Edison Co [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	31	31
Baltimore Gas and Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	17	12
Pepco Holdings, LLC [Member] \| Predecessor [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets		14
Pepco Holdings, LLC [Member] \| Successor [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	12
Potomac Electric Power Company [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	4	5
Delmarva Power and Light Company [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	7	7
Atlantic City Electric Company [Member]
Public Utilities, General Disclosures [Line Items]
Net Regulatory Assets	$ 1	$ 2

Investment in Constellation Energy Nuclear Group, LLC - Schedule of Assets and Liabilities of CENG (Details) $ in Millions	Mar. 31, 2016 USD ($)
Schedule of Equity Method Investments [Line Items]
Current assets	$ 2,107
Property, plant and equipment	11,071
Total assets	22,968
Current liabilities	3,425
Unamortized energy contract liabilities	1,550
Other liabilities	191
Total liabilities	15,826
Total net assets	$ 7,142

Investment in Constellation Energy Nuclear Group LLC - Narrative (Details) - USD ($)

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Apr. 01, 2014

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 53,000,000

7,573,000,000

$ 8,830,000,000

Other Comprehensive Income (Loss), Tax

^[1]

(2,596,000,000)

(2,673,000,000)

$ (2,624,000,000)

$ (2,684,000,000)

(17,000,000)

(12,000,000)

Guarantor Obligations, Current Carrying Value

75,000,000

Business Combination, Integration Related Costs

$ 102,000,000

108,000,000

Schedule of Equity Method Investments [Line Items]

Equity Method Investment, Ownership Percentage

50.01%

Payments of Distributions to Affiliates

$ 55,000,000

1,356,000,000

49.99%

Total equity investment earnings (losses) - CENG

(19,000,000)

$ 4,739,000,000

5,840,000,000

Other Comprehensive Income (Loss), Tax

^[1]

(64,000,000)

(53,000,000)

$ (63,000,000)

$ (36,000,000)

$ 4,000,000

5,000,000

85.00%

Business Combination, Integration Related Costs

$ 268,000,000

211,000,000

16,000,000

7,000,000

Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]

Schedule of Equity Method Investments [Line Items]

Other Comprehensive Income (Loss), Tax

$ 306,000,000

17,000,000

Investment in CENG

1,900,000,000

$ 77,000,000

Electricite De France LLC [Member]

Schedule of Equity Method Investments [Line Items]

15.00%

Constellation Energy Nuclear Group [Member] | Exelon Generation Co L L C [Member]

Schedule of Equity Method Investments [Line Items]

Due from Affiliates

$ 304,000,000

$ 400,000,000

Net Income (Loss) Attributable to Parent

93,000,000

Payment Guarantee [Member] | Constellation Energy Nuclear Group [Member]

Schedule of Equity Method Investments [Line Items]

Financial Guarantee [Member] | Constellation Energy Nuclear Group [Member]

245,000,000

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 165,000,000

Variable Interest Entity, Primary Beneficiary [Member]

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Current Carrying Value

275,000,000

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

Schedule of Equity Method Investments [Line Items]

Guarantor Obligations, Current Carrying Value

$ 7,000,000

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

Impairment of Long-Lived Assets (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Estimated residual value of leased assets	$ 356
Proceeds From Lease Termination	360	$ 0
Gain (Loss) on Contract Termination	4
Operating and maintenance	2,835	$ 2,081
Assets	111,742		$ 95,384
Constellation Energy Group LLC [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Tangible Asset Impairment Charges	119
Assets	$ 63

Impairment of Long-lived Assets - Components of the Net Investment in Long-term Leases (Details) $ in Millions	Mar. 31, 2016 USD ($)
Property, Plant and Equipment [Abstract]
Estimated residual value of leased assets	$ 356

Implications of Potential Early Plant Retirements Implications of Potential Early Plant Retirement (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	$ 1,229	$ 1,104
Property, plant and equipment, net	69,406	$ 57,439
Quad Cities [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	47
Nuclear Fuel, Net of Amortization	213
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	28
Asset Retirement Obligation	(706)
Property, plant and equipment, net	1,014
Clinton [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	58
Nuclear Fuel, Net of Amortization	95
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	11
Asset Retirement Obligation	(407)
Property, plant and equipment, net	574
Ginna [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	30
Nuclear Fuel, Net of Amortization	54
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	11
Asset Retirement Obligation	(651)
Property, plant and equipment, net	127
Nuclear Plant [Member]
Property, Plant and Equipment [Line Items]
Inventory, Raw Materials and Supplies, Gross	135
Nuclear Fuel, Net of Amortization	362
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	50
Asset Retirement Obligation	(1,764)
Property, plant and equipment, net	$ 1,715

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - Fair Value, Inputs, Level 3 [Member] - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2014	Dec. 31, 2015
Exelon Generation Co L L C [Member] \| Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ 903,000,000		$ 857,000,000
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	7		11
Forward gas price assets	0.58		1.18
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	88		88
Forward gas price assets	$ 7.67		8.95
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	5.00%	5.00%
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	184.00%	152.00%
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 7,000,000		7,000,000
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	9		13
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	$ 83		$ 78
Commonwealth Edison Co [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]
Fair Value Inputs [Abstract]
Forward heat rate	(8.00%)	(8.00%)
Commonwealth Edison Co [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]
Fair Value Inputs [Abstract]
Forward heat rate	(9.00%)	(9.00%)

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Derivative Asset, Current	$ 1,185	$ 1,365
Derivative Asset, Noncurrent	841	758
Derivative Liability, Current	203	205
Derivative Liability, Noncurrent	408	374
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Asset, Current	1,185	1,365
Derivative Asset, Noncurrent	799	733
Derivative Liability, Current	177	182
Derivative Liability, Noncurrent	166	150
InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Derivative Asset, Current	13	15
Derivative Asset, Noncurrent	53	39
Derivative Asset	66	54
Derivative Liability, Current	8	8
Derivative Liability, Noncurrent	18	8
Derivative Liability	26	16
Derivative, Fair Value, Net	40	38
InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Asset, Current	13	15
Derivative Asset, Noncurrent	11	14
Derivative Asset	24	29
Derivative Liability, Current	8	8
Derivative Liability, Noncurrent	15	8
Derivative Liability	23	16
Derivative, Fair Value, Net	1	13
InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member] \| Economic Hedging Instrument [Member]
Derivative [Line Items]
Derivative Asset, Current	10	10
Derivative Asset, Noncurrent	10	10
Derivative Asset	20	20
Derivative Liability, Current	3	2
Derivative Liability, Noncurrent	5	1
Derivative Liability	8	3
Derivative, Fair Value, Net	12	17
InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member] \| Proprietary Trading [Member]
Derivative [Line Items]
Derivative Asset, Current	8	10
Derivative Asset, Noncurrent	5	5
Derivative Asset	13	15
Derivative Liability, Current	6	9
Derivative Liability, Noncurrent	5	3
Derivative Liability	11	12
Derivative, Fair Value, Net	2	3
InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member] \| Collateral And Netting [Member]
Derivative [Line Items]
Derivative Asset, Current	(5)	(5)
Derivative Asset, Noncurrent	(4)	(1)
Derivative Asset	(9)	(6)
Derivative Liability, Current	(9)	(11)
Derivative Liability, Noncurrent	(7)	(4)
Derivative Liability	(16)	(15)
Derivative, Fair Value, Net	7	9
Interest Rate Swap [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Liability, Current	3
Designated as Hedging Instrument [Member] \| InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Derivative Asset, Current	0	0
Derivative Asset, Noncurrent	42	25
Derivative Asset	42	25
Derivative Liability, Current	0	0
Derivative Liability, Noncurrent	3	0
Derivative Liability	3	0
Derivative, Fair Value, Net	39	25
Designated as Hedging Instrument [Member] \| InterestRateAndForeignExchangeContract [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Asset, Current	0	0
Derivative Asset, Noncurrent	0	0
Derivative Asset	0	0
Derivative Liability, Current	8	8
Derivative Liability, Noncurrent	12	8
Derivative Liability	20	16
Derivative, Fair Value, Net	$ (20)	$ (16)

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Gain (Loss) on Cash Flow Hedge Ineffectiveness, Net

^[1]

$ 2

Derivative, Loss on Derivative

$ 9

(7)

Derivative, Loss on Derivative

^[1]

Fair Value Hedging [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

Derivative, Loss on Derivative

^[1]

(1)

Interest Expense [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]

$ (15)

Gain (Loss) on Fair Value Hedges Recognized in Earnings

$ (1)

[1]	For the three months ended March 31, 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

Mar. 31, 2016

Dec. 31, 2015

$ 1,185

$ 1,365

841

758

(203)

(205)

(408)

(374)

Derivative [Member]

1,172

1,350

Total mark-to-market derivative net assets (liabilities)

788

719

1,375

1,506

1,960

2,069

(195)

(197)

(390)

(366)

(585)

(563)

1,185

1,365

799

733

(177)

(182)

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]

(166)

(150)

Total mark-to-market derivative net assets (liabilities)

602

516

Current assets collateral offset

303

352

Noncurrent assets collateral offset

146

180

Current liabilities collateral offset

410

480

Noncurrent liabilities collateral offset

180

222

Total cash collateral received net of cash collateral posted

1,039

(1,234)

8,228

7,096

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member]

(7,626)

