Commonwealth Edison 10-Q 29 Apr 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015
Entity Registrant Name	EXELON CORP
Entity Central Index Key	1109357
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	-19
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding	861,243,550
Exelon Generation Co L L C [Member]
Entity Registrant Name	EXELON GENERATION CO LLC
Entity Central Index Key	1168165
Entity Filer Category	Non-accelerated Filer
Commonwealth Edison Co [Member]
Entity Registrant Name	COMMONWEALTH EDISON CO
Entity Central Index Key	22606
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	127,016,962
PECO Energy Co [Member]
Entity Registrant Name	PECO ENERGY CO
Entity Central Index Key	78100
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	170,478,507
Baltimore Gas and Electric Company [Member]
Entity Registrant Name	BALTIMORE GAS AND ELECTRIC
Entity Central Index Key	9466
Entity Filer Category	Non-accelerated Filer
Entity Common Stock Shares Outstanding	1,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations and Comprehensive Income (Unaudited) (USD $)	3 Months Ended
In Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Operating revenues [Abstract]
Operating revenues from affiliates	$1	[1]	$1	[1]
Interest expense	8,830	[2]	7,237	[2]
Operating expenses
Purchased power and fuel	4,470		4,006
Purchased power and fuel from affiliates	0		334
Operating and maintenance	2,081		1,858
Depreciation and amortization	610		564
Taxes other than income	304		293
Total operating expenses	7,465		7,055
Equity in losses of unconsolidated affiliates			-19
Gain (Loss) on Sale of Assets and Asset Impairment Charges	1		5
Operating income	1,366		168
Other income and (deductions)
Interest expense, net	-335		-217
Interest expense to affiliates	-10		-10
Other, net	80		98
Total other income and (deductions)	-265		-129
Income before income taxes	1,101		39
Income taxes	363		-54
Net income	738		93
Net income attributable to noncontrolling interest and preference stock dividends	45		3
Net income attributable to common shareholders	693		90
Pension and non-pension postretirement benefit plans:
Prior service (benefit) cost reclassified to periodic benefit cost	-11		1
Actuarial loss reclassified to periodic cost	54		34
Pension and non-pension postretirement benefit plans valuation adjustment	26		13
Unrealized gain (loss) on cash flow hedges	6		-25
Unrealized gain on equity investments	0		12
Unrealized loss on foreign currency translation	-12		-5
Other comprehensive income	11	[3]	4	[3]
Comprehensive income	749		97
Average shares of common stock outstanding:
Average common shares outstanding — basic	862		858
Average common shares outstanding — diluted	867		861
Earnings per average common share:
Earnings per share - basic (in usd per share)	$0.80		$0.10
Earnings per average common share - diluted
Earnings per share - diluted (in usd per share)	$0.80		$0.10
Dividends per common share (in usd per share)	$0.31		$0.31
Exelon Generation Co L L C [Member]
Operating revenues [Abstract]
Operating revenues	5,629		4,056
Operating revenues from affiliates	211		334
Interest expense	5,840		4,390
Operating expenses
Purchased power and fuel from affiliates	7		349
Purchased power and fuel	3,426		3,008
Operating and maintenance	1,162		938
Operating and maintenance from affiliates	149		149
Depreciation and amortization	254		211
Taxes other than income	122		105
Total operating expenses	5,120		4,760
Equity in losses of unconsolidated affiliates			-19
Gain (Loss) on Sale of Assets and Asset Impairment Charges	-1		5
Operating income	719		-384
Other income and (deductions)
Interest expense, net	-90		-73
Interest expense to affiliates	-12		-12
Other, net	94		85
Total other income and (deductions)	-8		0
Income before income taxes	711		-384
Income taxes	226		-199
Net income	485		-185
Net income attributable to noncontrolling interests	42		0
Net income (loss) attributable to membership interest	443		-185
Pension and non-pension postretirement benefit plans:
Unrealized gain (loss) on cash flow hedges	-5		-25
Unrealized gain on equity investments	0		12
Unrealized loss on foreign currency translation	-12		-5
Unrealized loss on marketable securities	0		-3
Other comprehensive income	-17	[3]	-21	[3]
Comprehensive income	468		-206
Commonwealth Edison Co [Member]
Operating revenues [Abstract]
Operating revenues	1,184		1,133
Operating revenues from affiliates	1		1
Interest expense	1,185		1,134
Operating expenses
Purchased power and fuel	318		212
Purchased power and fuel from affiliates	9		108
Operating and maintenance	333		287
Operating and maintenance from affiliates	45		39
Depreciation and amortization	175		173
Taxes other than income	75		77
Total operating expenses	955		896
Operating income	230		238
Other income and (deductions)
Interest expense, net	-81		-77
Interest expense to affiliates	-3		-3
Other, net	3		5
Total other income and (deductions)	-81		-75
Income before income taxes	149		163
Income taxes	59		65
Net income	90		98
Pension and non-pension postretirement benefit plans:
Comprehensive income	90		98
PECO Energy Co [Member]
Operating revenues [Abstract]
Operating revenues	985		992
Operating revenues from affiliates	0		1
Interest expense	985		993
Operating expenses
Purchased power and fuel	376		377
Purchased power and fuel from affiliates	62		87
Operating and maintenance	197		256
Operating and maintenance from affiliates	25		24
Depreciation and amortization	62		58
Taxes other than income	41		42
Total operating expenses	763		844
Equity in losses of unconsolidated affiliates			0
Gain (Loss) on Sale of Assets and Asset Impairment Charges			0
Gain (Loss) on Disposition of Assets	1
Operating income	223		149
Other income and (deductions)
Interest expense, net	-25		-25
Interest expense to affiliates	-3		-3
Other, net	2		2
Total other income and (deductions)	-26		-26
Income before income taxes	197		123
Income taxes	58		34
Net income	139		89
Net income attributable to common shareholders	139		89
Pension and non-pension postretirement benefit plans:
Comprehensive income	139		89
Baltimore Gas and Electric Company [Member]
Operating revenues [Abstract]
Operating revenues	1,029		1,038
Operating revenues from affiliates	7		16
Interest expense	1,036		1,054
Operating expenses
Purchased power and fuel	350		409
Purchased power and fuel from affiliates	137		120
Operating and maintenance	156		163
Operating and maintenance from affiliates	26		25
Depreciation and amortization	106		108
Taxes other than income	57		60
Total operating expenses	832		885
Equity in losses of unconsolidated affiliates			0
Operating income	204		169
Other income and (deductions)
Interest expense, net	-21		-23
Interest expense to affiliates	-4		-4
Other, net	4		4
Total other income and (deductions)	-21		-23
Income before income taxes	183		146
Income taxes	74		58
Net income	109		88
Preferred security dividends and redemption	3		3
Net income attributable to common shareholders	106		85
Pension and non-pension postretirement benefit plans:
Comprehensive income	$109		$88
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NzEwQ0VGNzJGQTI1RkM2RDgzOUMwOTNBRjYwNUU2MTQM}
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}
[3]	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income	$738	$93
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	948	908
Impairment of long-lived assets	0	1
Gain on sales of assets	-1	-5
Deferred income taxes and amortization of investment tax credits	129	-48
Net fair value changes related to derivatives	-91	730
Net realized and unrealized gains on nuclear decommissioning trust fund investments	-47	-26
Other non-cash operating activities	344	276
Changes in assets and liabilities:
Accounts receivable	-270	-606
Inventories	291	80
Accounts payable, accrued expenses and other current liabilities	-607	157
Option premiums received, net	5	15
Counterparty collateral received (posted), net	31	-677
Income taxes	174	17
Pension and non-pension postretirement benefit contributions	-269	-472
Other assets and liabilities	115	-278
Net cash flows provided by operating activities	1,490	165
Cash flows from investing activities
Capital expenditures	-1,784	-1,217
Proceeds from nuclear decommissioning trust fund sales	1,681	1,825
Investment in nuclear decommissioning trust funds	-1,747	-1,878
Acquisition of businesses	-15	0
Proceeds from sale of long-lived assets	142	18
Proceeds from termination of direct financing lease investment	0	335
Change in restricted cash	-26	-40
Other investing activities	-2	-54
Net cash flows used in investing activities	-1,751	-1,011
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings	-141	638
Issuance of long-term debt	1,206	950
Retirement of long-term debt	-580	-1,150
Dividends paid on common stock	-269	-266
Proceeds from employee stock plans	8	7
Other financing activities	-16	-28
Net cash flows provided by financing activities	208	151
Decrease in cash and cash equivalents	-53	-695
Cash and cash equivalents at beginning of period	1,878	1,609
Cash and cash equivalents at end of period	1,825	914
Exelon Generation Co L L C [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income	485	-185
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	591	557
Impairment of long-lived assets	0	1
Gain on sales of assets	1	-5
Deferred income taxes and amortization of investment tax credits	89	-161
Net fair value changes related to derivatives	-165	737
Net realized and unrealized gains on nuclear decommissioning trust fund investments	-47	-26
Other non-cash operating activities	45	89
Changes in assets and liabilities:
Accounts receivable	24	-295
Receivables from and payables to affiliates, net	-10	3
Inventories	228	1
Accounts payable, accrued expenses and other current liabilities	-345	128
Option premiums received, net	5	15
Counterparty collateral received (posted), net	62	-699
Income taxes	-104	-35
Pension and non-pension postretirement benefit contributions	-107	-191
Other assets and liabilities	85	-103
Net cash flows provided by operating activities	837	-169
Cash flows from investing activities
Capital expenditures	-937	-535
Proceeds from nuclear decommissioning trust fund sales	1,681	1,825
Investment in nuclear decommissioning trust funds	-1,747	-1,878
Changes in intercompany money pool		44
Acquisition of businesses	-15	0
Proceeds from sale of long-lived assets	142	18
Change in restricted cash	-21	9
Other investing activities	-2	-77
Net cash flows used in investing activities	-899	-594
Changes in Exelon intercompany money pool	936
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings	-1	354
Issuance of long-term debt	806	300
Retirement of long-term debt	-18	-532
Repayments of Related Party Debt	-550	0
Other financing activities	-3	-21
Distribution to member	-1,356	-30
Changes in Exelon intercompany money pool	936
Net cash flows provided by financing activities	-186	71
Decrease in cash and cash equivalents	-248	-692
Cash and cash equivalents at beginning of period	780	1,258
Cash and cash equivalents at end of period	532	566
Commonwealth Edison Co [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income	90	98
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	175	173
Deferred income taxes and amortization of investment tax credits	35	35
Other non-cash operating activities	126	36
Changes in assets and liabilities:
Accounts receivable	-38	-64
Receivables from and payables to affiliates, net	-2	-19
Inventories	-10	2
Accounts payable, accrued expenses and other current liabilities	-126	-57
Income taxes	131	44
Pension and non-pension postretirement benefit contributions	-121	-233
Other assets and liabilities	-9	-24
Net cash flows provided by operating activities	251	-9
Cash flows from investing activities
Capital expenditures	-530	-341
Proceeds from sales of investments	0	3
Other investing activities	7	8
Net cash flows used in investing activities	-523	-330
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings	-21	350
Issuance of long-term debt	400	650
Retirement of long-term debt	0	-617
Dividends paid on common stock	-75	-76
Other financing activities	-4	-1
Contributions from parent	14	38
Net cash flows provided by financing activities	314	344
Decrease in cash and cash equivalents	42	5
Cash and cash equivalents at beginning of period	66	36
Cash and cash equivalents at end of period	108	41
PECO Energy Co [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income	139	89
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	62	58
Gain on sales of assets		0
Deferred income taxes and amortization of investment tax credits	5	-2
Other non-cash operating activities	44	49
Changes in assets and liabilities:
Accounts receivable	-115	-110
Receivables from and payables to affiliates, net	5	2
Inventories	34	45
Accounts payable, accrued expenses and other current liabilities	1	117
Income taxes	67	33
Pension and non-pension postretirement benefit contributions	-12	-11
Other assets and liabilities	-72	-127
Net cash flows provided by operating activities	158	143
Cash flows from investing activities
Capital expenditures	-148	-184
Other investing activities	4	2
Net cash flows used in investing activities	-144	-182
Changes in Exelon intercompany money pool	65
Net Cash Provided by (Used in) Financing Activities [Abstract]
Dividends paid on common stock	-70	-80
Other financing activities	-1	0
Changes in Exelon intercompany money pool	65
Net cash flows provided by financing activities	-6	-80
Decrease in cash and cash equivalents	8	-119
Cash and cash equivalents at beginning of period	30	217
Cash and cash equivalents at end of period	38	98
Baltimore Gas and Electric Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net income	109	88
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	106	108
Deferred income taxes and amortization of investment tax credits	33	27
Other non-cash operating activities	64	43
Changes in assets and liabilities:
Accounts receivable	-141	-132
Receivables from and payables to affiliates, net	-8	-8
Inventories	38	33
Accounts payable, accrued expenses and other current liabilities	-8	-16
Counterparty collateral received (posted), net	-27	22
Income taxes	26	31
Pension and non-pension postretirement benefit contributions	-4	-5
Other assets and liabilities	93	44
Net cash flows provided by operating activities	281	235
Cash flows from investing activities
Capital expenditures	-136	-146
Change in restricted cash	2	-47
Other investing activities	2	6
Net cash flows used in investing activities	-132	-187
Net Cash Provided by (Used in) Financing Activities [Abstract]
Changes in short-term borrowings	-120	-66
Dividends paid on common stock	-36	0
Other financing activities	-13	13
Contributions from parent	0
Dividends paid on preferred securities	-3	-3
Net cash flows provided by financing activities	-172	-56
Decrease in cash and cash equivalents	-23	-8
Cash and cash equivalents at beginning of period	64
Cash and cash equivalents at end of period	$41	$23