(6,580)

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member]

5,851

5,236

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

2,377

1,860

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]

(5,570)

(4,907)

Exelon Generation Co L L C [Member] | Derivative [Member]

(2,056)

(1,673)

Total mark-to-market derivative net assets (liabilities)

^[1]

1,640

1,753

^[1]

1,960

2,069

Exelon Generation Co L L C [Member] | Derivative [Member] | Other Current Assets [Member]

^[1]

(320)

(316)

Exelon Generation Co L L C [Member] | Derivative [Member] | Other Noncurrent Assets [Member]

^[1]

1,172

1,350

Exelon Generation Co L L C [Member] | Derivative [Member] | Other Current Liabilities [Member]

^[1]

788

719

Exelon Generation Co L L C [Member] | Derivative [Member] | Other Noncurrent Liabilities [Member]

^[1]

(169)

(174)

Exelon Generation Co L L C [Member] | Proprietary Trading [Member]

^[1]

(151)

(142)

Total mark-to-market derivative net assets (liabilities)

(1)

143

130

Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Other Current Assets [Member]

(144)

(127)

Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Other Noncurrent Assets [Member]

113

108

Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Other Current Liabilities [Member]

Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Other Noncurrent Liabilities [Member]

(104)

(94)

Exelon Generation Co L L C [Member] | Collateral And Netting [Member]

(40)

(33)

Total mark-to-market derivative net assets (liabilities)

^[2]

1,039

1,234

^[2]

(6,411)

(5,157)

Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | Other Current Assets [Member]

^[2]

7,450

6,391

Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | Other Noncurrent Assets [Member]

(4,792)

(3,994)

Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | Other Current Liabilities [Member]

(1,619)

(1,163)

Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | Other Noncurrent Liabilities [Member]

5,505

4,827

1,945

1,564

(26)

(23)

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]

(239)

(224)

Total mark-to-market derivative net assets (liabilities)

^[3]

(265)

(247)

^[3]

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member]

^[3]

(265)

(247)

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member]

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]

(23)

Delmarva Power and Light Company [Member] | Designated as Hedging Instrument [Member]

239

(224)

Total mark-to-market derivative net assets (liabilities)

(1)

(2)

Delmarva Power and Light Company [Member] | Designated as Hedging Instrument [Member] | Other Current Assets [Member]

Delmarva Power and Light Company [Member] | Designated as Hedging Instrument [Member] | Other Noncurrent Assets [Member]

Delmarva Power and Light Company [Member] | Designated as Hedging Instrument [Member] | Other Current Liabilities [Member]

Delmarva Power and Light Company [Member] | Designated as Hedging Instrument [Member] | Other Noncurrent Liabilities [Member]

Delmarva Power and Light Company [Member] | Derivative [Member]

Total mark-to-market derivative net assets (liabilities)

^[4]

Delmarva Power and Light Company [Member] | Derivative [Member] | Other Current Assets [Member]

^[4]

Delmarva Power and Light Company [Member] | Derivative [Member] | Other Noncurrent Assets [Member]

^[4]

Delmarva Power and Light Company [Member] | Derivative [Member] | Other Current Liabilities [Member]

^[4]

Delmarva Power and Light Company [Member] | Derivative [Member] | Other Noncurrent Liabilities [Member]

^[4]

Delmarva Power and Light Company [Member] | Collateral And Netting [Member]

^[4]

Total mark-to-market derivative net assets (liabilities)

Delmarva Power and Light Company [Member] | Collateral And Netting [Member] | Other Current Assets [Member]

(1)

(2)

Delmarva Power and Light Company [Member] | Collateral And Netting [Member] | Other Noncurrent Assets [Member]

Delmarva Power and Light Company [Member] | Collateral And Netting [Member] | Other Current Liabilities [Member]

Delmarva Power and Light Company [Member] | Collateral And Netting [Member] | Other Noncurrent Liabilities [Member]

(1)

(2)

Total mark-to-market derivative net assets (liabilities)

PHI PEPCO [Member] | Derivative [Member]

$ 0

Total mark-to-market derivative net assets (liabilities)

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

Mar. 31, 2016

Mar. 31, 2015

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

$ 184

$ 363

Reclassifications from accumulated OCI to net income

4,473

5,632

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

151

226

Reclassifications from accumulated OCI to net income

4,471

5,629

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

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]

^[1]

(2)

(10)

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(2)

Accumulated OCI derivative gain - Beginning Balance

^[2]

(21)

Effective portion of changes in fair value

^[2]

(8)

Total Cash Flow Hedges [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]

(26)

(22)

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Total Cash Flow Hedges [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(26)

(23)

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Accumulated OCI derivative gain - Beginning Balance

^[2]

(19)

(28)

Effective portion of changes in fair value

^[2]

(10)

Total Cash Flow Hedges [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Accumulated OCI derivative gain - Beginning Balance

^[2]

(18)

Cash Flow Hedging [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Other, net [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]

^[1]

(2)

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

Other, net [Member] | Total Cash Flow Hedges [Member] | Operating Revenue [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

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]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

Interest Expense [Member] | Total Cash Flow Hedges [Member] | Operating Revenue [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

$ 3

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]

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] | Operating Revenue One [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]

Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion

$ (2)

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

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative [Line Items]
Change in fair value	$ 152	$ 85
Reclassification to realized at settlement	(44)	66
Net mark-to-market gains (losses)	108	151
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value	152	85
Reclassification to realized at settlement	(44)	66
Net mark-to-market gains (losses)	108	151
Other Segments [Member]
Derivative [Line Items]
Change in fair value	(3)	(65)
Reclassification to realized at settlement	(2)	(2)
Net mark-to-market gains (losses)	103	84
Purchased Power [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value	(3)	13
Reclassification to realized at settlement	(2)	(2)
Net mark-to-market gains (losses)	103	162
Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value	(127)	(79)
Reclassification to realized at settlement	167	87
Net mark-to-market gains (losses)	40	8
Interest Expense [Member]
Derivative [Line Items]
Change in fair value		0
Reclassification to realized at settlement		0
Net mark-to-market gains (losses)		0
Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value	279	164
Reclassification to realized at settlement	(211)	(21)
Net mark-to-market gains (losses)	68	143
Interest Rate Swap [Member] \| Other Segments [Member]
Derivative [Line Items]
Change in fair value		(78)
Reclassification to realized at settlement		0
Net mark-to-market gains (losses)		(78)
Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value	0	0
Reclassification to realized at settlement	0	0
Net mark-to-market gains (losses)	40	8
Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value	(3)	13
Reclassification to realized at settlement	(2)	(2)
Net mark-to-market gains (losses)	63	154
Interest Rate Swap [Member] \| Other Segments [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	(5)	(67)
Interest Rate Swap [Member] \| Purchased Power [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	(5)	11
Interest Rate Swap [Member] \| Interest Rate Swap [Member] \| Other Segments [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)		(78)
Interest Rate Swap [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	0	0
Interest Rate Swap [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	$ (5)	$ 11

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Derivative [Line Items]
Proprietary Trading Activities Change In Fair Value	$ (2)	$ 4
Proprietary Trading Activities Reclassification To Realized At Settlement	1	(4)
Proprietary Trading Activities Gain Loss Net	3	3
Operating Revenue [Member]
Derivative [Line Items]
Proprietary Trading Activities Change In Fair Value	7	1
Proprietary Trading Activities Reclassification To Realized At Settlement	(3)	2
Proprietary Trading Activities Gain Loss Net	4	3
Interest Rate Swap [Member] \| Operating Revenue [Member]
Derivative [Line Items]
Proprietary Trading Activities Gain Loss Net	(1)	$ 0
PHI PEPCO [Member] \| Exelon Generation Co L L C [Member]
Derivative [Line Items]
Due From Affiliate Current Electric Utility	$ 36

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) - Exelon Generation Co L L C [Member]
$ in Millions

Mar. 31, 2016

USD ($)

Investor-owned utilities, marketers and power producers

$ 781

Energy Cooperatives And Municipalities

909

Financial institutions

116

Net Exposure [Member]

1,218

No external ratings - internally rated - investment grade

515

No external ratings - internally rated - non-investment grade

Total Exposure Before Credit Collateral [Member]

1,869

1,276

No external ratings - internally rated - investment grade

516

No external ratings - internally rated - non-investment grade

101

Credit Collateral [Member]

1,964

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]

436

No external ratings - internally rated - investment grade

No external ratings - internally rated - non-investment grade

$ 436

[1]	of March 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $8 million of cash and $87 million of letters of credit.Co

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

Mar. 31, 2016

Dec. 31, 2015

Aggregate fair value of derivatives with credit-risk-related contingent features

$ (979)

$ (932)

Contractual right of offset related to derivative assets

728

684

Net liability position after contractual right of offset

^[1]

$ (251)

$ (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

6 Months Ended

12 Months Ended

Mar. 31, 2016

USD ($)

GWh

Mar. 31, 2015

USD ($)

GWh

Jun. 30, 2015

USD ($)

Dec. 31, 2014

USD ($)

Dec. 31, 2015

USD ($)

Hypothetical Increase In Interest Rates

$ 184

$ 363

0.50%

$ 600

Hypothetical increase in interest rates associated with variable-rate debt

841

$ 758

Ineffective portion recognized in income

^[1]

Mark-to-market derivative liabilities (noncurrent liabilities)

408

374

Interest Rate Fair Value Hedge Asset at Fair Value

203

205

Cash collateral posted

Letters of credit posted

Debt Instrument, Face Amount

750

Designated as Hedging Instrument [Member]

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

1,287

Proprietary trading activities volume | GWh

$ 151

$ 226

1,220

1,808

Mark-to-market derivative liabilities (noncurrent liabilities)

$ 799

733

166

150

Cash collateral received not offset against net derivative positions

177

182

Cash collateral posted

1,063

1,267

Letters of credit held

Letters of credit posted

519

497

Cash collateral held

Incremental collateral for loss of investment grade credit rating

1,900

2,000

Interest Rate Fair Value Hedge Asset at Fair Value

Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]

Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives

687

Mark-to-market derivative liabilities (noncurrent liabilities)

$ 59

239

224

Incremental collateral for loss of investment grade credit rating

Cash collateral held

Estimated percentage of natural gas purchases hedged

$ 43

30.00%

Incremental collateral for loss of investment grade credit rating

$ 22

Incremental collateral for loss of investment grade credit rating

Credit Exposure Under Off System Sales

Minimum [Member] | Exelon Generation Co L L C [Member]

$ (9)

Expected Generation Hedged In Next Twelve Months

96.00%

Expected Generation Hedged In Year Two

69.00%

Expected generation hedged in year three

37.00%

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

99.00%

Expected Generation Hedged In Year Two

72.00%

Expected generation hedged in year three

40.00%

Maximum [Member] | Baltimore Gas and Electric Company [Member]

Estimated percentage of natural gas purchases hedged

20.00%

Interest Rate Swap [Member] | Derivative [Member]

Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]

$ 800

Cash Flow Hedging [Member]

100

Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]

Total mark-to-market derivative net assets (liabilities)

602

516

Designated as Hedging Instrument [Member] | Commonwealth Edison Co [Member]

Total mark-to-market derivative net assets (liabilities)

^[2]

(265)

(247)

Designated as Hedging Instrument [Member] | Delmarva Power and Light Company [Member]

Total mark-to-market derivative net assets (liabilities)

(1)

(2)

Foreign Exchange Contract [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]

137

Brokered Natural Gas Margin Revenue

Fair Value Hedging [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments

800

$ 800

$ 25

Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]

Increase In Notional Amount Of Derivative Instruments

189

Other Solar Projects [Member] | Exelon Generation Co L L C [Member]

Notional amounts on forward starting interest rate swaps

Other Solar Projects [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]

Notional amounts on forward starting interest rate swaps

PHI Merger [Member] | Designated as Hedging Instrument [Member]

Derivative, Gain (Loss) on Derivative, Net

$ 64

PHI Merger [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

ExGen Texas Power [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

$ 2,400

ExGen Texas Power [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]

499

Mark-to-market derivative liabilities (noncurrent liabilities)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Cash Flow Hedge Gain Loss Reclassified To Pretax Net Income From Accumulated Other Comprehensive Income

^[3]

(2)

(10)

$ 2

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]

^[3]

(2)

Commonwealth Edison Co Affiliate [Member] | Exelon Generation Co L L C [Member]

^[3]

(2)

Net receivable from electric utility

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

Delmarva Power and Light Company [Member] | Exelon Generation Co L L C [Member]

Net receivable from electric utility

Atlantic City Electric Company [Member] | Exelon Generation Co L L C [Member]

Net receivable from electric utility

$ 8

[1]	For the three months ended March 31, 2015, the loss on Generation swaps included $1 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.
[2]	.
[3]	Amounts in parenthesis represent a decrease in net income.

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) - USD ($) $ in Millions	Apr. 01, 2016	Mar. 31, 2016	Dec. 31, 2015
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Commercial paper borrowings		$ 1,378	$ 0
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Commercial paper borrowings		643	294
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings		150	210
PEPCO Holdings Inc [Member]
Short-term Debt [Line Items]
Commercial paper borrowings		442	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		75	105
Atlantic City Electric Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings		0	$ 5
Revolving Credit Facility [Member] \| Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 150
Revolving Credit Facility [Member] \| Subsequent Event [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200

Debt and Credit Agreements - Narrative (Details) - USD ($)						1 Months Ended	3 Months Ended
	Apr. 20, 2016	Apr. 15, 2016	Apr. 05, 2016	Apr. 01, 2016	Feb. 29, 2016	Feb. 29, 2016	Mar. 31, 2016	Mar. 31, 2015	Apr. 07, 2016	Jan. 13, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Repayments of Long-term Debt							$ 116,000,000	$ 580,000,000
Debt Instrument, Face Amount								750,000,000
Subsequent Event [Member] \| Senior Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount									$ 1,800,000,000
Subsequent Event [Member] \| SeniorNotes2021 [Member] \| Senior Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount									300,000,000
Subsequent Event [Member] \| SeniorNotes2026 [Member] \| Senior Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount									750,000,000
Subsequent Event [Member] \| SeniorNotes2046 [Member] \| Senior Loans [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount									$ 750,000,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity							100,000,000
Revolving Credit Facility [Member] \| Subsequent Event [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity				$ 200,000,000
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt							$ 94,000,000	18,000,000
Interest Rate											2.74%
Exelon Generation Co L L C [Member] \| Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate							4.11%
Debt Instrument, Face Amount							$ 150,000,000
Exelon Generation Co L L C [Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ 1,000,000
Exelon Generation Co L L C [Member] \| ExgenRenewablesI425June62021[Member] \| Non Recourse Debt [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		$ 10,000,000
Interest Rate		5.25%
Exelon Generation Co L L C [Member] \| Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount							25,000,000
Exelon Generation Co L L C [Member] \| Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							150,000,000
Atlantic City Electric Company [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 3,000,000.0000						$ 11,000,000	$ 10,000,000
Atlantic City Electric Company [Member] \| Transition Bonds555October2023 [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	$ 8,000,000.0000
Interest Rate							5.55%
Repayments of Secured Debt							$ 8,000,000.0000
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Repayments of Bank Debt				$ 1,000,000
Interest Rate				5.72%
Baltimore Gas and Electric Company [Member] \| Convertible Debt Securities [Member]
Debt Instrument [Line Items]
Repayments of Bank Debt				$ 38,000,000
Interest Rate				5.82%
Pepco Holdings, LLC [Member] \| Subsequent Event [Member]
Debt Instrument [Line Items]
Short-term Bank Loans and Notes Payable										$ 500,000,000
Short-term Debt, Percentage Bearing Variable Interest Rate										1.00%
Repayments of Bank Debt							300,000,000
Pepco Energy Services [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities							3,000,000
Financing Receivable, Significant Sales						$ 41,000,000
Delmarva Power and Light Company [Member] \| Variable Rate Demand Obligation [Member]
Debt Instrument [Line Items]
Long-term Debt, Current Maturities							105,000,000
CEU Holdings, LLC [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Increase (Decrease), Other, Net					$ 45,000,000
Secured Demand Note Deficiency					$ 23,000,000	$ 23,000,000	16,000,000
Outstanding borrowings/facility draws											$ 85,000,000
Line of Credit Facility, Maximum Borrowing Capacity							500,000,000
Long-term Debt							$ 61,000,000				$ 68,000,000

Debt and Credit Agreements - Schedule of Issuance of Long-Term Debt (Details) - USD ($) $ in Millions	Apr. 01, 2016	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 750
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Interest Rate			2.74%
Exelon Generation Co L L C [Member] \| Subsequent Event [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		$ 25
Exelon Generation Co L L C [Member] \| ExGen Texas Power [Member]
Debt Instrument [Line Items]
Interest Rate		5.00%
Exelon Generation Co L L C [Member] \| CEU Credit Agreement [Member]
Debt Instrument [Line Items]
Interest Rate		3.19%
Exelon Generation Co L L C [Member] \| Continental Wind 6000 February 28, 2033 [Member]
Debt Instrument [Line Items]
Interest Rate		6.00%
Exelon Generation Co L L C [Member] \| DOE Financing Project [Member] \| Energy Efficiency Project Financing [Member]
Debt Instrument [Line Items]
Interest Rate		1.43%
Debt Instrument, Face Amount		$ 32
Exelon Generation Co L L C [Member] \| Unsecured Debt [Member]
Debt Instrument [Line Items]
Interest Rate		4.11%
Debt Instrument, Face Amount		$ 150
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Interest Rate	5.72%
Baltimore Gas and Electric Company [Member] \| Convertible Debt Securities [Member]
Debt Instrument [Line Items]
Interest Rate	5.82%