Consolidated_Balance_Sheets_Un

Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Assets, Current [Abstract]
Cash and cash equivalents	$1,825		$1,878
Restricted cash and cash equivalents	297		271
Accounts receivable, net
Customer	3,702		3,482
Other	1,077		1,227
Mark-to-market derivative assets	1,117		1,279
Unamortized energy contract assets	209		254
Inventories, net
Fossil fuel and emission allowances	266		579
Materials and supplies	1,035		1,024
Deferred income taxes	231		244
Regulatory assets	804		847
Disposal Group, Including Discontinued Operation, Assets, Current	1		147
Other	793		865
Total current assets	11,357		12,097
Property, plant and equipment, net	53,001		52,087
Deferred debits and other assets
Regulatory assets	6,068		6,076
Nuclear decommissioning trust funds	10,712		10,537
Investments	568		544
Goodwill	2,672		2,672
Mark-to-market derivative assets	913		773
Unamortized energy contracts assets	558		549
Pledged assets for Zion Station decommissioning	308		319
Other	1,234		1,160
Total deferred debits and other assets	23,033		22,630
Total assets	87,391		86,814
Liabilities, Current [Abstract]
Short-term borrowings	309		460
Long-term debt due within one year	1,260		1,802
Accounts payable	2,839		3,048
Accrued expenses	1,230		1,539
Regulatory liabilities	421		310
Mark-to-market derivative liabilities (current liabilities)	117		234
Unamortized energy contract liabilities	172		238
Other	1,018		1,123
Due to Affiliate, Current	8		8
Total current liabilities	7,374		8,762
Long-term debt	20,519		19,362
Long-term debt to financing trusts	648		648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,218		13,019
Asset retirement obligations	7,446		7,295
Pension obligations	3,154		3,366
Non-pension postretirement benefit obligations	1,825		1,742
Spent nuclear fuel obligation	1,021		1,021
Regulatory liabilities	4,566		4,550
Mark-to-market derivative liabilities (noncurrent liabilities)	491		403
Unamortized energy contract liabilities	189		211
Payable for Zion Station decommissioning	136		155
Other	2,166		2,147
Total deferred credits and other liabilities	34,212		33,909
Total liabilities	62,753	[1]	62,681	[1]
Commitments and contingencies
Stockholders' Equity Attributable to Parent [Abstract]
Common stock	16,731		16,709
Treasury stock, at cost (35 shares at both March 31, 2015 and December 31, 2014)	-2,327		-2,327
Retained earnings	11,334		10,910
Accumulated other comprehensive loss, net	-2,673	[2]	-2,684	[2]
Total shareholders’ equity	23,065		22,608
BGE preference stock not subject to mandatory redemption	193		193
Noncontrolling interest	1,380		1,332
Total equity	24,638		24,133
Total liabilities and shareholders’ equity	87,391		86,814
Member’s equity
Accumulated other comprehensive loss, net	-2,673	[2]	-2,684	[2]
Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]
Deferred debits and other assets
Total assets	8,182		8,160
Deferred credits and other liabilities
Total liabilities	2,702		2,723
Exelon Generation Co L L C [Member]
Assets, Current [Abstract]
Cash and cash equivalents	532		780
Restricted cash and cash equivalents	179		158
Accounts receivable, net
Customer	2,320		2,295
Other	378		318
Mark-to-market derivative assets	1,116		1,276
Unamortized energy contract assets	209		254
Receivables from affiliates	115		113
Inventories, net
Fossil fuel and emission allowances	232		465
Materials and supplies	841		847
Deferred income taxes	266		327
Disposal Group, Including Discontinued Operation, Assets, Current	1		147
Other	530		658
Total current assets	6,719		7,638
Property, plant and equipment, net	23,414		22,945
Deferred debits and other assets
Nuclear decommissioning trust funds	10,712		10,537
Investments	122		104
Goodwill	47		47
Mark-to-market derivative assets	911		771
Unamortized energy contracts assets	558		549
Deferred Tax Assets, Net, Noncurrent	3		3
Pledged assets for Zion Station decommissioning	308		319
Other	776		731
Prepaid pension asset	1,748		1,704
Total deferred debits and other assets	15,185		14,765
Total assets	45,318	[3]	45,348	[3]
Liabilities, Current [Abstract]
Short-term borrowings	25		36
Long-term debt due within one year	75		58
Accounts payable	1,634		1,759
Accrued expenses	694		886
Mark-to-market derivative liabilities (current liabilities)	97		214
Unamortized energy contract liabilities	172		238
Other	532		605
Payables to affiliates	110		107
Related Party Transaction, Due from (to) Related Party	936
Due to Affiliate, Current	0		556
Total current liabilities	4,275		4,459
Long-term debt	7,477		6,709
Long-term debt to affiliate	940		943
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	6,091		6,034
Asset retirement obligations	7,296		7,146
Non-pension postretirement benefit obligations	919		915
Spent nuclear fuel obligation	1,021		1,021
Mark-to-market derivative liabilities (noncurrent liabilities)	121		105
Unamortized energy contract liabilities	189		211
Payable for Zion Station decommissioning	136		155
Other	764		719
Payables to affiliates	2,921		2,880
Total deferred credits and other liabilities	19,458		19,186
Total liabilities	32,150	[3]	31,297	[3]
Commitments and contingencies
Stockholders' Equity Attributable to Parent [Abstract]
Accumulated other comprehensive loss, net	-53	[2]	-36	[2]
Noncontrolling interest	1,380		1,333
Member’s equity
Membership interest	8,951		8,951
Undistributed earnings	2,890		3,803
Accumulated other comprehensive loss, net	-53	[2]	-36	[2]
Total member's equity	11,788		12,718
Total equity	13,168		14,051
Total liabilities and equity	45,318		45,348
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]
Deferred debits and other assets
Total assets	8,118		8,119
Deferred credits and other liabilities
Total liabilities	2,486		2,507
Commonwealth Edison Co [Member]
Assets, Current [Abstract]
Cash and cash equivalents	108		66
Restricted cash and cash equivalents	4		4
Accounts receivable, net
Customer	503		477
Other	512		648
Receivables from affiliates	17		14
Inventories, net
Regulatory assets	317		349
Other	41		40
Inventories, net	135		125
Total current assets	1,637		1,723
Property, plant and equipment, net	16,099		15,793
Deferred debits and other assets
Regulatory assets	866		852
Investments	6		6
Goodwill	2,625		2,625
Other	276		271
Receivable from affiliate	2,603		2,571
Prepaid pension asset	1,619		1,551
Total deferred debits and other assets	7,995		7,876
Total assets	25,731		25,392
Liabilities, Current [Abstract]
Short-term borrowings	283		304
Long-term debt due within one year	260		260
Accounts payable	534		598
Accrued expenses	223		331
Deferred income taxes	44		63
Regulatory liabilities	131		125
Mark-to-market derivative liabilities (current liabilities)	20		20
Other	69		73
Customer deposits	128		128
Due to Affiliate, Current	84		84
Total current liabilities	1,776		1,986
Long-term debt	6,099		5,698
Long-term debt to financing trusts	206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,553		4,498
Asset retirement obligations	103		103
Non-pension postretirement benefit obligations	262		263
Regulatory liabilities	3,692		3,655
Mark-to-market derivative liabilities (noncurrent liabilities)	221		187
Other	881		889
Total deferred credits and other liabilities	9,712		9,595
Total liabilities	17,793		17,485
Commitments and contingencies
Stockholders' Equity Attributable to Parent [Abstract]
Common stock	1,588		1,588
Retained earnings	866		851
Other paid-in capital	5,484		5,468
Total shareholders’ equity	7,938		7,907
Total liabilities and shareholders’ equity	25,731		25,392
PECO Energy Co [Member]
Assets, Current [Abstract]
Cash and cash equivalents	38		30
Restricted cash and cash equivalents	2		2
Accounts receivable, net
Customer	390		320
Other	123		141
Receivables from affiliates	3		3
Inventories, net
Fossil fuel and emission allowances	19		57
Materials and supplies	26		22
Deferred income taxes	70		69
Regulatory assets	41		29
Other	30		31
Prepaid utility taxes	107		10
Total current assets	849		714
Property, plant and equipment, net	6,867		6,801
Deferred debits and other assets
Regulatory assets	1,543		1,529
Investments	31		31
Other	32		34
Receivable from affiliate	500		490
Prepaid pension asset	347		344
Total deferred debits and other assets	2,453		2,428
Total assets	10,169		9,943
Liabilities, Current [Abstract]
Accounts payable	334		337
Accrued expenses	109		91
Regulatory liabilities	119		90
Other	31		31
Payables to affiliates	65		0
Customer deposits	53		52
Due to Affiliate, Current	57		52
Total current liabilities	768		653
Long-term debt	2,246		2,246
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,708		2,671
Asset retirement obligations	29		29
Non-pension postretirement benefit obligations	287		287
Regulatory liabilities	662		657
Other	95		95
Total deferred credits and other liabilities	3,781		3,739
Total liabilities	6,979		6,822
Commitments and contingencies
Stockholders' Equity Attributable to Parent [Abstract]
Common stock	2,439		2,439
Retained earnings	750		681
Accumulated other comprehensive loss, net	1	[2]	1	[2]
Total shareholders’ equity	3,190		3,121
Total liabilities and shareholders’ equity	10,169		9,943
Member’s equity
Accumulated other comprehensive loss, net	1	[2]	1	[2]
Baltimore Gas and Electric Company [Member]
Assets, Current [Abstract]
Cash and cash equivalents	41		64
Restricted cash and cash equivalents	48		50
Accounts receivable, net
Customer	489		390
Other	99		82
Inventories, net
Fossil fuel and emission allowances	16		57
Materials and supplies	33		30
Deferred income taxes	15		6
Regulatory assets	187		214
Other	4		5
Prepaid utility taxes	30		59
Total current assets	962		957
Property, plant and equipment, net	6,280		6,204
Deferred debits and other assets
Regulatory assets	491		510
Investments	12		12
Other	28		25
Prepaid pension asset	357		370
Total deferred debits and other assets	888		917
Total assets	8,130		8,078
Liabilities, Current [Abstract]
Short-term borrowings	0		120
Long-term debt due within one year	75		75
Accounts payable	222		215
Accrued expenses	155		131
Deferred income taxes	36		52
Regulatory liabilities	124		44
Other	27		51
Customer deposits	95		92
Due to Affiliate, Current	46		66
Total current liabilities	780		846
Long-term debt	1,867		1,867
Long-term debt to financing trusts	258		258
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,924		1,865
Asset retirement obligations	18		17
Non-pension postretirement benefit obligations	211		212
Regulatory liabilities	187		200
Other	62		60
Total deferred credits and other liabilities	2,402		2,354
Total liabilities	5,307	[4]	5,325	[4]
Stockholders' Equity Attributable to Parent [Abstract]
Common stock	1,360		1,360
Retained earnings	1,273		1,203
Total shareholders’ equity	2,633		2,563
BGE preference stock not subject to mandatory redemption	190		190
Total equity	2,823		2,753
Total liabilities and shareholders' equity	8,130		8,078
Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]
Deferred debits and other assets
Total assets	49		24
Deferred credits and other liabilities
Total liabilities	$200		$197
[1]	Exelon’s consolidated assets include $8,182 million and $8,160 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,702 million and $2,723 million at March 31, 2015 and December 31, 2014, 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 parentheses represent a decrease in accumulated other comprehensive income.
[3]	Generation’s consolidated assets include $8,118 million and $8,119 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,486 million and $2,507 million at March 31, 2015 and December 31, 2014, 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 $49 million and $24 million at March 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $200 million and $197 million at March 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 — Variable Interest Entities.

Consolidated_Balance_Sheets_Un1

Consolidated Balance Sheets (Unaudited) (Parenthetical)	Mar. 31, 2015	Dec. 31, 2014
Stockholders' Equity Attributable to Parent [Abstract]
Common Stock, Shares Authorized	2,000,000,000	2,000,000,000
Common Stock, Shares, Outstanding	861,243,550	859,825,013
Treasury Stock, Shares held	35,000,000	35,000,000

Consolidated_Statement_of_Chan

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (USD $)		Total	Common Stock [Member]	Treasury Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Preference Stock Not Subject To Mandatory Redemption [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member]
In Millions, except Share data in Thousands, unless otherwise specified										Undistributed Earnings [Member]	Membership Interest [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]		Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]		Common Stock [Member]	Other Additional Capital [Member]	Retained Earnings, Unappropriated [Member]	Retained Earnings, Appropriated [Member]		Common Stock [Member]	Nonredeemable Preferred Stock [Member]	Retained Earnings [Member]
Beginning Balance at Dec. 31, 2014		$22,608												$3,121	$2,439	$681	$1	$7,907	$1,588	$5,468	($1,639)	$2,490	$2,563	$1,360	$190	$1,203
Beginning Balance at Dec. 31, 2014		24,133	16,709	-2,327	10,910	-2,684	1,332	193															2,753
Beginning Balance (in shares) at Dec. 31, 2014		894,568
Beginning Balance at Dec. 31, 2014									14,051	3,803	8,951	-36	1,333
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		738			693		42	3	485	443		0	42	139		139		90			90		109		0	109
Noncontrolling Interest, Increase from Sale of Parent Equity Interest									5	0		0	5
Long-term incentive plan activity (in shares)		1,156
Long-term incentive plan activity		12	12
Employee stock purchase plan issuances (in shares)		255
Employee stock purchase plan issuances		8	8
Appropriation of retained earnings for future dividends																		0			-90	90
Tax benefit on stock compensation		2	2
Common stock dividends		-269			-269			-3						-70		-70		-75				-75
Contribution from parent																		14		14
Distribution to members									-1,356	-1,356		0	0
Allocation of tax benefit from parent																		2		2
Minority Interest Increase From Acquisition		6					6
Preferred security dividends		-3																					-3		0	-3
Other comprehensive loss, net of income taxes of $53		11				11			-17	0		-17	0
Other comprehensive income (loss), net of tax	[1]	11							-17
Ending Balance at Mar. 31, 2015		23,065												3,190	2,439	750	1	7,938	1,588	5,484	-1,639	2,505	2,633	1,360	190	1,273
Ending Balance at Mar. 31, 2015		24,638	16,731	-2,327	11,334	-2,673	1,380	193															2,823
Ending Balance (in shares) at Mar. 31, 2015		895,979
Ending Balance at Mar. 31, 2015									$13,168	$2,890	$8,951	($53)	$1,380
[1]	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.

Consolidated_Statement_of_Chan1

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Income taxes	$363	($54)
Exelon Generation Co L L C [Member]
Income taxes	226	-199
PECO Energy Co [Member]
Income taxes	58	34
Commonwealth Edison Co [Member]
Income taxes	59	65
Baltimore Gas and Electric Company [Member]
Income taxes	$74	$58

Basis_of_Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)	Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)
	Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses.
	The energy generation business includes:
	•	Generation:    Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions.
	The energy delivery businesses include:
	•	ComEd:   Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.
	•	PECO:    Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
	•	BGE:    Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore.
	Each of the Registrant’s consolidated financial statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated. As a result of the Registrants' 2014 divestiture of certain unconsolidated affiliates considered integral to their operations and the consolidation of CENG during 2014, all Equity in earnings (losses) from unconsolidated affiliates will be presented below Income taxes in the Registrants' Statement of Operations and Comprehensive Income starting in the first quarter of 2015. For the three months ended March 31, 2015, Equity in earnings (losses) of unconsolidated affiliates was less than $1 million.
	The accompanying consolidated financial statements as of March 31, 2015 and 2014 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, 2014 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, 2015. 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 2014 Form 10-K Reports.

New_Accounting_Pronouncements_

New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)	New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)
	The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of the Registrants.
	Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
	In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either run the software on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted. The guidance can be applied retrospectively to each prior reporting period presented or prospectively to arrangements entered into, or materially modified, after the effective date. The Registrants are currently assessing the impact this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance.
	Simplifying the Presentation of Debt Issuance Costs
	In April 2015, the FASB issued authoritative guidance that changes the presentation of debt issuance costs in financial statements. The new guidance requires entity’s to present such costs in the balance sheet as a direct reduction to the related debt liability rather than as a deferred cost (i.e., an asset) as required by current guidance. The new standard does not change the recognition or measurement of debt issuance costs. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The guidance is required to be applied retrospectively to all prior periods presented. The Registrants are currently assessing the impact this guidance may have on their financial positions and disclosures, as well as whether to early adopt. The standard will not impact the results of operations and cash flows of the Registrants.
	Amendments to the Consolidation Analysis
	In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the assessment of limited partnerships as VIEs, (2) amends the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2015. Early adoption is permitted. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impact this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. The Registrants do not plan to early adopt the standard.
	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 guidance 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 financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016; and early adoption would not be permitted.  However, in April 2015, FASB proposed a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017. In addition, the FASB proposal would include an option to early adopt the guidance for annual periods beginning on or after December 15, 2016.

Variable_Interest_Entities_Exe

Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Variable Interest Entity [Abstract]
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)	Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)
	Under the applicable authoritative guidance, a VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s economic performance.
	At March 31, 2015 and December 31, 2014, Exelon, Generation, and BGE collectively consolidated six VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of March 31, 2015 and December 31, 2014, the Registrants had significant interests in seven and six other VIEs, respectively, for which the Registrants do not have the power to direct the entities’ activities and, accordingly, were not the primary beneficiary.
	Consolidated Variable Interest Entities
	Exelon, Generation and BGE’s consolidated VIEs consist of:
	•	BondCo, a special purpose bankruptcy remote limited liability company formed by BGE to acquire, hold, issue and service bonds secured by rate stabilization property,
	•	a retail gas group formed by Generation to enter into a collateralized gas supply agreement with a third-party gas supplier
	•	a group of solar project limited liability companies formed by Generation to build, own and operate solar power facilities,
	•	several wind project companies designed by Generation to develop, construct and operate wind generation facilities,
	•	certain retail power companies for which Generation is the sole supplier of energy, and
	•	CENG.
	As of March 31, 2015 and December 31, 2014, ComEd and PECO do not have any material consolidated VIEs.
	As of March 31, 2015 and December 31, 2014, Exelon, Generation, and BGE provided the following support to their respective consolidated VIEs:
	•	In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three months ended March 31, 2015 and March 31, 2014, BGE remitted $21 million and $21 million to BondCo, respectively.
	•	Generation provides operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to the Antelope Valley project.
	•	Generation and Exelon, where indicated, provide the following support to CENG (see Note 6 — Investment in Constellation Energy Nuclear Group, LLC, and Note 25 — Related Party Transactions, of the Exelon 2014 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 Inc. (EDFI) (a subsidiary 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 will purchase 50.01% of the available output generated by the CENG nuclear plants 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) which Ginna entered into with Rochester Gas and Electric Corporation (RG&E) on February 13, 2015. The obligations under the RSSA commenced on April 1, 2015 and are effective through September 30, 2018, (see Note 5 — Regulatory Matters for additional details),
	•	Generation provided a $400 million loan to CENG. As of March 31, 2015, the remaining obligation is $288 million, which reflects the principal payment made in January 2015 (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC of the Exelon 2014 Form 10-K for additional details),
	•	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 Agreement. (See Note 17 — 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, 2015, the remaining obligation is approximately $2 million,
	•	Generation and EDFI share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance (see Note 17 — Commitments and Contingencies for more details),
	•	Generation provides a guarantee of approximately $7 million associated with hazardous waste management facilities and underground storage tanks. In addition, EDFI executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts paid by Generation under this guarantee,
	•	Generation and EDFI are the members-insured with Nuclear Electric Insurance Limited (NEIL) 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 17 — 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 $7 million in credit support for the retail power companies for which Generation is the sole supplier of energy, and
	•	Generation provides a $75 million parental guarantee to the third-party gas supplier in support of its retail gas group.
	For each of the consolidated VIEs, except as otherwise noted:
	•	the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
	•	Exelon, Generation and BGE did not provide any additional material financial support to the VIEs;
	•	Exelon, Generation and BGE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and
	•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s or BGE’s general credit.
	The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in Exelon’s, Generation’s, and BGE’s consolidated financial statements at March 31, 2015 and December 31, 2014 are as follows:
		31-Mar-15									31-Dec-14
		Exelon(a)			Generation			BGE			Exelon(a)			Generation			BGE
	Current assets	$	1,185		$	1,134		$	46		$	1,271		$	1,242		$	21
	Noncurrent assets	7,676			7,664			3			7,580			7,566			3
	Total assets	$	8,861		$	8,798		$	49		$	8,851		$	8,808		$	24
	Current liabilities	$	520		$	434		$	80		$	611		$	526		$	77
	Noncurrent liabilities	2,812			2,682			120			2,730			2,600			120
	Total liabilities	$	3,332		$	3,116		$	200		$	3,341		$	3,126		$	197
	_______________________
	(a)	Includes certain purchase accounting adjustments not pushed down to the BGE 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, 2015 and December 31, 2014, these assets and liabilities primarily consisted of the following:
			March 31, 2015									December 31, 2014
			Exelon			Generation			BGE			Exelon			Generation				BGE
	Cash and cash equivalents		$	334		$	334		$	—		$	392		$	392		$	—
	Restricted cash			159			113			46			117			96			21
	Accounts receivable, net
		Customer		296			296			—			297			297			—
		Other		33			33			—			57			57			—
	Mark-to-market derivatives assets			130			130			—			171			171			—
	Inventory
		Materials and supplies		168			168			—			172			172			—
	Other current assets			40			34			—			33			26			—
		Total current assets		1,160			1,108			46			1,239			1,211			21
	Property, plant and equipment, net			4,720			4,720			—			4,638			4,638			—
	Nuclear decommissioning trust funds			2,114			2,114			—			2,097			2,097			—
	Goodwill			47			47			—			47			47			—
	Mark-to-market derivatives assets			51			51			—			44			44			—
	Other noncurrent assets			90			78			3			95			82			3
	Total noncurrent assets			7,022			7,010			3			6,921			6,908			3
	Total assets	$	8,182		$	8,118		$	49		$	8,160		$	8,119		$	24
Long-term debt due within one year		$	85		$	5		$	75		$	87		$	5		$	75
Accounts payable			268			268			—			292			292			—
Accrued expenses			77			71			5			111			108			2
Mark-to-market derivative liabilities			10			10			—			24			24			—
Unamortized energy contract liabilities			9			9			—			22			22			—
Other current liabilities			18			18			—			25			25			—
	Total current liabilities		467			381			80			561			476			77
Long-term debt			211			81			120			212			81			120
Asset retirement obligations			1,843			1,843			—			1,763			1,763			—
Pension obligation(a)			9			9			—			9			9			—
Unamortized energy contract liabilities			48			48			—			51			51			—
	Other noncurrent liabilities		124			124			—			127			127			—
	Noncurrent liabilities		2,235			2,105			120			2,162			2,031			120
	Total liabilities	$	2,702		$	2,486		$	200		$	2,723		$	2,507		$	197
______________
(a)	Includes 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 12 — 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 and the fuel purchase commitments (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements. Further, Exelon and Generation have not provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.
The Registrants’ unconsolidated VIEs consist of:
•	Energy purchase and sale agreements with VIEs for which Generation has concluded that consolidation is not required.
•	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 projects and energy generating facilities for which Generation has concluded that consolidation is not required.
As of March 31, 2015 and December 31, 2014, Exelon and Generation had significant unconsolidated variable interests in seven and six VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The increase in the number of unconsolidated VIEs is due to the execution of an energy purchase and sale agreement with a new unconsolidated VIE. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
31-Mar-15	Commercial			Equity			Total
	Agreement			Investment
	VIEs			VIEs
Total assets(a)	$	259		$	85		$	344
Total liabilities(a)	32			47			79
Exelon's ownership interest in VIE(a)	—			9			9
Other ownership interests in VIE(a)	227			29			256
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—			13			13
Contract intangible asset	9			—			9
Debt and payment guarantees	—			3			3
Net assets pledged for Zion Station decommissioning(b)	27			—			27
31-Dec-14	Commercial			Equity			Total
	Agreement			Investment
	VIEs			VIEs
Total assets(a)	$	506		$	91		$	597
Total liabilities(a)	237			49			286
Exelon's ownership interest in VIE(a)	—			9			9
Other ownership interests in VIE(a)	269			33			302
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	—			13			13
Contract intangible asset	9			—			9
Debt and payment guarantees	—			3			3
Net assets pledged for Zion Station decommissioning(b)	27			—			27
___________________
(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
(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 include, gross pledged assets of $308 million and $319 million as of March 31, 2015 and December 31, 2014, respectively; offset by payables to ZionSolutions, LLC of $281 million and $292 million as of March 31, 2015 and December 31, 2014, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE.
For each 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_Dispo