Debt and Credit Agreements - Retirement and Redemptions of Current and Long-Term Debt (Details) - USD ($)			3 Months Ended
	Apr. 20, 2016	Apr. 01, 2016	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities			$ 29,314,000,000		$ 23,645,000,000
Repayments of Long-term Debt			116,000,000	$ 580,000,000
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Interest Rate					2.74%
Long-term Debt, Excluding Current Maturities			7,945,000,000		$ 7,936,000,000
Repayments of Long-term Debt			$ 94,000,000	18,000,000
Exelon Generation Co L L C [Member] \| CEU Credit Agreement [Member]
Debt Instrument [Line Items]
Interest Rate			3.19%
Exelon Generation Co L L C [Member] \| ExGen Texas Power [Member]
Debt Instrument [Line Items]
Interest Rate			5.00%
Repayments of Long-term Debt			$ 2,000,000
Exelon Generation Co L L C [Member] \| Continental Wind 6000 February 28, 2033 [Member]
Debt Instrument [Line Items]
Interest Rate			6.00%
Repayments of Long-term Debt			$ 15,000,000
Exelon Generation Co L L C [Member] \| AVSR [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ 5,000,000
Exelon Generation Co L L C [Member] \| AVSR [Member] \| Minimum [Member]
Debt Instrument [Line Items]
Interest Rate			2.29%
Exelon Generation Co L L C [Member] \| AVSR [Member] \| Maximum [Member]
Debt Instrument [Line Items]
Interest Rate			3.056%
Exelon Generation Co L L C [Member] \| Clear Horizon solar [Member]
Debt Instrument [Line Items]
Interest Rate			2.56%
Repayments of Long-term Debt			$ 32,000,000
Exelon Generation Co L L C [Member] \| Sacramento Solar [Member]
Debt Instrument [Line Items]
Interest Rate			2.58%
Repayments of Long-term Debt			$ 33,000,000
Exelon Generation Co L L C [Member] \| Capital Lease Obligations [Member] \| Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member]
Debt Instrument [Line Items]
Interest Rate			7.83%
Repayments of Long-term Debt			$ 1,000,000
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Repayments of Bank Debt		$ 1,000,000
Interest Rate		5.72%
Long-term Debt, Excluding Current Maturities			1,481,000,000		1,480,000,000
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities			5,845,000,000		5,844,000,000
Potomac Electric Power Company [Member]
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities			2,341,000,000		2,340,000,000
Repayments of Long-term Debt			0	12,000,000
Atlantic City Electric Company [Member]
Debt Instrument [Line Items]
Long-term Debt, Excluding Current Maturities			1,144,000,000		1,153,000,000
Repayments of Long-term Debt	$ 3,000,000.0000		$ 11,000,000	$ 10,000,000
Atlantic City Electric Company [Member] \| Transition Bonds555October2023 [Member]
Debt Instrument [Line Items]
Interest Rate			5.55%
Repayments of Secured Debt			$ 8,000,000.0000
Repayments of Long-term Debt	$ 8,000,000.0000
Atlantic City Electric Company [Member] \| Transition Bonds505October2020 [Member]
Debt Instrument [Line Items]
Interest Rate			5.05%
Repayments of Secured Debt			$ 3,000,000.0000
CEU Holdings, LLC [Member]
Debt Instrument [Line Items]
Long-term Debt			61,000,000		$ 68,000,000
CEU Holdings, LLC [Member] \| CEU Credit Agreement [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			$ 7,000,000

Income Taxes - Reconciliation to Effective Tax Rate (Details)		3 Months Ended
	Mar. 31, 2016	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		(1.10%)		2.60%
Qualified nuclear decommissioning trust fund income		5.60%		1.90%
Domestic production activities deduction		0.00%		(2.20%)
Health care reform legislation		0.00%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		(1.60%)		(0.90%)
Plant basis differences		(5.50%)		(1.30%)
Production tax credits and other credits		5.10%		1.80%
Non-controlling interest		0.50%		(0.70%)
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent		33.60%
Other		(2.00%)		0.40%
Effective income tax rate		59.40%		33.00%
Exelon Generation Co L L C [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		3.70%		2.70%
Qualified nuclear decommissioning trust fund income		4.20%		3.00%
Domestic production activities deduction		0.00%		(3.40%)
Health care reform legislation		0.00%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		(1.00%)		(1.40%)
Plant basis differences		0.00%		0.00%
Production tax credits and other credits		3.90%		2.80%
Non-controlling interest		0.30%		(1.10%)
Other		(1.60%)		(0.20%)
Effective income tax rate		36.70%		31.80%
Commonwealth Edison Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		5.10%		5.00%
Qualified nuclear decommissioning trust fund income		0.00%		0.00%
Domestic production activities deduction		0.00%
Health care reform legislation		0.00%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		(0.30%)		(0.30%)
Plant basis differences		(0.10%)		(0.30%)
Production tax credits and other credits		(0.00%)		(0.00%)
Non-controlling interest		0.00%
Other		0.40%		0.20%
Effective income tax rate		40.10%		39.60%
PECO Energy Co [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		1.00%		1.20%
Qualified nuclear decommissioning trust fund income		0.00%		0.00%
Domestic production activities deduction		0.00%
Health care reform legislation		0.00%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		(0.10%)		(0.10%)
Plant basis differences		(9.30%)		(6.70%)
Production tax credits and other credits		(0.00%)		(0.00%)
Non-controlling interest		0.00%
Other		(0.90%)		0.00%
Effective income tax rate		25.70%		29.40%
Baltimore Gas and Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		5.20%		5.30%
Qualified nuclear decommissioning trust fund income		0.00%		0.00%
Domestic production activities deduction		0.00%
Health care reform legislation		0.00%		0.20%
Amortization of investment tax credit, including deferred taxes on basis difference		(0.10%)		0.00%
Plant basis differences		(0.60%)		(0.30%)
Production tax credits and other credits		(0.00%)		(0.00%)
Non-controlling interest		0.00%
Other		0.00%		0.20%
Effective income tax rate		39.50%		40.40%
Pepco Holdings, LLC [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)				7.20%
Amortization of investment tax credit, including deferred taxes on basis difference				(0.50%)
Plant basis differences				(4.90%)
Other				(0.70%)
Effective income tax rate				36.10%
Pepco Holdings, LLC [Member] \| Predecessor [Member]
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)			11.90%
Qualified nuclear decommissioning trust fund income			0.00%
Domestic production activities deduction			0.00%
Health care reform legislation			(0.90%)
Amortization of investment tax credit, including deferred taxes on basis difference			(13.50%)
Production tax credits and other credits			(0.00%)
Non-controlling interest			0.00%
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent			11.10%
Other			3.60%
Effective income tax rate			47.20%
Pepco Holdings, LLC [Member] \| Successor [Member]
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)	5.40%
Qualified nuclear decommissioning trust fund income	0.00%
Domestic production activities deduction	0.00%
Health care reform legislation	0.00%
Amortization of investment tax credit, including deferred taxes on basis difference	0.00%
Production tax credits and other credits	(0.00%)
Non-controlling interest	0.00%
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent	(15.10%)
Other	0.20%
Effective income tax rate	25.50%
Potomac Electric Power Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate				35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		(2.50%)		5.30%
Qualified nuclear decommissioning trust fund income		0.00%		0.00%
Domestic production activities deduction		0.00%
Health care reform legislation		0.00%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		2.80%		(0.10%)
Plant basis differences				(8.50%)
Production tax credits and other credits		(0.00%)		(0.00%)
Non-controlling interest		0.00%
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent		(16.50%)
Other		0.00%		(0.10%)
Effective income tax rate		18.80%		31.60%
Delmarva Power and Light Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		(2.70%)		5.70%
Qualified nuclear decommissioning trust fund income		0.00%		0.00%
Domestic production activities deduction		0.00%
Health care reform legislation		0.20%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		0.60%		(0.20%)
Plant basis differences				(0.90%)
Production tax credits and other credits		(0.00%)		(0.00%)
Non-controlling interest		0.00%
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent		(22.10%)
Other		0.10%		0.00%
Effective income tax rate		11.10%		39.60%
Atlantic City Electric Company [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate		35.00%		35.00%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit (b)		5.90%		5.90%
Qualified nuclear decommissioning trust fund income		0.00%		0.00%
Domestic production activities deduction		0.00%
Health care reform legislation		0.10%		0.00%
Amortization of investment tax credit, including deferred taxes on basis difference		0.70%		(1.40%)
Plant basis differences				(2.80%)
Production tax credits and other credits		(0.00%)		(0.00%)
Non-controlling interest		0.00%
Effective Income Tax Rate Reconciliation, Disposition of Business, Percent		(17.00%)
Other		0.10%		(1.00%)
Effective income tax rate		24.80%		35.70%
Atlantic City Electric Company [Member] \| Predecessor [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate			35.00%
Atlantic City Electric Company [Member] \| Successor [Member]
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. Federal statutory rate	35.00%

Income Taxes - Narrative (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended
Income Taxes - Narrative (Details) - USD ($) $ in Millions	Sep. 30, 2014	Mar. 31, 2016	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2009
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		$ 75
Unrecognized Tax Benefits		328
Increase (Decrease) in Income Taxes		270
Deferred tax gain under involuntary conversion provisions of the IRC						$ 1,200
IRS asserted penalties for understatement of tax		90
Expected non-cash charge to earnings				$ 265
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position		460
Early termination amount			$ 335
Taxes Payable, Current			360
Tax Adjustments, Settlements, and Unusual Provisions		300
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent		59
Parent Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		950			$ 1,101
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 that if recognized would affect the effective tax rate		531			534
Increase (Decrease) in Income Taxes	$ 67
Effective Income Tax Rate Reconciliation, Tax Settlement, Amount		120
Tax Adjustments, Settlements, and Unusual Provisions		6
Commonwealth Edison Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		(12)			142
Unrecognized Tax Benefits		154
Expected non-cash charge to earnings				172
Non-cash equity contributions				$ 172
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position		275
Taxes Payable, Current			$ 65
Tax Adjustments, Settlements, and Unusual Provisions		12
PECO Energy Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		0			0
Baltimore Gas and Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		120			120
Pepco Holdings, LLC [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		168			22
PEPCO Holdings Inc [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities		146
Fresh-Start Adjustment, Increase (Decrease), Deferred Income Tax Liabilities, Noncurrent		8
Potomac Electric Power Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		86			8
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities		78
Increase (Decrease) in Income Taxes	63
Delmarva Power and Light Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		39			3
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities		36
Increase (Decrease) in Income Taxes	$ 20
Atlantic City Electric Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		24			$ 0
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities		$ 24