Mergers, Acquisitions, and Dispositions	3 Months Ended
	Mar. 31, 2015
Business Combinations [Abstract]
Mergers, Acquisitions and Dispositions	Mergers, Acquisitions, and Dispositions
	Proposed Merger with Pepco Holdings, Inc. (Exelon)
	Description of Transaction
	On April 29, 2014, Exelon and Pepco Holdings, Inc. (PHI) signed an agreement and plan of merger (as subsequently amended and restated as of July 18, 2014, the Merger Agreement) to combine the two companies in an all cash transaction. The resulting company will retain the Exelon name and be headquartered in Chicago. Under the Merger Agreement, PHI’s shareholders will receive $27.25 of cash in exchange for each share of PHI common stock. In connection with the Merger Agreement, Exelon entered into a subscription agreement under which it has purchased $144 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI as of March 31, 2015, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. The preferred securities are included in Other non-current assets on Exelon’s Consolidated Balance Sheet. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any. Exelon expects total cash required to fund the acquisition of common stock and preferred securities plus other related acquisition costs to total approximately $7.2 billion. As part of the applications for approval of the merger, under pending or final settlements reached to date, as well as other filings, Exelon and PHI have proposed a package to the PHI utilities’ respective customers, providing for direct investment in excess of approximately $300 million with the actual amount and timing of any related payments dependent upon settlement discussions in merger regulatory approval proceedings and the terms of regulatory orders approving the merger.
	On October 9, 2014, PHI and Exelon each received a request for additional information from the DOJ. The request had the effect of extending the DOJ review period until 30 days after PHI and Exelon each has certified that it had substantially complied with the request. On November 21, 2014, Exelon and PHI each certified that it had substantially complied with the request. Accordingly, the HSR Act waiting period expired on December 22, 2014, and the HSR Act no longer precludes completion of the merger. Although the DOJ allowed the waiting period under the HSR Act to expire without taking any action with respect to the merger, the DOJ has not advised Exelon or PHI that it has concluded its investigation. Exelon and PHI have cooperated with the DOJ regarding the proposed merger.
	To date, the PHI stockholders, the Virginia State Corporation Commission, the New Jersey Board of Public Utilities (NJBPU) and the FERC have approved the merger of PHI and Exelon. The Federal Communications Commission has also approved the transfer of certain PHI communications licenses.
	On February 13, 2015, Exelon and PHI announced that they had reached a settlement agreement in the proceeding before the Delaware Public Service Commission (DPSC) to review the proposed merger. The settlement, which was amended on April 7, 2015 and is subject to the approval of the DPSC, was signed and filed by Exelon, PHI, Delmarva Power & Light Company (DPL), the DPSC Staff, the Delaware Public Advocate, the Delaware Department of Natural Resources and Environment Control, the Delaware Sustainable Energy Utility, the Mid-Atlantic Renewable Energy Coalition and the Clean Air Council. As part of this settlement, Exelon and PHI have proposed a package of benefits to DPL customers and the state of Delaware including the establishment of customer rate credits of $40 million for DPL customers in Delaware, $2 million of funding for energy efficiency programs for DPL low income customers, and $2 million of funding for workforce development.
	On March 17, 2015, Exelon and PHI announced that they had reached a settlement agreement with Montgomery and Prince George’s Counties in the proceeding before the MDPSC to review the proposed merger.  The settlement, which is subject to the approval of the MDPSC, was signed and filed by Exelon, PHI, Montgomery County, Prince George’s County, the National Consumer Law Center, National Housing Trust, Maryland Affordable Housing Coalition, the Housing Association of Nonprofit Developers and a consortium of recreational trail advocacy organizations led by the Mid-Atlantic Off-Road Enthusiasts.  As part of this settlement, Exelon and PHI have proposed a package of benefits to Potomac Electric Power Company (Pepco) and DPL customers and the state of Maryland including the establishment of a customer investment fund of $94.4 million for utility customers in Maryland.  A portion of the customer investment fund, representing approximately $36.8 million, will provide bill credits to Pepco and DPL customers in Maryland, with the remaining $57.6 million funding energy-efficiency programs, including programs targeted to help low income customers lower their energy bills.  Exelon also agreed to establish a Green Sustainability Fund (GSF) of $50 million to be allocated across the service territories of Pepco, DPL and ACE, with $19.8 million allocated to Maryland.  The GSF will be allocated within each state to state and local “green banks” and similar sponsoring organizations to make loans to finance public and private investment in renewable energy, microgrids, and other developing energy technologies.  Loans made by sponsoring organizations from the GSF must mature within 20 years following the merger closing.  At the end of that 20 year period, principal payments received by the sponsoring organizations must be returned to Exelon, but Exelon’s recovery of the entire GSF is not assured.  In the settlement, Exelon also agreed to provide $4 million in funding for workforce development in Maryland and made various other commitments, including a commitment to develop 15 MW of commercial solar projects in Maryland.  In a related agreement with Prince George’s County, Exelon agreed to develop an additional 5 MW of solar generation in Maryland, the output of which will be delivered to Prince George’s County under a 30-year PPA at no cost to the county for the first 15 years and at market pricing for the second 15 years.  This agreement also requires Prince George’s County to purchase substantially all of its requirements for electricity and natural gas from an Exelon affiliate for a period of 15 years, unless the Exelon affiliate is not the lowest bidder.
	On March 10, 2015, Exelon and PHI announced that they had reached a settlement agreement with the Alliance for Solar Choice, a group of solar developers, in the proceeding before the MDPSC. The settlement, which is subject to the approval of the MDPSC, provides for enhancements to the interconnection process for behind-the-meter distributed generation and storage projects.
	Exelon and PHI continue to expect the merger to be completed late in the second or third quarter of 2015.
	Exelon has been named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. The suits seek to enjoin PHI from completing the merger or seek rescission of the merger if completed. In addition, they also seek unspecified damages and costs. Exelon was also named in a federal court suit making similar claims. In September 2014, the parties reached a proposed settlement that would resolve all claims, which is subject to court approval. Final court approval of the proposed settlement is not anticipated until approximately 90 days after merger close. Exelon does not believe these suits will impact the completion of the transaction, and they are not expected to have a material impact on Exelon’s results of operations.
	Including 2014 and through March 31, 2015, Exelon has incurred approximately $289 million of expense associated with the proposed merger, primarily $69 million related to acquisition and integration costs and $220 million of costs incurred to finance the transaction.
	The Merger Agreement also provides for termination rights for both parties. Under certain circumstances, if the Merger Agreement is terminated, PHI may be required to pay Exelon a termination fee ranging from $259 million to $293 million plus certain expenses. If the Merger Agreement is terminated due to a regulatory failure, Exelon may be required to pay PHI a termination fee equal to the amount of purchased nonvoting preferred securities of PHI described above, through the redemption by PHI of the outstanding nonvoting preferred securities for no consideration other than the nominal par value of the stock, plus certain expenses.
	Merger Financing
	Exelon intends to fund the all-cash transaction using a combination of approximately $3.5 billion of debt, up to $1.0 billion in cash from asset sales primarily at Generation, and the remainder through issuance of equity (including mandatory convertible securities). On June 11, 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share in connection with forward sales agreements and $1.2 billion of junior subordinated notes in the form of 23 million equity units.  In addition, Exelon signed a 364-day $7.2 billion senior unsecured bridge credit facility to support the contemplated transaction and provide flexibility for timing of permanent financing, which has subsequently been reduced to a $3.2 billion facility as a result of the execution of the equity issuance and the net after-tax cash proceeds from generating asset divestitures during the second half of 2014. See Note 9 — Debt and Credit Agreements and Note 15 — Common Stock for more information.
	Acquisitions (Exelon and Generation)
	Acquisition of Integrys Energy Group, Inc. (Exelon and Generation)
	On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. As of March 31, 2015, Generation had remitted $319 million to Integrys Energy Group, Inc. and the remaining balance of $13 million is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets. The remaining balance was paid on April 17, 2015.
	Asset Divestitures (Exelon and Generation)
	On January 21, 2015, Generation closed on the sale of the Quail Run generating facility. Including the sale of the Quail Run generating facility, Generation has sold generating assets for total pre-tax proceeds of $1.8 billion (after-tax proceeds of $1.4 billion) which are expected to be used primarily to finance a portion of the acquisition of PHI.
	At March 31, 2015, assets of $1 million related to property, plant and equipment are recorded as Assets held for sale on Exelon’s and Generation’s Consolidated Balance Sheet.

Regulatory_Matters_Exelon_Gene

Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)	Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)
	Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)
	Except for the matters noted below, the disclosures set forth in Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.
	Illinois Regulatory Matters
	Energy Infrastructure Modernization Act (Exelon and ComEd).    Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. EIMA also provides a structure for substantial capital investment by utilities to modernize Illinois’ electric utility infrastructure. EIMA was scheduled to sunset, ending ComEd’s performance based rate formula and investment commitment, at December 31, 2017, unless approved to continue through 2022 by the Illinois General Assembly. On April 3, 2015, the Governor signed legislation extending the EIMA sunset from 2017 to 2019.
	Participating utilities are required to file an annual update to the performance-based formula rate tariff on or before May 1, with resulting rates effective in January of the following year. This annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement(s) in effect for the prior year and actual costs incurred for that year. Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement(s) in effect and ComEd’s best estimate of the revenue requirement expected to be approved by the ICC for that year’s reconciliation. As of March 31, 2015, and December 31, 2014, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $316 million and $371 million, respectively. The regulatory asset associated with distribution true-up is amortized to Operating revenues as the associated amounts are recovered through rates.
	On April 15, 2015, ComEd filed its annual distribution formula rate with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2016 after the ICC’s review and approval, which is due by December 2015. The revenue requirement requested is based on 2014 actual costs plus projected 2015 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2014 to the actual costs incurred that year. ComEd's 2015 filing request includes a total decrease to the revenue requirement of $50 million, reflecting an increase of $92 million for the initial revenue requirement for 2016 and an decrease of $142 million related to the annual reconciliation for 2014. The revenue requirement for 2016 provides for a weighted average debt and equity return on distribution rate base of 7.05% inclusive of an allowed return on common equity of 9.14%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2014 provided for a weighted average debt and equity return on distribution rate base of 7.02% inclusive of an allowed return on common equity of 9.09%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points.
	Participating utilities are also required to file an annual update on their AMI implementation progress. On June 11, 2014, the ICC approved ComEd's accelerated deployment plan which allows for the installation of more than four million smart meters throughout ComEd's service territory by 2018, three years in advance of the originally scheduled 2021 completion date. On April 1, 2015, ComEd filed an annual progress report on its AMI Implementation Plan with the ICC. To date, over one million smart meters have been installed in the Chicago area.
	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 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. On October 22, 2014, the ICC issued an order approving ComEd’s Grand Prairie Gateway Project over the objection of numerous landowners and the City of Elgin. On January 15, 2015, the City of Elgin and other parties filed a Notice of Appeal in the Illinois Appellate Court. On April 8, 2015, the ICC issued a rehearing order denying the appeals filed to consider an alternate route for the transmission line. The rehearing order affirmed the route approved within the ICC’s October 22, 2014 order. ComEd expects to begin construction of the line in the second quarter of 2015 with an in-service date expected in the second quarter of 2017.
	Pennsylvania Regulatory Matters
	2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO). On March 27, 2015, PECO filed a petition with the PAPUC requesting an increase of $190 million to its annual service revenues for electric delivery, which would reflect a 4.4% increase on the basis of total Pennsylvania jurisdictional operating revenue. The requested rate of return on common equity is 10.95%. The new electric delivery rates would take effect no later than January 1, 2016. The results of the rate case are expected to be known in the fourth quarter of 2015. PECO cannot predict how much of the requested increase the PAPUC will ultimately approve.
	Pennsylvania Procurement Proceedings (Exelon and PECO).    On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO’s second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129.  In the second DSP Program, PECO entered into contracts with PAPUC-approved bidders, including Generation, to procure electric supply for its default electric customers through five competitive procurements.
	In addition, the second DSP Program includes a number of retail market enhancements recommended by the PAPUC in its previously issued Retail Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income Customer Assistance Program (CAP) customers to purchase their generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan with the PAPUC. By Order entered on January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20, 2014, 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 March 11, 2015, the appeal was argued before the Commonwealth Court (the Court). PECO cannot implement CAP Shopping until the Court reaches a decision, which is expected in 2015.
	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. In March 2015, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential class and its small, medium, and large commercial classes commencing in June 2015. Charges incurred for electric supply procured through contracts with Generation are included in purchased power from affiliates on PECO’s Statement of Operations and Comprehensive Income.
	On March 12, 2015, PECO settled the CAP Design with the Office of Consumer Advocates (OCA) and Low Income Advocates, and filed the proposed plan with the PAPUC on March 20, 2015.  The program design changes the rate structure of PECO's CAP to make the bills more affordable to customers enrolled in the assistance program. The CAP discounts continue to be recovered through PECO’s universal service fund cost.  If the CAP Design proposed plan is approved by the PAPUC, PECO plans to implement the program changes in October 2016.
	Smart Meter and Smart Grid Investments (Exelon and PECO).    In April 2010, pursuant to Act 129 and the follow-on Implementation Order of 2009, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP). PECO is currently in the second phase of the SMPIP, under which PECO will deploy substantially all remaining smart meters, for a total of 1.7 million smart meters, on an accelerated basis by the second quarter of 2015. In total, PECO currently expects to spend up to $591 million, excluding the cost of the original meters, on its smart meter infrastructure and approximately $155 million on smart grid investments through final deployment of which $200 million was funded by SGIG. As of March 31, 2015, PECO has spent $568 million and $155 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received.
	For further information on the SGIG and Smart Meter and Smart Grid program, see Note 3—Regulatory Matters of the Exelon 2014 Form 10-K.
	Pennsylvania Act 11 of 2012 (Exelon and PECO). In February 2012, Act 11 was signed into law, which seeks to clarify the PAPUC’s authority to approve alternative ratemaking mechanisms, allowing for the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair, improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the PAPUC's implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure.
	On February 5, 2015, PECO filed a petition to modify its natural gas LTIIP with the PAPUC, which was originally approved by the PAPUC in May 2013.  If approved, the modification would allow PECO to further accelerate the replacement of existing gas mains and also included a plan for the relocation of meters from indoors to outside in accordance with recent PAPUC rulemaking. In addition, on March 20, 2015, PECO filed a petition with the PAPUC for approval of its gas DSIC mechanism for recovery of gas LTIIP expenditures.
	On March 27, 2015, PECO filed a petition with the PAPUC for approval of its proposed electric DSIC and LTIIP. In accordance with the LTIIP (System 2020 plan), PECO plans to spend $275 million over the next five years to modernize and storm-harden its electric distribution system, making it more weather resistant and less vulnerable to damage. If approved, the DSIC will allow PECO the opportunity to recover the costs, subject to certain criteria, incurred to repair, improve or replace its electric distribution property between rate cases.
	Maryland Regulatory Matters
	2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE).    On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, respectively. In addition to these requested rate increases, BGE’s application 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 in BGE’s 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. Rates became effective for services rendered on or after December 13, 2013. The MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. The ERI initiative surcharge became effective June 1, 2014. On November 3, 2014, BGE filed a surcharge update including a true-up of cost estimates included in the 2014 surcharge, along with its work plan and cost estimates for 2015, to be included in the 2015 surcharge. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE's 2014 annual report, 2015 work plan and the 2015 surcharge.
	In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in BGE's 2013 electric and gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22, 2014, challenging the MDPSC's approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a hearing was held on November 17, 2014. BGE cannot predict the outcome of this appeal. If the residential consumer advocate's appeal is successful, BGE could recover ERI expenditures through other regulatory mechanisms.
	Smart Meter and Smart Grid Investments (Exelon and BGE).    In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that included the planned installation of 2 million residential and commercial electric and gas smart meters at an expected total cost of $480 million of which $200 million was recovered through a grant from the DOE. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. As of March 31, 2015 and December 31, 2014, BGE recorded a regulatory asset of $143 million and $128 million, respectively, representing incremental costs, depreciation and amortization, and a debt return on fixed assets related to its AMI program. As part of the settlement in BGE's 2014 electric and gas distribution rate case, the cost of the retired non-AMI meters will be amortized over 10 years.
	The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to recover promptly reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law; which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates. Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation. On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a decision conditionally approving the first five years of BGE’s plan and surcharge. On March 26, 2014, the Maryland PSC approved as filed BGE’s proposed 2014 project list, tariff and associated surcharge amounts, with a surcharge that became effective April 1, 2014. On November 17, 2014, BGE filed a surcharge update including a true-up of cost estimates included in the 2014 surcharge, along with its 2015 project list and cost estimates to be included in the 2015 surcharge. The filing was approved with a revised surcharge effective January 1, 2015. At its December 17, 2014 weekly Administrative Meeting, the MDPSC approved BGE's 2015 project list and the proposed surcharge for 2015. As of March 31, 2015, BGE recorded a regulatory liability of $1 million, representing the difference between the surcharge revenues and program costs.
	In February 2014, the residential consumer advocate in Maryland filed an appeal with the Baltimore City Circuit Court to the decision issued by the MDPSC on BGE’s infrastructure replacement plan. On September 5, 2014, the Baltimore City Circuit Court affirmed the MDPSC decision on BGE's infrastructure replacement plan and associated surcharge. On October 10, 2014, the residential consumer advocate noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court. The Court of Special Appeals has issued a preliminary procedural schedule that sets oral argument in this matter for a date in the first two weeks of November 2015.
	New York Regulatory Matters
	Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). Ginna Nuclear Power Plant's (Ginna) prior period fixed-price PPA contract with Rochester Gas & Electric Company (RG&E) expired in June 2014. In light of the expiration of the agreement, Ginna advised the New York Public Service Commission (NYPSC) and ISO-NY that in absence of a reliability need, Ginna management would make a recommendation, subject to approval by the CENG board, that Ginna be retired as soon as practicable. A formal study conducted by the ISO-NY and RG&E concluded that the Ginna nuclear plant needs to remain in operation to maintain the reliability of the transmission grid in the Rochester region through 2018 when planned transmission system upgrades are expected to be completed. In November 2014, in response to a petition filed by Ginna, the NYPSC directed Ginna and RG&E to negotiate a Reliability Support Services Agreement (RSSA). On February 13, 2015, regulatory filings, including RSSA terms negotiated between Ginna and RG&E, to support the continued operation of Ginna for reliability purposes were made with the NYPSC and with FERC for their approval. Although the RSSA contract is still subject to regulatory approvals, on April 1, 2015, Ginna began delivering power and capacity into ISO-NY consistent with the provisions of the proposed RSSA contract. RG&E may terminate the RSSA contract upon providing 12-months' notice, which would require RG&E to make a specified termination payment to Ginna. The proposed RSSA contract extends through September 30, 2018. In the event that Ginna continues to operate beyond the RSSA term, Ginna would be required to make a specified refund payment to RG&E. The FERC issued an order on April 14, 2015, directing Ginna to make a compliance filing to ensure that the RSSA does not allow Ginna to receive revenues above its full cost-of-service and rejecting any extension of the RSSA beyond its initial term, rather requiring any extension be subject to the rules currently being developed by ISO-NY. The FERC order also set the RSSA for hearing and settlement procedures. Until final regulatory approvals are received, Generation will recognize revenue based on market prices for energy and capacity delivered by Ginna into ISO-NY. Upon receiving regulatory approvals, under the RSSA contract terms, Generation would record an adjustment to recognize revenue based on the final approved pricing contained in the contract as of the April 1, 2015 effective date. While the RSSA is expected to receive regulatory approvals and, therefore, permit Ginna to continue operating through the RSSA term, there is still a risk that, for economic reasons, including adjustments to the revenue Ginna would be entitled to under the RSSA, Ginna could be retired before the end of its operating license period. In absence of such an agreement and in the event the plant is retired before the current license term ends in 2029, Exelon's and Generation's results of operations could be adversely affected by increased depreciation rates, impairment charges, severance costs, and accelerated future decommissioning costs, among other items. However, it is not expected that such impacts would be material to Exelon's or Generation's results of operations.
	Federal Regulatory Matters
	Transmission Formula Rate (Exelon, ComEd and BGE).    ComEd’s and BGE’s transmission rates are each established based on a FERC-approved formula. ComEd and BGE are required to file an annual update to the FERC-approved formula on or before May 15, with the resulting rates effective on June 1 of the same year. The annual formula rate update is based on prior year actual costs and current year projected capital additions. The update also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year. ComEd and BGE record regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue requirement in effect and ComEd’s and BGE’s best estimate of the revenue requirement expected to be approved by the FERC for that year’s reconciliation. As of March 31, 2015 and December 31, 2014, ComEd had recorded a net regulatory asset associated with the transmission formula rate of $25 million and $21 million, respectively, and BGE recorded a net regulatory asset associated with the transmission formula rate of $2 million and $1 million at March 31, 2015 and December 31, 2014, respectively. The regulatory asset associated with the transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.
	On April 15, 2015, ComEd filed its annual transmission formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2015, subject to review by the FERC and other parties, which is due by October 2015. ComEd's 2015 filing request includes a total increase to the revenue requirement of $91 million, reflecting an increase of $73 million for the initial revenue requirement and an increase of $18 million related to the annual reconciliation. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.61%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.62% average debt and equity return previously authorized.
	As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%.
	In April 2015, BGE filed its annual transmission formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that will take effect in June 2015, subject to review by the FERC and other parties, which is due by October 2015. BGE's 2015 filing request includes a total increase to the revenue requirement of $10 million, reflecting an increase of $13 million for the initial revenue requirement and a decrease of $3 million related to the annual reconciliation. The revenue requirement provides for a weighted average debt and equity return on transmission rate base of 8.46%, inclusive of an allowed return on common equity of 11.30%, a decrease from the 8.53% average debt and equity return previously authorized.
	As part of the FERC-approved settlement of BGE’s 2005 transmission rate case in 2006, the rate of return on common equity for BGE’s electric transmission business for new transmission projects placed in service on and after January 1, 2006 is 11.30%, which is inclusive of a 50 basis point incentive for participating in PJM.
	FERC Transmission Complaint (Exelon and BGE).  On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and PHI companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% base rate of return on common equity (ROE) and a 50 basis point incentive for participating in PJM (the latter of which is conditioned upon crediting the first 50 basis points of any incentive ROE adders). The parties seek a reduction in the base return on equity to 8.7% and changes to the formula rate process. FERC docketed the matter and set April 3, 2013 as the deadline for interventions, protests and answers. Under FERC rules, the revenues subject to refund are limited to a fifteen month period and the earliest date from which the base ROE could be adjusted and refunds required is the date of the complaint. On March 19, 2013, BGE filed a motion to dismiss or sever the complaint.