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) - Nuclear Decommissioning Asset Retirement Obligation [Member] - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Dec. 31, 2015

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Nuclear Decommissioning ARO, Beginning Balance

^[1]

$ 8,246

Net increase due to changes in, and timing of, estimated cash flows

106

Asset Retirement Obligation, Period Increase (Decrease)

Nuclear Decommissioning ARO, Ending Balance

^[1]

8,412

Current portion of ARO

$ 6

$ 7

[1]	Includes $6 million and $7 million as the current portion of the ARO at March 31, 2016 and December 31, 2015 which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

Nuclear Decommissioning (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	$ 10,526	$ 10,342
Decommissioning Liability, Noncurrent	72	90
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Fund Investments	10,526	10,342
Decommissioning Liability, Noncurrent	71	$ 90
Nuclear Plant [Member] \| Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Liability, Noncurrent	$ 85

Nuclear Decommissioning - Unrealized Gains on NDT Funds (Details) - Exelon Generation Co L L C [Member] - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]

Net unrealized gains (losses) on decommissioning trust funds - regulatory agreement units

^[1]

$ 79

$ 48

Net unrealized gains (losses) on decommissioning trust funds - non-regulatory agreement units

^[2],[3]

Unrealized Gain Loss Investment Income Pledged Assets

$ 2

$ (10)

[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 $2 million and $10 million of net unrealized gain related to the Zion Station pledged assets for the three months ended March 31, 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

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Dec. 31, 2015

Nuclear Decommissioning Additional Narrative Information [Line Items]

$ 183

$ 206

Nuclear Decommissioning Additional Narrative Information [Line Items]

Payable to Zion Solutions

183

206

^[1]

166

189

Current portion of payable to Zion Solutions

^[2]

$ 99

Withdrawals by Zion Solutions to pay decommissioning costs

^[3]

$ 812

$ 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
	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015
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
Pension Obligations Valuation Adjustment			35
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense		$ 7
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)
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets	7.00%
Pension Plan, Defined Benefit [Member] \| Exelon Legacy Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.29%
Pension Plan, Defined Benefit [Member] \| PEPCO Holdings Inc [Member] \| PHI Pension and Postretirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets	6.50%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets	6.71%
Discount rate	4.30%
Other Postretirement Benefit Plan, Defined Benefit [Member] \| PEPCO Holdings Inc [Member] \| PHI Pension and Postretirement [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected return on assets	6.75%
Discount rate	4.00%

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) - USD ($) $ in Millions		3 Months Ended
	Mar. 31, 2016	Mar. 31, 2016	Mar. 23, 2016	Dec. 31, 2015	Mar. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions		$ 26	$ 1	$ 22
Amortization of:
Pension and Other Postretirement Benefit Costs			7
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		78			$ 82
Interest cost		190			178
Expected return on assets		263			257
Amortization of:
Prior service cost (benefit)		127			143
Defined Benefit Plan, Amortization of Transition Obligations (Assets)		3			3
Net periodic benefit cost		135	22		149
Pension Plan, Defined Benefit [Member] \| Predecessor [Member]
Amortization of:
Net periodic benefit cost					22
Other Postretirement Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost		26			30
Interest cost		43			42
Expected return on assets		38			38
Amortization of:
Prior service cost (benefit)		14			20
Defined Benefit Plan, Amortization of Transition Obligations (Assets)		(44)			(43)
Net periodic benefit cost		1			11
Other Postretirement Benefit Plan, Defined Benefit [Member]
Amortization of:
Net periodic benefit cost			1		2
Pepco Holdings, LLC [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$ 0	1	3		2
Pepco Holdings, LLC [Member] \| Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions					3
Pepco Holdings, LLC [Member] \| Pension Plan, Defined Benefit [Member] \| Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost			12		14
Interest cost			26		27
Expected return on assets			30		35
Amortization of:
Prior service cost (benefit)			0		0
Defined Benefit Plan, Actuarial Gain (Loss)			14		16
Pepco Holdings, LLC [Member] \| Other Postretirement Benefit Plan, Defined Benefit [Member] \| Predecessor [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost			1		2
Interest cost			6		6
Expected return on assets			5		6
Amortization of:
Prior service cost (benefit)			(3)		(3)
Defined Benefit Plan, Actuarial Gain (Loss)			2		3
Delmarva Power and Light Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions		1	1		$ 0
Amortization of:
Pension and Other Postretirement Benefit Costs			4
Atlantic City Electric Company [Member]
Amortization of:
Pension and Other Postretirement Benefit Costs			$ 3
CENG [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions		$ 1

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Mar. 31, 2015

$ 136

$ 159

Other Segment [Member]

Pepco Holdings, LLC [Member]

$ 14

Pepco Holdings, LLC [Member] | Other Segment [Member]

$ 3

$ 23

^[1]

$ 17

Predecessor [Member] | Pepco Holdings, LLC [Member]

$ 4

$ 24

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246N0QzMjIzMURGRDVBNjNBQTgzRjZGQkE2NTU2RDY2MjkM}

Retirement Benefits - Defined Contribution Savings Plans (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Mar. 31, 2015

Pepco Holdings, LLC [Member]

$ 26

$ 1

$ 22

$ 0

$ 2

^[1]

Business Services Company [Member]

^[2]

$ 1

Predecessor [Member] | Pepco Holdings, LLC [Member]

$ 1

Movement in Accumulated Other Comprehensive Income [Roll Forward]

$ 3

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246Njk4QjRCMkQ4OThEMEE4NzdFRkVGQkE2NTU2RDc3MDAM}
[2]	ese 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.

Severance - Ongoing Severance Plans (Details) - Exelon Generation Co L L C [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 2	$ 20
Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 1

Severance - PHI Merger (Details) - USD ($) $ in Millions	3 Months Ended
Severance - PHI Merger (Details) - USD ($) $ in Millions	Mar. 31, 2016	Mar. 31, 2015
PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 52
Exelon Generation Co L L C [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	2	$ 20
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	1
Exelon Generation Co L L C [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	10
Exelon Generation Co L L C [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	9
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] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	37
Pepco Holdings, LLC [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	18
Potomac Electric Power Company [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	18
Delmarva Power and Light Company [Member] \| PHI Merger [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	11
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	8
Atlantic City Electric Company [Member] \| PHI Merger [Member] \| Corporate, Non-Segment [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance Costs	$ 8

Severance - Severance Liabilities (Details) $ in Millions	3 Months Ended
Severance - Severance Liabilities (Details) $ in Millions	Mar. 31, 2016 USD ($)
Restructuring Reserve [Roll Forward]
Beginning Balance	$ 35
Severance Charges Expense	71
Payments for Restructuring	4
Ending Balance	102
Exelon Generation Co L L C [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	23
Severance Charges Expense	7
Payments for Restructuring	3
Ending Balance	27
Commonwealth Edison Co [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	3
Severance Charges Expense	0
Payments for Restructuring	0
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
Ending Balance	1
Pepco Holdings, LLC [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	51
Payments for Restructuring	0
Ending Balance	51
Potomac Electric Power Company [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	0
Payments for Restructuring	0
Ending Balance	0
Delmarva Power and Light Company [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	0
Severance Charges Expense	0
Payments for Restructuring	0
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

Severance Severance - Cost Management Program-Related (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	$ 17
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	2	$ 20
Exelon Generation Co L L C [Member] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	12
Exelon Generation Co L L C [Member] \| Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	1
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] \| Cost Management Project [Member]
Restructuring Cost and Reserve [Line Items]
Severance Costs	3
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

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

^[1]

$ (2,624)

$ (2,684)

^[1]

(49)

^[1],[2]

(31)

^[1]

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[1]

(2,596)

(2,673)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(11)

^[1],[2]

^[1]

(7)

Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

(26)

(22)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

(1)

^[1]

(1)

Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(2,565)

(2,640)

^[1]

^[1],[2]

(34)

^[1]

Accumulated Translation Adjustment [Member]

^[1]

(2,532)

(2,623)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(40)

^[1]

(12)

^[1]

(12)

Accumulated Equity Investment [Member]

^[1]

(34)

(31)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(3)

^[1]

(3)

^[1],[2]

^[1]

(3)

^[1]

(6)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(63)

(36)

^[1]

(4)

(18)

^[1],[2]

^[1]

(1)

(17)

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[1]

(64)

(53)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(6)

^[1],[2]

^[1]

(5)

Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

(26)

(23)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

^[1]

Exelon Generation Co L L C [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(40)

^[1]

(12)

^[1]

(12)

Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]

^[1]

(34)

(31)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

(3)

^[1]

(2)

^[1],[2]

^[1]

(2)

^[1]

(5)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[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]

^[1]

PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

^[1]

^[1]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(36)

(46)

(1)

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

(35)

(45)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(8)

(9)

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]

(8)

(9)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

(37)

(1)

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Translation Adjustment [Member]

(27)

(36)

Movement in Accumulated Other Comprehensive Income [Roll Forward]

PEPCO Holdings Inc [Member] | Predecessor [Member] | Accumulated Equity Investment [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

$ 0

[1]	All amounts are net of tax. Amounts in parenthesis represent a decrease in AOCI.
[2]	See next tables for details about these reclassifications.