	On August 21, 2014, FERC issued an order in the BGE and PHI companies' proceeding, which established hearing and settlement judge procedures for the complaint, and set a refund effective date of February 27, 2013. BGE, the PHI companies and the parties began settlement discussions under the guidance of a FERC administrative law judge on September 23, 2014. On November 24, 2014, the Settlement Judge informed FERC and the Chief Judge that the parties had reached an impasse and determined that a settlement was not possible. On November 26, 2014, the Chief Judge issued an order terminating the settlement proceeding, designating a presiding judge at the hearings and directing that an initial decision be issued by November 25, 2015.
	On December 8, 2014, various state agencies in Delaware, Maryland, New Jersey, and D.C. filed a second complaint against BGE regarding the base ROE of the transmission business seeking a reduction from 10.8% to 8.8%. The filing of the second complaint creates a second refund window. By order issued on February 9, 2015, FERC established a hearing on the second complaint with the complainants' requested refund effective date of December 8, 2014. On February 20, 2015, the Chief Judge issued an order consolidating the two complaint proceedings and established an Initial Decision issuance deadline of February 29, 2016. On March 2, 2015, the Presiding Administrative Law Judge issued an order establishing a procedural schedule for the consolidated proceedings that provides for the hearing to commence on October 20, 2015.
	Based on the current status of the complaint filings, BGE believes it is probable that BGE's base ROE rate will be adjusted, and that a refund to customers of transmission revenue for the two maximum fifteen month periods will be required. However, BGE is unable to estimate the most likely refund amount for either complaint at this time, and has therefore established a reserve, which is not material, representing the low end of a reasonably possible estimated range of loss. Additionally, management is unable to estimate the maximum exposure of a potential refund at this time, which may have a material impact on BGE's results of operations and cash flows. The estimated annual ongoing reduction in revenues if FERC approved the ROEs requested by the parties in their filings is approximately $11 million. If FERC were to order a reduction of BGE’s base ROE to 8.7% as sought in the first complaint (while retaining the 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment), the result of the first fifteen month refund window would be a refund to customers of approximately $13 million. If FERC were to order a reduction in BGE’s base ROE to 8.8% as sought in the second complaint (while retaining 50 basis points of any incentives that were credited to the base return on equity for certain new transmission investment) and the refund period extended for a full fifteen months, the result would be a refund to customers of approximately $14 million.
	PJM Transmission Rate Design and Operating Agreements (Exelon, ComEd, PECO and BGE).  PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO and BGE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order, FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to the U.S. Court of Appeals for the Seventh Circuit.
	In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand, FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the Cost Allocation Issue. The hearing only concerns new facilities approved by the PJM Board prior to February 1, 2013. As of March 31, 2015, settlement discussions are continuing.
	Because a new cost allocation had been adopted for projects approved by the PJM Board on or after February 1, 2013, this latest remand only involves the cost allocation for facilities 500 kV and above approved prior to that date. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd’s results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO’s 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO’s results of operations, cash flows or financial position. To the extent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE’s results of operations, cash flows or financial position.
	Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE). On May 23, 2014, the D.C. Circuit Court issued an opinion vacating the FERC Order No. 745 (D.C. Circuit Decision). Order No. 745 established uniform compensation levels for demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation resource and was cost-effective.
	In addition to invalidating the compensation structure established by Order No. 745, the D.C. Circuit Court, in broad language, explained that demand response is part of the retail market and FERC is restricted from regulating retail markets. The full implication of the D.C. Circuit Decision for both energy and capacity markets regulated by FERC is not yet known and will depend on how FERC and the RTOs and ISOs implement the decision. FERC and several other parties sought rehearing of the D.C. Circuit Decision, which was denied in September 2014. In addition, on September 22, 2014, FERC and another party sought to stay the issuance of the D.C. Circuit Court’s mandate so that FERC may appeal the decision to the U.S. Supreme Court. The stay was granted with respect to the FERC’s request only. In January 2015, the FERC sought to appeal the decision to the U.S. Supreme Court. Thus, the stay will be extended at least until the U.S. Supreme Court determines whether to allow the appeal. In addition, contemporaneously with the D.C. Circuit Court’s decision on May 23, 2014, First Energy filed a complaint at FERC asking FERC to direct PJM to remove all PJM Tariff provisions that allow or require PJM to compensate demand response providers as a form of supply in the PJM capacity market effective May 23, 2014. FirstEnergy also asked FERC to declare the results of PJM’s May 2014 Base Residual Auction for the 2017/2018 Delivery Year, void and illegal to the extent that demand response resources cleared that auction. On November 14, 2014, the New England Power Generators Association, Inc. (NEPGA) filed a similar complaint at FERC asking FERC to disqualify demand response from the upcoming capacity auction in New England and to revise the New England tariff to remove demand response from participation in the capacity market. FERC’s response to the FirstEnergy complaint and the NEPGA complaint and its response to address the D.C. Circuit Court’s decision in all markets could preclude demand response resources from receiving any future capacity market revenues and also subject such resources to refund obligations. In addition, there is uncertainty as to how FERC might treat already settled capacity market auctions as well as future auctions, both for demand response resources and generation resources. FERC could grant all or a portion of the relief requested by FirstEnergy and may grant relief retroactively or only prospectively. FERC could also pursue alternative means for allowing demand response to effectively participate in capacity markets it regulates. Due to these uncertainties, the Registrants are unable to predict the outcome of these proceedings, and the final outcome is not expected for several months. Nonetheless, the final decision and its implementation by FERC and the RTOs and ISOs, could be material to Exelon, Generation, ComEd, PECO and BGE’s results of operations and cash flows.
	New England Capacity Market Results (Exelon and Generation).  Each year, ISO New England, Inc. (ISO-NE) files the results of its annual capacity auction at the FERC which is required to include documentation regarding the competitiveness of the auction.  Consistent with this requirement, on February 27, 2015, ISO-NE filed the results of its ninth capacity auction (covering the June 1, 2018 through May 30, 2019 delivery period).
	On February 28, 2014, ISO-NE filed the results of its eighth capacity auction (covering the June 1, 2017 through May 30, 2018 delivery period).  On June 27, 2014, the FERC issued a letter to ISO-NE noting that ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing.  ISO-NE filed the information on July 17, 2014, and the ISO-NE's filings became effective by operation of law pursuant to a notice issued by the secretary of FERC on September 16, 2014. Several parties sought rehearing of the secretary’s notice which was effectively denied in October 2014 and have since appealed the matter to the D.C. Circuit Court. On April 7, 2015 the D.C. Circuit Court issued an order referring the matter to a merits panel where issues raised by parties challenging the FERC decision will be heard as well as FERC's Motion to Dismiss the challenges. It is not clear whether the court will decide ultimately on the merits of the case or whether it will dismiss the case as FERC urges based on the fact that there is no action by the FERC to be considered. Nonetheless, while any change in the auction results is thought to be unlikely, Exelon and Generation cannot predict with certainty what further action the court may take concerning the results of that auction, but any court action could be material to Exelon’s and Generation's expected revenues from the capacity auction.
	License Renewals (Exelon and Generation).    On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Project (Muddy Run), respectively.
	Generation is working with stakeholders to resolve water quality licensing issues with the MDE for Conowingo, including: (1) water quality, (2) fish passage and habitat, and (3) sediment. On January 30, 2014, Generation filed a water quality certification application pursuant to Section 401 of the CWA with MDE for Conowingo, addressing these and other issues, although Generation cannot currently predict the conditions that ultimately may be imposed. MDE indicated that it believed it did not have sufficient information to process Generation's application. As a result, on December 5, 2014, Generation withdrew its pending application for a water quality certification. FERC policy requires that an applicant resubmit its request for a water quality certification within 90 days of the date of withdrawal. Accordingly, on March 3, 2015, Generation refiled its application for a water quality certification. In addition, Generation has 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. Resolution of these issues relating to Conowingo may have a material effect on Exelon's and Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.
	On June 3, 2014, and subsequently modified December 9, 2014, the PA DEP issued its water quality certificate for Muddy Run, which is a necessary step in the FERC licensing process and included certain commitments made by Generation. On March 2, 2015, Generation and US Fish and Wildlife Services (USFWS) submitted to FERC an executed settlement agreement resolving all outstanding issues related to Muddy Run. The financial impact associated with these commitments is estimated to be in the range of $25 million to $35 million, and will include both capital expenditures and operating expenses, primarily relating to fish passage and habitat improvement projects.
	The FERC licenses for Muddy Run and Conowingo expired on August 31, 2014 and September 1, 2014 respectively. Under the Federal Power Act, FERC is required to issue annual licenses for the facilities until the new licenses are issued.  On September 10, 2014, FERC issued annual licenses for Conowingo and Muddy Run, effective as of the expiration of the previous licenses. If FERC does not issue new licenses prior to the expiration of annual licenses, the annual licenses will renew automatically. On March 11, 2015, FERC issued the final Environmental Impact Statement for Muddy Run and Conowingo.
	The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of March 31, 2015, $40 million of direct costs associated with licensing efforts have been capitalized
	Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)
	Exelon, ComEd, PECO and BGE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
	The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of March 31, 2015 and December 31, 2014. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K.
	31-Mar-15		Exelon			ComEd			PECO			BGE
	Regulatory assets
	Pension and other postretirement benefits		$	3,248		$	—		$	—		$	—
	Deferred income taxes		1,561			65			1,419			77
	AMI programs		325			106			76			143
	Under-recovered distribution service costs(a)		316			316			—			—
	Debt costs		54			51			3			8
	Fair value of BGE long-term debt		184			—			—			—
	Severance		11			—			—			11
	Asset retirement obligations		119			75			26			18
MGP remediation costs		250			213			36			1
Under-recovered uncollectible accounts		62			62			—			—
Renewable energy		241			241			—			—
Energy and transmission programs(b) (c)		41			37			—			4
Deferred storm costs		3			—			—			3
Electric generation-related regulatory asset		28			—			—			28
Rate stabilization deferral		136			—			—			136
Energy efficiency and demand response programs		230			—			—			230
Merger integration costs		8			—			—			8
Conservation voltage reduction		2			—			—			2
Other		53			17			24			9
Total regulatory assets		6,872			1,183			1,584			678
Less: current portion		804			317			41			187
Total noncurrent regulatory assets		$	6,068		$	866		$	1,543		$	491
31-Mar-15		Exelon			ComEd			PECO			BGE
Regulatory liabilities
Other postretirement benefits		$	72		$	—		$	—		$	—
Nuclear decommissioning		2,920			2,420			500			—
Removal costs		1,567			1,351			—			216
Energy efficiency and demand response programs		27			25			2			—
DLC Program Costs		10			—			10			—
Energy efficiency Phase 2		38			—			38			—
Electric distribution tax repairs		106			—			106			—
Gas distribution tax repairs		34			—			34			—
Energy and transmission programs(b)(c)(d)		142			23			84			35
Over-recovered electric universal service fund costs		3			—			3			—
Revenue subject to refund		3			3			—			—
Over-recovered revenue decoupling(e)		56			—			—			56
Other		9			1			4			4
Total regulatory liabilities		4,987			3,823			781			311
Less: current portion		421			131			119			124
Total noncurrent regulatory liabilities		$	4,566		$	3,692		$	662		$	187
31-Dec-14		Exelon			ComEd			PECO			BGE
Regulatory assets
Pension and other postretirement benefits		$	3,256		$	—		$	—		$	—
Deferred income taxes		1,542			64			1,400			78
AMI programs		296			91			77			128
Under-recovered distribution service costs(a)		371			371			—			—
Debt costs		57			53			4			9
Fair value of BGE long-term debt		190			—			—			—
Severance		12			—			—			12
Asset retirement obligations		116			74			26			16
MGP remediation costs		257			219			37			1
Under-recovered uncollectible accounts		67			67			—			—
Renewable energy		207			207			—			—
Energy and transmission programs(b)(c)		48			33			—			15
Deferred storm costs		3			—			—			3
Electric generation-related regulatory asset		30			—			—			30
Rate stabilization deferral		160			—			—			160
Energy efficiency and demand response programs		248			—			—			248
Merger integration costs		8			—			—			8
Conservation voltage reduction		2			—			—			2
Under recovered electric revenue decoupling		7			—			—			7
Other		46			22			14			7
Total regulatory assets		6,923			1,201			1,558			724
Less: current portion		847			349			29			214
Total noncurrent regulatory assets		$	6,076		$	852		$	1,529		$	510
31-Dec-14		Exelon			ComEd			PECO			BGE
Regulatory liabilities
Other postretirement benefits		$	88		$	—		$	—		$	—
Nuclear decommissioning		2,879			2,389			490			—
Removal costs		1,566			1,343			—			223
Energy efficiency and demand response programs		27			25			2			—
DLC Program Costs		10			—			10			—
Energy efficiency phase II		32			—			32			—
Electric distribution tax repairs		102			—			102			—
Gas distribution tax repairs		49			—			49			—
Energy and transmission programs(b)(c)(d)		84			19			58			7
Over-recovered electric universal service fund costs		2			—			2			—
Revenue subject to refund		3			3			—			—
Over-recovered revenue decoupling(e)		12			—			—			12
Other		6			1			2			2
Total regulatory liabilities		4,860			3,780			747			244
Less: current portion		310			125			90			44
Total noncurrent regulatory liabilities		$	4,550		$	3,655		$	657		$	200
________________
(a)	As of March 31, 2015, ComEd’s regulatory asset of $316 million was comprised of $240 million for the applicable annual reconciliations and $76 million related to significant one-time events including $59 million of deferred storm costs and $17 million of Constellation merger and integration related costs.  As of December 31, 2014, ComEd’s regulatory asset of $371 million was comprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events, including $66 million of deferred storm costs and $19 million of Constellation merger and integration related costs. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for further information.
(b)	As of March 31, 2015, ComEd’s regulatory asset of $37 million included $5 million related to under-recovered energy costs for non-hourly customers, $25 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, 2015, ComEd’s regulatory liability of $23 million included $5 million related to over-recovered energy costs for hourly customers and $18 million associated with revenues received for renewable energy requirements. As of December 31, 2014, ComEd’s regulatory asset of $33 million included $4 million related to under-recovered energy costs for non-hourly customers, $22 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, 2014, ComEd’s regulatory liability of $19 million included $3 million related to over-recovered energy costs for hourly customers and $16 million associated with revenues received for renewable energy requirements.
(c)	As of March 31, 2015, BGE's regulatory asset of $4 million included $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval, partially offset by $1 million related to over-recovered electric energy costs. As of March 31, 2015, BGE's regulatory liability of $35 million related to $31 million of over-recovered natural gas supply costs and $4 million of over-recovered electric energy costs. As of December 31, 2014, BGE's regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE's regulatory liability of $7 million related to over-recovered natural gas supply costs.
(d)	At PECO, includes $42 million related to the DSP program, $34 million related to the over-recovered natural gas costs under the PGC and $8 million related to over-recovered electric transmission costs as of March 31, 2015. As of December 31, 2014, includes $39 million related to the DSP program, $16 million related to the over-recovered electric transmission costs and $3 million related to the over-recovered natural gas costs under the PGC.
(e)	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2015, BGE had a regulatory liability of $19 million related to over-recovered electric revenue decoupling and a regulatory liability of $37 million related to over-recovered natural gas revenue decoupling. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling.
Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE)
ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities’ consolidated billing. ComEd and BGE purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through its distribution rates. Exelon, ComEd, PECO and BGE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of March 31, 2015 and December 31, 2014.
As of March 31, 2015	Exelon			ComEd			PECO			BGE
Purchased receivables(a)	$	336		$	150		$	91		$	95
Allowance for uncollectible accounts(b)	(51		)	(25		)	(10		)	(16		)
Purchased receivables, net	$	285		$	125		$	81		$	79
As of December 31, 2014	Exelon			ComEd			PECO			BGE
Purchased receivables(a)	$	290		$	139		$	76		$	75
Allowance for uncollectible accounts(b)	(42		)	(21		)	(8		)	(13		)
Purchased receivables, net	$	248		$	118		$	68		$	62
_________
(a)	PECO’s gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.
(b)	For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

Investment_in_Constellation_En

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)	3 Months Ended
	Mar. 31, 2015
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)
	As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements, see Note 25 — Related Party Transactions of the Exelon 2014 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 25 — Related Party Transactions of the Exelon 2014 Form 10-K, EDF and Generation had a PPA with CENG under which they purchased 15% and 85% (through December 31, 2014), respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs. Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation will purchase 49.99% and 50.01%, respectively, of the nuclear output owned by CENG not subject to other contractual agreements. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For the three months ended March 31, 2015, Generation had sales to EDF of $182 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
	For the three months ended 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 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, 2015, Generation reduced by $4 million 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 $197 million and CENG’s net income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $98 million during the three months ended March 31, 2015.

Fair_Value_of_Financial_Assets

Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)	Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)
	Fair Value of Financial Liabilities Recorded at the Carrying Amount
	The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 2015 and December 31, 2014:
	Exelon
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	312			$	3			$	309			$	—			$	312
	Long-term debt (including amounts due within one year)	21,779				1,119				21,486				1,380				23,985
	Long-term debt to financing trusts	648				—				—				672				672
	SNF obligation	1,021				—				843				—				843
		31-Dec-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	463			$	3			$	448			$	12			$	463
	Long-term debt (including amounts due within one year)	21,164				1,208				20,417				1,311				22,936
	Long-term debt to financing trusts	648				—				—				648				648
	SNF obligation	1,021				—				833				—				833
	Generation
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	25			$	—			$	25			$	—			$	25
	Long-term debt (including amounts due within one year)	8,492				—				7,885				1,380				9,265
	SNF obligation	1,021				—				843				—				843
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	36			$	—			$	24			$	12			$	36
	Long-term debt (including amounts due within one year)	8,266				—				7,511				1,311				8,822
	SNF obligation	1,021				—				833				—				833
	ComEd
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	283			$	—			$	283			$	—			$	283
	Long-term debt (including amounts due within one year)	6,359				—				7,347				—				7,347
	Long-term debt to financing trust	206				—				—				206				206
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	304			$	—			$	304			$	—			$	304
	Long-term debt (including amounts due within one year)	5,958				—				6,788				—				6,788
	Long-term debt to financing trust	206				—				—				213				213
	PECO
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Long-term debt (including amounts due within one year)	$	2,246			$	—			$	2,602			$	—			$	2,602
	Long-term debt to financing trusts	184				—				—				201				201
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Long-term debt (including amounts due within one year)	$	2,246			$	—			$	2,537			$	—			$	2,537
	Long-term debt to financing trusts	184				—				—				199				199
	BGE
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	3			$	3			$	—			$	—			$	3
	Long-term debt (including amounts due within one year)	1,942				—				2,234				—				2,234
	Long-term debt to financing trusts	258				—				—				265				265
		December 31, 2014
		Carrying				Fair Value
	Amount			Level 1				Level 2				Level 3				Total
Short-term liabilities	$	123			$	3			$	120			$	—			$	123
Long-term debt (including amounts due within one year)	1,942				—				2,178				—				2,178
Long-term debt to financing trusts	258				—				—				236				236
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in other current liabilities) (Level 1), short-term borrowings (Level 2) and third party financing (Level 3). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term nature of these instruments.
Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) are determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of existing Exelon debt securities as well as debt securities of other issuers in the electric utility sector with similar credit ratings in both the primary and secondary market, across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S. Treasury rates in order to determine the current market yields for the various tenors. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note. The fair value of Exelon's equity units (Level 1) are valued based on publicly traded securities issued by Exelon.
The fair value of Generation’s non-government-backed fixed rate project financing debt, including nuclear fuel procurement contracts, (Level 3) is based on market and quoted prices for its own and other project financing debt with similar risk profiles. Given the low trading volume in the project financing debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described above.  Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable Treasury rate as well as a current market curve derived from government-backed securities.  Variable rate project financing debt resets on a quarterly basis and the carrying value approximates fair value (Level 2).
SNF Obligation. The carrying amount of Generation’s SNF obligation (Level 2) is derived from a contract with the DOE to provide for disposal of SNF from Generation’s nuclear generating stations. When determining the fair value of the obligation, the future carrying amount of the SNF obligation estimated to be settled in 2025 is calculated by compounding the current book value of the SNF obligation at the 13-week Treasury rate. The compounded obligation amount is discounted back to present value using Generation’s discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2025.
Long-Term Debt to Financing Trusts. Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts. Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt is classified as Level 3.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•	Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to access as of the reporting date.
•	Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•	Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.
Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material. Transfers into Level 2 from Level 3 generally occur when the contract tenure becomes more observable. Transfers into Level 3 from Level 2 generally occur due to changes in market liquidity or assumptions for certain commodity contracts. There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2015 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.
Exelon and Generation
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, 2015 and December 31, 2014:
		Generation																Exelon
As of March 31, 2015		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
Assets
Cash equivalents(a)		$	220			$	—			$	—			$	220			$	1,107				$	—				$	—				$	1,107
Nuclear decommissioning trust fund investments
Cash equivalents		224				40				—				264				224					40					—					264
Equity
Domestic		2,459				2,227				—				4,686				2,459					2,227					—					4,686
Foreign		639				—				—				639				639					—					—					639
Equity funds subtotal		3,098				2,227				—				5,325				3,098					2,227					—					5,325
Fixed income
Corporate debt		—				1,911				248				2,159				—					1,911					248					2,159
U.S. Treasury and agencies		1,201				—				—				1,201				1,201					—					—					1,201
Foreign governments		—				89				—				89				—					89					—					89
State and municipal debt		—				423				—				423				—					423					—					423
Other		—				488				—				488				—			—		488			—		—			—		488
Fixed income subtotal		1,201				2,911				248				4,360				1,201					2,911					248					4,360
Middle market lending		—				—				363				363				—					—					363					363
Private Equity		—				—				95				95				—					—					95					95
Real Estate		—				—				9				9				—			—		—			—		9					9
Other		—				323				—				323				—					323					—					323
Nuclear decommissioning trust fund investments subtotal(b)		4,523				5,501				715				10,739				4,523					5,501					715					10,739
		Generation																Exelon
As of March 31, 2015		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
Pledged assets for Zion Station decommissioning
Cash equivalents		—				19				—				19				—					19					—					19
Equities		6				1				—				7				6					1					—					7
Fixed income
U.S. Treasury and agencies		2				3				—				5				2					3					—					5
Corporate debt		—				84				—				84				—					84					—					84
State and municipal debt		—				10				—				10				—					10					—					10
Other		—				4				—				4				—			—		4			—		—					4
Fixed income subtotal		2				101				—				103				2					101					—					103
Middle market lending		—				—				178				178				—					—					178					178
Pledged assets for Zion Station		8				121				178				307				8					121					178					307
decommissioning subtotal(c)
Rabbi trust investments in mutual funds(d)(e)		16				—				—				16				48					—					—					48
Commodity derivative assets
Economic hedges		1,510				3,554				1,917				6,981				1,510					3,554					1,917					6,981
Proprietary trading		176				286				39				501				176					286					39					501
Effect of netting and allocation of collateral(f)		(1,899		)		(2,849		)		(740		)		(5,488		)		(1,899		)			(2,849		)			(740		)			(5,488		)
Commodity derivative assets subtotal		(213		)		991				1,216				1,994				(213		)			991					1,216					1,994
Interest rate and foreign currency derivative
assets
Derivatives designated as hedging instruments		—				—				—				—				—					32					—					32
Economic hedges		—				27				—				27				—					29					—					29
Proprietary trading		18				1				—				19				18					1					—					19
Effect of netting and allocation of collateral		(8		)		(5		)		—				(13		)		(8		)			(36		)			—					(44		)
Interest rate and foreign currency derivative		10				23				—				33				10					26					—					36
assets subtotal
Other investments		—				—				3				3				2					—					3					5
Total assets		4,564				6,636				2,112				13,312				5,485					6,639					2,112					14,236
Liabilities
Commodity derivative liabilities
Economic hedges		(2,126		)		(3,370		)		(1,025		)		(6,521		)		(2,126		)			(3,370		)			(1,266		)			(6,762		)
Proprietary trading		(169		)		(295		)		(50		)		(514		)		(169		)			(295		)			(50		)			(514		)
Effect of netting and allocation of collateral(f)		2,324				3,585				925				6,834				2,324					3,585					925					6,834
Commodity derivative liabilities subtotal		29				(80		)		(150		)		(201		)		29					(80		)			(391		)			(442		)
Interest rate and foreign currency derivative
liabilities
Derivatives designated as hedging instruments		—				(17		)		—				(17		)		—					(17		)			—					(17		)
Economic hedges		—				(6		)		—				(6		)		—					(186		)			—					(186		)
Proprietary trading		(1		)		(14		)		—				(15		)		(1		)			(14		)			—					(15		)
Effect of netting and allocation of collateral		15				6				—				21				15					37					—					52
Interest rate and foreign currency derivative		14				(31		)		—				(17		)		14					(180		)			—					(166		)
liabilities subtotal
Deferred compensation obligation		—				(30		)		—				(30		)		—					(103		)			—					(103		)
Total liabilities		43				(141		)		(150		)		(248		)		43					(363		)			(391		)			(711		)
Total net assets		$	4,607			$	6,495			$	1,962			$	13,064			$	5,528				$	6,276				$	1,721				$	13,525
		Generation																Exelon
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3				Total
Assets
Cash equivalents(a)		$	405			$	—			$	—			$	405			$	1,119				$	—				$	—			$	1,119
Nuclear decommissioning trust fund investments
Cash equivalents		208				37				—				245				208					37					—				245
		Generation																Exelon
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3				Total
Equity
Domestic		2,423				2,207				—				4,630				2,423					2,207					—				4,630
Foreign		612				—				—				612				612					—					—				612
Equity funds subtotal		3,035				2,207				—				5,242				3,035					2,207					—				5,242
Fixed income
Corporate debt		—				2,023				239				2,262				—					2,023					239				2,262
U.S. Treasury and agencies		996				—				—				996				996					—					—				996
Foreign governments		—				95				—				95				—					95					—				95
State and municipal debt		—				438				—				438				—					438					—				438
Other		—				511				—				511				—			—		511			—		—				511
Fixed income subtotal		996				3,067				239				4,302				996					3,067					239				4,302
Middle market lending		—				—				366				366				—					—					366				366
Private Equity		—				—				83				83				—					—					83				83
Real Estate		—				—				3				3				—			—		—			—		3				3
Other		—				301				—				301				—					301					—				301
Nuclear decommissioning trust fund investments subtotal(b)		4,239				5,612				691				10,542				4,239					5,612					691				10,542
Pledged assets for Zion Station
decommissioning
Cash equivalents		—				15				—				15				—					15					—				15
Equities		6				1				—				7				6					1					—				7
Fixed income
U.S. Treasury and agencies		5				3				—				8				5					3					—				8
Corporate debt		—				89				—				89				—					89					—				89
State and municipal debt		—				10				—				10				—					10					—				10
Other		—				3				—				3				—			—		3			—		—				3
Fixed income subtotal		5				105				—				110				5					105					—				110
Middle market lending		—				—				184				184				—					—					184				184
Pledged assets for Zion Station		11				121				184				316				11					121					184				316
decommissioning subtotal(c)
Rabbi trust investments(d)
Cash equivalents		—				—				—				—				1					—					—				1
Mutual funds(e)		16				—				—				16				46					—					—				46
Rabbi trust investments subtotal		16				—				—				16				47					—					—				47
Commodity derivative assets
Economic hedges		1,667				3,465				1,681				6,813				1,667					3,465					1,681				6,813
Proprietary trading		201				284				27				512				201					284					27				512
Effect of netting and allocation of collateral(f)		(1,982		)		(2,757		)		(557		)		(5,296		)		(1,982		)			(2,757		)			(557		)		(5,296		)
Commodity derivative assets subtotal		(114		)		992				1,151				2,029				(114		)			992					1,151				2,029
Interest rate and foreign currency derivative
assets
Derivatives designated as hedging instruments		—				8				—				8				—					31					—				31
Economic hedges		—				12				—				12				—					13					—				13
Proprietary trading		18				9				—				27				18					9					—				27
Effect of netting and allocation of collateral		(17		)		(12		)		—				(29		)		(17		)			(31		)			—				(48		)
Interest rate and foreign currency derivative		1				17				—				18				1					22					—				23
assets subtotal
Other investments		—				—				3				3				2					—					3				5
Total assets		4,558				6,742				2,029				13,329				5,305					6,747					2,029				14,081
		Generation																Exelon
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3				Total
Liabilities
Commodity derivative liabilities
Economic hedges		(2,241		)		(3,458		)		(788		)		(6,487		)		(2,241		)			(3,458		)			(995		)		(6,694		)
Proprietary trading		(195		)		(295		)		(42		)		(532		)		(195		)			(295		)			(42		)		(532		)