Changes in Accumulated Other Comprehensive Income - Reclassification out of Accumulated Other Comprehensive Income (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Mar. 31, 2015

$ 7,573

$ 8,830

310

1,101

(184)

(363)

123

738

Equity in (losses) earnings of unconsolidated affiliates

114

Reclassification out of Accumulated Other Comprehensive Income [Member]

277

335

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]

^[1]

(60)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(5)

(27)

^[1]

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]

(3)

(17)

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]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(71)

^[1]

(22)

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

^[1]

(43)

^[1],[2]

Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

^[1],[3]

(90)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

4,739

5,840

411

711

(151)

(226)

257

485

Equity in (losses) earnings of unconsolidated affiliates

Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[1]

(3)

(1)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

^[1]

(5)

(1)

^[1]

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]

(3)

(1)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

PEPCO Holdings Inc [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

^[1]

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)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

PEPCO Holdings Inc [Member] | Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

(2)

(1)

Prior service benefit reclassified to periodic benefit cost

(1)

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax

$ (2)

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Equity in (losses) earnings of unconsolidated affiliates

$ (4)

$ 0

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

Equity in (losses) earnings of unconsolidated affiliates

$ 2

$ 0

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

551

545

(133)

(12)

(108)

Equity in (losses) earnings of unconsolidated affiliates

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

362

421

(81)

(21)

(72)

Equity in (losses) earnings of unconsolidated affiliates

Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]

291

334

(133)

(5)

(100)

Equity in (losses) earnings of unconsolidated affiliates

Accumulated Other Comprehensive Income (Loss) [Line Items]

$ 16

[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).
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246NDA1RDVDRTgyRkJEQTYyMERFNTFGQkE2NTU2RDQzMkUM}

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

Dec. 31, 2015

Dec. 31, 2014

Pension and non-pension postretirement benefit plans:

^[1]

$ (2,596)

$ (2,673)

$ (2,624)

$ (2,684)

Prior service benefit reclassified to periodic benefit cost

Actuarial loss reclassified to periodic cost

(30)

(35)

Pension and non-pension postretirement benefit plans valuation adjustment

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

(2)

Change in unrealized loss on equity investments

Change in unrealized loss on marketable securities

(17)

(12)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(49)

^[1],[2]

(60)

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

(35)

(45)

(36)

(46)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(1)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(64)

(53)

(63)

(36)

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

Change in unrealized loss on equity investments

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(4)

(18)

^[1],[2]

(3)

(1)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]

^[1]

(1)

(17)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(26)

(22)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(11)

^[1],[2]

(3)

(17)

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

^[1]

(7)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

(8)

(9)

(8)

(9)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(26)

(23)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(6)

^[1],[2]

(3)

(1)

Accumulated Net Unrealized Investment Gain (Loss) [Member]

^[1]

(5)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

^[1]

(1)

Accumulated Net Unrealized Investment Gain (Loss) [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

^[1]

(1)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Accumulated Net Unrealized Investment Gain (Loss) [Member] | Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

^[1]

Accumulated Defined Benefit Plans Adjustment [Member]

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(2,532)

(2,623)

(2,565)

(2,640)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

^[1],[2]

(43)

Accumulated Defined Benefit Plans Adjustment [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

(27)

(36)

(37)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

(1)

Accumulated Defined Benefit Plans Adjustment [Member] | Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Accumulated Translation Adjustment [Member]

^[1]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(34)

(31)

(40)

^[1]

(12)

Accumulated Translation Adjustment [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

^[1]

(12)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Accumulated Translation Adjustment [Member] | Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(34)

(31)

(40)

^[1]

(12)

Accumulated Equity Investment [Member]

^[1]

(12)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(6)

(3)

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(3)

^[1],[2]

Accumulated Equity Investment [Member] | PEPCO Holdings Inc [Member] | Predecessor [Member]

^[1]

(3)

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

Accumulated Equity Investment [Member] | Exelon Generation Co L L C [Member]

Accumulated Other Comprehensive Income (Loss) [Line Items]

Pension and non-pension postretirement benefit plans:

^[1]

(5)

$ (3)

$ 0

Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax

^[1]

(2)

^[1],[2]

^[1]

$ (2)

$ 0

[1]	All amounts are net of tax. Amounts in parenthesis represent a decrease in AOCI.
[2]	See next tables for details about these reclassifications.

Mezzanine Equity Mezzanine Equity (Details) - USD ($)	3 Months Ended
Mezzanine Equity Mezzanine Equity (Details) - USD ($)	Mar. 31, 2016	Mar. 23, 2016	Mar. 31, 2015	Dec. 31, 2015
Redeemable Noncontrolling Interest [Line Items]
Common Stock, Value, Issued	$ 18,686,000,000			$ 18,676,000,000
Redeemable Noncontrolling Interest, Equity, Fair Value [Abstract]
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	$ 19,000,000			28,000,000
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Number of preferred shares purchased	18,000
Payments to Acquire Businesses, Gross	$ 6,645,000,000		$ 15,000,000
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, Equity, Fair Value [Abstract]
Redeemable Noncontrolling Interest, Equity, Common, Carrying Amount	19,000,000			$ 28,000,000
Temporary Equity, Other Changes	(19,000,000)
Noncontrolling Interest, Increase from Sale of Parent Equity Interest	10,000,000
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Payments to Acquire Businesses, Gross	$ 1,000,000		$ 15,000,000
Pepco Holdings, LLC [Member]
Preferred Stock, Shares Subscribed but Unissued, Value [Abstract]
Total mark-to-market derivative net assets (liabilities)		0
Increase (Decrease) in Derivative Assets		$ 18,000,000

Common Stock - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions	Jun. 05, 2013 USD ($) $ / shares shares
Common Stock [Abstract]
Temporary Equity, Share Subscriptions	57.5
Shares Issued, Price Per Share \| $ / shares	$ 35
Junior Subordinated Notes, Noncurrent \| $	$ 1,150
Forward Contract Indexed to Issuer's Equity, Indexed Shares	23.0

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) - USD ($) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$ 173	$ 693
Weighted average common shares outstanding — basic	923	862
Assumed exercise and/or distributions of stock-based awards	2	5
Weighted average common shares outstanding — diluted	925	867

Earnings Per Share and Equity - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding	13,000,000	15,000,000
Treasury Stock, Shares held	35,000,000		35,000,000
Treasury Stock, Value	$ 2,327		$ 2,327
Equity units issued [Member]
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding	4,000,000	1,000,000
Employee Stock Option [Member]
Statement Of Equity Line Item [Line Items]
Stock options not included in the calculation of diluted common shares outstanding	16,000,000	20,000,000

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) - Equity Method Investments [Member] - Exelon Generation Co L L C [Member] $ in Millions	Mar. 31, 2016 USD ($)
Guarantor Obligations [Line Items]
Other Unrecorded Amounts	$ 20
Total	$ 299

Commitments and Contingencies - Commitments Narrative (Details)
$ in Millions

3 Months Ended

Mar. 31, 2016

USD ($)

Mar. 31, 2015

USD ($)

Jun. 30, 2013

USD ($)

Guarantor Obligations, Maximum Exposure, Undiscounted

$ 53

Noncash Merger Related Costs

^[1],[2]

503

Noncash Merger Related Costs

^[2]

Costs Incurred, Development Costs

398

Business Acquisition, Direct Investment With State And Local Governments Due To Settlement

$ 1,000

Minimum [Member] | Exelon Generation Co L L C [Member]

Business Acquisition, Construction Cost

$ 95

Business Acquisition, Development Of New Generation Cost

$ 500

Business Acquisition, Expected New Generation Mwh | MW

275

Maximum [Member] | Exelon Generation Co L L C [Member]

Business Acquisition, Construction Cost

$ 120

Business Acquisition, Development Of New Generation Cost

$ 600

Business Acquisition, Expected New Generation Mwh | MW

300

Noncash Merger Related Costs

$ 105

[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	3 Months Ended
	Mar. 31, 2016	Mar. 31, 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	$ 53
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
Maximum liability per nuclear incident		$ 13,100
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)	1 Months Ended				3 Months Ended
	Aug. 31, 2015 gal	Jan. 31, 2011 gal	Jul. 31, 2010 USD ($)	Oct. 31, 2007 USD ($)	Mar. 31, 2016 USD ($) MGPSite gal Principle_responsible_party	Mar. 31, 2014 USD ($)	Sep. 30, 2013 USD ($)
Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Consent decree penalty				$ 1,000,000
Environmental loss contingencies					$ 11,000,000
PEPCO Holdings Inc [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Sites under study/remediation \| MGPSite					9
Minimum estimated clean-up costs for all potentially responsible parties					$ 7,000,000
Maximum estimated clean-up costs for all potentially responsible parties					18,000,000
Environmental Remediation Expense			$ 10,000,000
Potomac Electric Power Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Minimum estimated clean-up costs for all potentially responsible parties					9,000,000		$ 106,000
Maximum estimated clean-up costs for all potentially responsible parties					13,000,000		$ 161,000
QuantityOfMineralOilSPill \| gal	6,100	4,500
Litigation Settlement, Expense					600,000	$ 875,000
Loss Contingency, Damages Paid, Value					250,000
Charitable donations					25,000
Potomac Electric Power Company [Member] \| Minimum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost					3,000,000
Potomac Electric Power Company [Member] \| Maximum [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost					$ 6,000,000
Delmarva Power and Light Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites \| gal					2
Approved clean-up \| MGPSite					1
Calpine Corporation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Maximum estimated clean-up costs for all potentially responsible parties					$ 10,000,000
Sixty-Eighth Street Dump [Member] \| Baltimore Gas and Electric Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency Number Of Parties Jointly And Severally Liable In Environmental Protection Agency Action \| Principle_responsible_party					50,000,000
Minimum estimated clean-up costs for all potentially responsible parties					$ 64,000,000

Commitments and Contingencies - Litigation and Regulatory Matters (Details) $ in Millions	Mar. 31, 2016 USD ($) claimant Open_claim	Dec. 31, 2015 USD ($)
Exelon Generation Co L L C [Member]
Asbestos Loss Contingency [Abstract]
Asbestos liability reserve	$ 21	$ 0
Asbestos liability reserve related to open claims	$ 0
Open asbestos liability claims \| Open_claim	72,000,000
Asbestos liability reserve related to anticipated claims	$ 95
Telephone Consumer Protection Act Lawsuit [Abstract]
Loss Contingency Accrual	$ 44
Baltimore Gas and Electric Company [Member]
Asbestos Loss Contingency [Abstract]
Number of claimants \| claimant	93,000,000

Supplemental Financial Information - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015	Mar. 31, 2015
Supplemental Financial Information Tables [Line Items]
Debt Instrument, Face Amount			$ 750
PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	$ 14	$ 15
Financing Receivable, Allowance for Credit Losses	13		15
Low To Medium Risk [Member] \| PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	1		1
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	$ 9		$ 11

Supplemental Financial Information - Operations (Detail) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 23, 2016

Mar. 31, 2015

Dec. 31, 2015

Supplemental Income Statement Information [Line Items]

$ 153

$ 148

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Net unrealized income (losses) on pledged assets

Regulatory offset to decommissioning trust fund-related activities

(95)

(106)

^[2]

Total decommissioning-related activities

Gain (Loss) on Disposition of Assets

^[3]

(23)

Gain (Loss) on Sale of Derivatives

114

$ 62

$ 56

(2)

Supplemental Income Statement Information [Line Items]

Net realized income on decommissioning trust funds - Regulatory Agreement Units

^[1]

Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units

^[1]

Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units

Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement

Net unrealized income (losses) on pledged assets

Regulatory offset to decommissioning trust fund-related activities

(95)

(106)

^[2]

Total decommissioning-related activities

Gain (Loss) on Disposition of Assets

(3)

(2)

Supplemental Income Statement Information [Line Items]

Supplemental Income Statement Information [Line Items]

Supplemental Income Statement Information [Line Items]

^[4]

Supplemental Income Statement Information [Line Items]

Supplemental Income Statement Information [Line Items]

$ 77

(11)

$ (4)

Supplemental Income Statement Information [Line Items]

Supplemental Income Statement Information [Line Items]

$ 1

Depreciation, Amortization and Accretion [Abstract]

$ 2

$ 0

[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

Mar. 31, 2016

Mar. 23, 2016

Dec. 31, 2015

Mar. 31, 2015

$ 606

$ 540

Amortization of energy contract assets and liabilities

^[1]

(14)

(31)

^[2]

283

272

^[3]

109

1,063

948

136

159

(3)

^[4]

(55)

(44)

Amortization of regulatory asset related to debt costs

^[5]

(9)

(3)

(9)

^[6]

(46)

Severance Obligation Severance Charges

^[7],[8]

503

Inventory Adjustments

$ 36

Changes In Other Assets and Liabilities [Abstract]

804

344

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(311)

(250)

(290)

$ 56

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(2)

Capital Project [Member]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Successor [Member]

^[8]

358

Depreciation, Amortization and Accretion [Abstract]

278

242

Amortization of energy contract assets and liabilities

^[1]

(14)

(32)

^[2]

283

272

^[3]

109

667

591

^[9]

(3)

^[4]

(55)

(44)

Amortization of regulatory asset related to debt costs

^[5]

(9)

(3)

(4)

Severance Obligation Severance Charges

^[8]

(1)

Inventory Adjustments

Changes In Other Assets and Liabilities [Abstract]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(148)

(232)

^[8]

119

(234)

Exelon Generation Co L L C [Member] | Capital Project [Member]

(2)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Noncash or Part Noncash Acquisition, Fixed Assets Acquired

Depreciation, Amortization and Accretion [Abstract]

170

154

189

175

Amortization of regulatory asset related to debt costs

^[6]

(46)

(6)

Changes In Other Assets and Liabilities [Abstract]

126

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Commonwealth Edison Co [Member] | Indemnification Agreement [Member]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

Contribution of Property

^[10]

Depreciation, Amortization and Accretion [Abstract]

Amortization of regulatory asset related to debt costs

(1)

Changes In Other Assets and Liabilities [Abstract]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(95)

(70)

(65)

Depreciation, Amortization and Accretion [Abstract]

109

106

Amortization of regulatory asset related to debt costs

(5)

(3)

Changes In Other Assets and Liabilities [Abstract]

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(30)

(4)

Depreciation, Amortization and Accretion [Abstract]

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

Amortization of regulatory asset related to debt costs

^[8]

138

(1)

Changes In Other Assets and Liabilities [Abstract]

153

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(9)

(18)

Severance Obligation Severance Charges

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

127

$ 0

(7)

Depreciation, Amortization and Accretion [Abstract]

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

152

155

Amortization of regulatory asset related to debt costs

(3)

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

$ 46

Depreciation, Amortization and Accretion [Abstract]

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

(2)

Amortization of regulatory asset related to debt costs

(1)

410

Depreciation, Amortization and Accretion [Abstract]

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

Amortization of regulatory asset related to debt costs

^[8]

100

(1)

Changes In Other Assets and Liabilities [Abstract]

118

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(9)

Depreciation, Amortization and Accretion [Abstract]

Amortization of energy contract assets and liabilities

^[1]

^[2]

^[3]

Amortization of regulatory asset related to debt costs

^[8]

120

(2)

(1)

Changes In Other Assets and Liabilities [Abstract]

132

Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]

(3)

$ 20

(9)

$ 2

$ 0

[1]	Included in Operating revenues or Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[2]	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income
[3]	Included in Operating and maintenance 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 to results of operations
[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]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246N0QzMjIzMURGRDVBNjNBQTgzRjZGQkE2NTU2RDY2MjkM}
[10]	See Note 11— Income Taxes for discussion of the like-kind exchange tax position

Supplemental Financial Information - Balance Sheet (Details) - USD ($)
$ in Millions

Mar. 31, 2016

Dec. 31, 2015

$ 16,776

^[1]

$ 16,375

^[2]

351

284

8,950

^[1]

8,639

^[2]

Accumulated amortization of nuclear fuel

3,008

2,861

3,716

3,710

3,139

3,101

3,069

3,016

5,341

2,960

2,929

1,140

1,139

983

968

$ 18

$ 17

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $3,008 million
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,861 million

Segment Information - Narrative (Details)	3 Months Ended
Segment Information - Narrative (Details)	Mar. 31, 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

Mar. 31, 2016

Mar. 23, 2016

Mar. 31, 2015

Dec. 31, 2015

$ 7,573

$ 8,830

3,429

4,188

2,657

2,574

222

318

822

1,124

123

738

111,742

$ 95,384

444

624

Operating Segments [Member]

(1)

Intersegment Eliminations [Member]

(266)

(209)

(6)

(1)

(1)

(1)

(1)

(11,653)

(11,728)

(5)

(7)

Intersegment Eliminations [Member] | Predecessor [Member]

(418)

(316)

$ (4)

(4)

(4)

(5,238)

Intersegment Eliminations [Member] | Successor [Member]

(4,374)

Exelon Generation Co L L C [Member] | Operating Segments [Member]

3,695

4,397

222

319

822

1,124

257

485

47,002

46,529

Exelon Generation Co L L C [Member] | Intersegment Eliminations [Member]

Generation Midwest [Member]

266

210

Generation Midwest [Member] | Operating Segments [Member]

1,095

1,276

Generation Midwest [Member] | Intersegment Eliminations [Member]

^[1]

1,089

1,276

Commonwealth Edison Co [Member] | Operating Segments [Member]

1,249

1,185

115

26,887

26,532

Commonwealth Edison Co [Member] | Intersegment Eliminations [Member]

PECO Energy Co [Member] | Operating Segments [Member]

644

677

124

139

10,462

10,367

197

308

PECO Energy Co [Member] | Intersegment Eliminations [Member]

Baltimore Gas and Electric Company [Member] | Operating Segments [Member]

680

713

101

109

8,361

8,295

249

323

Baltimore Gas and Electric Company [Member] | Intersegment Eliminations [Member]

Corporate and Other [Member] | Operating Segments [Member] | Predecessor [Member]

Corporate and Other [Member] | Operating Segments [Member] | Successor [Member]

7,158

Corporate and Other [Member] | Other Segments [Member]

11,077

(164)

(84)

9,751

15,389

Corporate and Other [Member] | Other Segments [Member] | Predecessor [Member]

405

318

(44)

(14)

Corporate and Other [Member] | Other Segments [Member] | Successor [Member]

Corporate and Other [Member] | Intersegment Eliminations [Member]

Segment Elimination [Member] | Intersegment Eliminations [Member]

405

317

Generation Total Consolidated Group [Member]

(695)

(533)

Generation Total Consolidated Group [Member] | Operating Segments [Member]

4,739

5,840

Generation Total Consolidated Group [Member] | Intersegment Eliminations [Member]

^[1]

4,739

5,840

1,096

1,268

(309)

PEPCO Holdings Inc [Member] | Operating Segments [Member] | Predecessor [Member]

PEPCO Holdings Inc [Member] | Operating Segments [Member] | Successor [Member]

(309)

20,932

PEPCO Holdings Inc [Member] | Other Segments [Member] | Predecessor [Member]

PEPCO Holdings Inc [Member] | Other Segments [Member] | Successor [Member]

16,184

PEPCO Holdings Inc [Member] | Intersegment Eliminations [Member] | Predecessor [Member]

20,932

PEPCO Holdings Inc [Member] | Intersegment Eliminations [Member] | Successor [Member]

Potomac Electric Power Company [Member] | Operating Segments [Member] | Predecessor [Member]

511

545

6,908

Potomac Electric Power Company [Member] | Operating Segments [Member] | Successor [Member]

(140)

6,877

Delmarva Power and Light Company [Member] | Operating Segments [Member] | Predecessor [Member]

279

335

3,969

Delmarva Power and Light Company [Member] | Operating Segments [Member] | Successor [Member]

(98)

3,959

Atlantic City Electric Company [Member] | Operating Segments [Member] | Predecessor [Member]

268

334

$ 3,387

Atlantic City Electric Company [Member] | Operating Segments [Member] | Successor [Member]

$ 0

(105)

3,393

Operating Segments [Member] | PECO Energy Co Affiliate [Member]

Operating Segments [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Generation Midwest [Member]

Operating Segments [Member] | Commonwealth Edison Co Affiliate [Member] | Generation Midwest [Member]

173

138

Operating Segments [Member] | PotomacElectricPowerCompanyAffiliate [Member] | Generation Midwest [Member] | Successor [Member]

$ 9

Operating Segments [Member] | DelmarvaPowerandLightCompanyAffiliate [Member] | Generation Midwest [Member] | Successor [Member]

Operating Segments [Member] | AtlanticCityElectricCompanyAffiliate [Member] | Generation Midwest [Member] | Successor [Member]

$ 1

[1]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246NUMzQ0MzNUZBOUJFQjJEREJCRDZGQkE2NTU2RkRBMTEM}

Segment Information - Generation Total Revenues (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

$ 7,573

$ 8,830

123

738

Generation Mid Atlantic [Member]

(7)

Generation New England [Member]

1,520

1,513

Generation New York [Member]

470

859

Generation ERCOT [Member]

203

310

Generation Other Regions [Member]

163

180

Generation Reportable Segments Total [Member]

223

214

Generation Reportable Segments Total [Member] | Scenario, Adjustment [Member]

3,674

4,352

Generation All Other Segments [Member]

(43)

Amortization of intangible assets related to commodity contracts

1,065

1,488

Generation All Other Segments [Member] | Scenario, Adjustment [Member]

154

(43)

Generation Total Consolidated Group [Member]

Operating Segments [Member] | Generation Mid Atlantic [Member]

4,739

5,840

Operating Segments [Member] | Generation New England [Member]

^[1],[2]

1,532

1,556

Operating Segments [Member] | Generation New York [Member]

^[1]

471

865

Operating Segments [Member] | Generation ERCOT [Member]

^[1],[2]

218

307

Operating Segments [Member] | Generation Other Regions [Member]

^[1]

163

181

Operating Segments [Member] | Generation Reportable Segments Total [Member]

^[1],[3]

222

212

Operating Segments [Member] | Generation Total Consolidated Group [Member]

^[1]

3,695

4,397

Operating Segments [Member] | Exelon Generation Co L L C [Member]

^[1]

4,739

5,840

Other Segment [Member] | Generation All Other Segments [Member]

257

485

Intersegment Eliminations [Member]

^[1],[4]

1,044

1,443

(1)

Intersegment Eliminations [Member] | Corporate and Other [Member]

(1)

Intersegment Eliminations [Member] | Segment Elimination [Member]

405

317

Intersegment Eliminations [Member] | Generation Mid Atlantic [Member]

(695)

(533)

Intersegment Eliminations [Member] | Generation New England [Member]

^[2]

(12)

(43)

Intersegment Eliminations [Member] | Generation New York [Member]

(1)

(6)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

^[2]

(15)

Intersegment Eliminations [Member] | Generation Other Regions [Member]

(1)

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

^[3]

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

(21)

(45)

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]

^[4]

Intersegment Eliminations [Member] | Exelon Generation Co L L C [Member]

Other Segments [Member] | Corporate and Other [Member]

266

210

$ (164)

$ (84)

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[2]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246NjVBNzc5N0FGN0ZBMTJDMUQ2OThGQkE2NTU2Rjg4MUMM}
[3]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246N0VDOTc2NzhBOTQxRTVCRjVFQTBGQkE2NTU2RkQzMkMM}
[4]	{F\|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmI4M2MxNDE3MDYxODRkNzQ5ZTcwNzJlZThlYmU3MWU2fFRleHRTZWxlY3Rpb246NUFDMUZBMUNBNUIxOEE4RTZBQjFGQkE2NTU2RjBBOEUM}

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) - USD ($)
$ in Millions

3 Months Ended

Mar. 31, 2016

Mar. 31, 2015

$ 7,573

$ 8,830

Unrealized Gain (Loss) on Derivatives

(7)

107

Generation Total Consolidated Group [Member]

Segment Reporting Information Revenue Net of Purchase Power And Fuel

2,297

2,407

Generation Mid Atlantic [Member]

4,739

5,840

Segment Reporting Information Revenue Net of Purchase Power And Fuel

841

787

Generation Midwest [Member]

1,520

1,513

Segment Reporting Information Revenue Net of Purchase Power And Fuel

718

703

Generation New England [Member]

1,095

1,276

Segment Reporting Information Revenue Net of Purchase Power And Fuel

158

Generation New York [Member]

470

859

Segment Reporting Information Revenue Net of Purchase Power And Fuel

130

189

Generation ERCOT [Member]

203

310

Segment Reporting Information Revenue Net of Purchase Power And Fuel

Generation Other Regions [Member]

163

180

Segment Reporting Information Revenue Net of Purchase Power And Fuel

Other Segments [Member] | Scenario, Adjustment [Member]

223

214

Segment Reporting Information Revenue Net of Purchase Power And Fuel

Generation All Other Segments [Member]

Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel

Segment Reporting Information Revenue Net of Purchase Power And Fuel

390

469

1,065

1,488

Unrealized Gain (Loss) on Derivatives

154

103

162

Generation All Other Segments [Member] | Scenario, Adjustment [Member]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

(5)

(4)

Generation Reportable Segments Total [Member]

(43)

Segment Reporting Information Revenue Net of Purchase Power And Fuel

1,907

1,938

Generation Reportable Segments Total [Member] | Scenario, Adjustment [Member]

3,674

4,352

Segment Reporting Information Revenue Net of Purchase Power And Fuel

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]

Intersegment Eliminations [Member] | Generation Mid Atlantic [Member]

(21)

Intersegment Eliminations [Member] | Generation Midwest [Member]

^[1]

(12)

(43)

(6)

Intersegment Eliminations [Member] | Generation New England [Member]

(5)

(24)

Intersegment Eliminations [Member] | Generation New York [Member]

(1)

(6)

(11)

Intersegment Eliminations [Member] | Generation ERCOT [Member]

^[1]

(15)

(20)

(33)

Intersegment Eliminations [Member] | Generation Other Regions [Member]

(1)

(10)

(26)

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

^[2]

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

^[3]

(34)

(90)

Operating Segments [Member] | Generation Total Consolidated Group [Member]

(21)

(45)

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

2,297

2,407

Operating Segments [Member] | Generation Mid Atlantic [Member]

^[4]

4,739

5,840

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

832

808

Operating Segments [Member] | Generation Midwest [Member]

^[1],[4]

1,532

1,556

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

715

709

Operating Segments [Member] | Generation New England [Member]

^[4]

1,089

1,276

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

182

Operating Segments [Member] | Generation New York [Member]

^[4]

471

865

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

141

169

Operating Segments [Member] | Generation ERCOT [Member]

^[1],[4]

218

307

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

Operating Segments [Member] | Generation Other Regions [Member]

^[4]

163

181

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

Operating Segments [Member] | Generation All Other Segments [Member]

^[2],[4]

222

212

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

356

379

Operating Segments [Member] | Generation Reportable Segments Total [Member]

Segment Reporting Information Revenue Net Of Purchase Power And Fuel From External Customers

1,941

2,028