Effect of netting and allocation of collateral(f)		2,416				3,557				729				6,702				2,416					3,557					729				6,702
Commodity derivative liabilities subtotal		(20		)		(196		)		(101		)		(317		)		(20		)			(196		)			(308		)		(524		)
Interest rate and foreign currency derivative
liabilities
Derivatives designated as hedging instruments		—				(12		)		—				(12		)		—					(41		)			—				(41		)
Economic hedges		—				(2		)		—				(2		)		—					(103		)			—				(103		)
Proprietary trading		(14		)		(9		)		—				(23		)		(14		)			(9		)			—				(23		)
Effect of netting and allocation of collateral		25				10				—				35				25					29					—				54
Interest rate and foreign currency derivative		11				(13		)		—				(2		)		11					(124		)			—				(113		)
liabilities subtotal
Deferred compensation obligation		—				(31		)		—				(31		)		—					(107		)			—				(107		)
Total liabilities		(9		)		(240		)		(101		)		(350		)		(9		)			(427		)			(308		)		(744		)
Total net assets		$	4,549			$	6,502			$	1,928			$	12,979			$	5,296				$	6,320				$	1,721			$	13,337
______________
(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
(b)	Excludes net (liabilities) of $(27) million and $(5) million at March 31, 2015 and December 31, 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(c)	Excludes net assets of $1 million and $3 million at March 31, 2015 and December 31, 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(d)	Excludes $36 million and $35 million of cash surrender value of life insurance investment at March 31, 2015 and December 31, 2014, respectively, at Exelon Consolidated. Excludes $12 million and $11 million and of cash surrender value of life insurance investment at March 31, 2015 and December 31, 2014, respectively, at Generation.
(e)	The mutual funds held by the Rabbi trusts at Exelon include $47 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at March 31, 2015, and $45 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2014.
(f)	Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $425 million, $736 million and $185 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2015. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014.
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value on the utility Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2015 and December 31, 2014:
		ComEd																PECO																BGE
As of March 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		$	67			$	—			$	—			$	67			$	5			$	—			$	—			$	5			$	75	$	—		$	—	$	75
Rabbi trust investments in mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		5
Total assets		67				—				—				67				14				—				—				14				80		—			—		80
Liabilities
Deferred compensation		—				(8		)		—				(8		)		—				(14		)		—				(14		)		—		(4		)	—		(4		)
obligation
Mark-to-market derivative		—				—				(241		)		(241		)		—				—				—				—				—		—			—		—
liabilities (b)
Total liabilities		—				(8		)		(241		)		(249		)		—				(14		)		—				(14		)		—		(4		)	—		(4		)
Total net assets (liabilities)		$	67			$	(8	)		$	(241	)		$	(182	)		$	14			$	(14	)		$	—			$	—			$	80	$	(4	)	$	—	$	76
		ComEd																PECO																BGE
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total				Level 1		Level 2			Level 3		Total
Assets
Cash equivalents		$	25			$	—			$	—			$	25			$	12			$	—			$	—			$	12			$	103	$	—		$	—	$	103
Rabbi trust investments in mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		$	5
Total assets		25				—				—				25				21				—				—				21				108		—			—		108
Liabilities
Deferred compensation obligation		—				(8		)		—				(8		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Mark-to-market derivative liabilities (b)		—				—				(207		)		(207		)		—				—				—				—				—		—			—		—
Total liabilities		—				(8		)		(207		)		(215		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Total net assets (liabilities)		$	25			$	(8	)		$	(207	)		$	(190	)		$	21			$	(15	)		$	—			$	6			$	108	$	(5	)	$	—	$	103
______________
(a)	At PECO, excludes $14 million of the cash surrender value of life insurance investments at both March 31, 2015 and December 31, 2014.
(b)	The Level 3 balance includes the current and noncurrent liability of $20 million and $221 million at March 31, 2015, respectively, and $20 million and $187 million at December 31, 2014, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three months ended March 31, 2015 and 2014:
		Generation																				ComEd								Exelon
Three Months Ended March 31, 2015		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Eliminated in Consolidation				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of December 31, 2014		$	691			$	184			$	1,050			$	3			$	1,928			$	(207	)		$	—			$	1,721
Total realized / unrealized gains (losses)
Included in net income		2				—				(32		)	(a)	—				(30		)		—				—				(30		)
Included in noncurrent payables to affiliates		8				—				—				—				8				—				(8		)		—
Included in payable for Zion Station decommissioning		—				3				—				—				3				—				—				3
Included in regulatory assets		—				—				—				—				—				(34		)		8				(26		)
Change in collateral		—				—				12				—				12				—				—				12
Purchases, sales, issuances and settlements																										—
Purchases		47				5				41				—				93				—				—				93
Sales		(8		)		(14		)		—				—				(22		)		—				—				(22		)
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		$	715			$	178			$	1,066			$	3			$	1,962			$	(241	)		$	—			$	1,721
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended March 31, 2015		$	1			$	—			$	180			$	—			$	181			$	—			$	—			$	181
		Generation																					ComEd								Exelon
Three Months Ended March 31, 2014		Nuclear					Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Eliminated in Consolidation				Total
		Decommissioning					for Zion Station				Derivatives				Investments
		Trust Fund					Decommissioning
		Investments
Balance as of December 31, 2013		$	350				$	112			$	465			$	15			$	942			$	(193	)		$	—			$	749
Total realized / unrealized gains (losses)
Included in net income		1					—				(312		)	(a)	—				(311		)		—				—				(311		)
Included in noncurrent payables to affiliates		3					—				—				—				3				—				(3		)		—
Included in payable for Zion Station decommissioning		—					(1		)		—				—				(1		)		—				—				(1		)
Included in regulatory assets		—					—								—				—				25				3				28
Change in collateral		—			—		—				144				—				144				—				—				144
Purchases, sales, issuances and settlements
Purchases		139					30				10				2				181				—				—				181
Sales		(1		)			(4		)		(2		)		—				(7		)		—				—				(7		)
Settlements		(6		)			—				—				—				(6		)		—				—				(6		)
Transfers into Level 3		—					—				(26		)		—				(26		)		—				—				(26		)
Transfers out of Level 3		—					—				8				(7		)		1				—				—				1
Balance as of March 31, 2014		$	486				$	137			$	287			$	10			$	920			$	(168	)		$	—			$	752
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended March 31, 2014		$	—				$	—			$	(446	)		$	—			$	(446	)		$	—			$	—			$	(446	)
______________
(a) Includes the reclassification of $212 million and $(134) million of realized gains (losses) due to the settlement of derivative contracts for the three months ended March 31, 2015 and 2014, respectively.
(b) Includes $36 million of decreases in fair value and realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2015. Includes $30 million of increases in fair value and realized gains due to settlements of $5 million for the three months ended March 31, 2014.
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, 2015 and 2014:
		Generation									Exelon
		Operating			Purchased			Other, net(a)			Operating			Purchased			Other, net(a)
		Revenues			Power and						Revenues			Power and
					Fuel									Fuel
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
	Generation												Exelon
	Operating				Purchased				Other, net(a)				Operating				Purchased				Other, net(a)
	Revenues				Power and								Revenues				Power and
					Fuel												Fuel
Total gains (losses) included in net income for the three months ended March 31, 2014	$	(268	)		$	(44	)		$	1			$	(268	)		$	(44	)		$	1
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2014	(425		)		(21		)		—				(425		)		(21		)		—
______________
(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE). The Registrants’ cash equivalents include investments with maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the fair value hierarchy.
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).    The trust fund investments have been established to satisfy Generation’s and CENG's nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in Equities, Fixed Income and Other. Generation’s and CENG's investment policies place limitations on the types and investment grade ratings of the securities that may be held by the trusts. These policies limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
With respect to individually held equity securities, which are included in Domestic or Foreign equities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds are based on quoted prices in active markets and are categorized in Level 1. Equity securities held individually are primarily traded on the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Generation has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1 because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury securities, are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The fair values of private placement fixed income securities, 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 fixed income mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives. The fair values of fixed income commingled and mutual funds held within the trust funds, which generally hold short-term fixed income securities and are not subject to restrictions regarding the purchase or sale of shares, are derived from observable prices. The objectives of the remaining equity commingled funds in which Exelon, Generation, and CENG invest primarily seek to track the performance of certain equity indices by purchasing equity securities to replicate the capitalization and characteristics of the indices. Commingled and mutual funds are categorized in Level 2 because the fair value of the funds are based on NAVs per fund share (the unit of account), primarily derived from the quoted prices in active markets on the underlying equity securities.
Middle market lending are investments in loans or managed funds which invest in private companies. Generation elected the fair value option for its investments in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation models including cost models, market models, and income models. Investments in middle market lending are categorized as Level 3 because the fair value of these securities is based largely on inputs that are unobservable and utilize complex valuation models. Investments in middle market lending typically cannot be redeemed until maturity of the term loan.
Private equity investments include investments in operating companies that are not publicly traded on a stock exchange. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highly observable, private equity investments have been categorized as Level 3.
As of March 31, 2015, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $265 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.
See Note 12—Nuclear Decommissioning for further discussion on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, ComEd, PECO and BGE).  The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of mutual funds and life insurance policies. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. Mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, which is provided by a third party. The cash surrender value inputs are not observable.
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps and options, model inputs are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominately at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.
Exelon may utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. These interest rate derivatives are typically designated as cash flow hedges. Exelon determines the current fair value by calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy. See Note 8 - Derivative Financial Instruments for further discussion on mark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE).    The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd)
Mark-to-Market Derivatives (Exelon, Generation, ComEd). For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief risk officer and includes the chief financial officer, corporate controller, general counsel, treasurer, vice president of strategy, vice president of audit services and officers representing Exelon’s business units. The RMC reports to the Exelon Board of Directors on the scope of the risk management activities and is responsible for approving all valuation procedures at Exelon. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data in its assessment of credit and nonperformance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas, coal purchases, certain transmission congestion contracts, and project financing debt. Generation utilizes various inputs and factors including market data and assumptions that market participants would use in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of observability of a forward commodity price 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 $3.15 and $0.31 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities.
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 8 —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, 2015				Valuation		Unobservable		Range
						Technique		Input
Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	892			Discounted		Forward power		$17	-	$121	(d)
						Cash Flow		price
								Forward gas		$1.68	-	$13.69	(d)
								price
						Option Model		Volatility		8%	-	172%
								percentage
Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	(11	)		Discounted		Forward power		$17	-	$95	(d)
						Cash Flow		price
Mark-to-market derivatives (ComEd)		$	(241	)		Discounted		Forward heat		8x	-	9x
						Cash Flow		rate(b)
								Marketability		3.50%	-	8%
								reserve
								Renewable		86%	-	126%
								factor
______________
(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 $185 million as of March 31, 2015.
(d)	The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas economic hedges would be approximately $107 and $8.19, respectively, and would be approximately $55 for power proprietary trading.
Type of trade		Fair Value at December 31, 2014				Valuation		Unobservable		Range
						Technique		Input
Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	893			Discounted		Forward power		$15	-	$120	(d)
						Cash Flow		price
								Forward gas		$1.52	-	$14.02	(d)
								price
						Option Model		Volatility		8%	-	257%
								percentage
Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	(15	)		Discounted		Forward power		$15	-	$117	(d)
						Cash Flow		price
Mark-to-market derivatives (ComEd)		$	(207	)		Discounted		Forward heat		8x	-	9x
						Cash Flow		rate(b)
								Marketability		3.50%	-	8%
								reserve
								Renewable		86%	-	126%
								factor
______________
(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 $172 million as of December 31, 2014.
(d)	The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading.
The inputs listed above would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.
Nuclear Decommissioning Trust Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation).    For middle market lending, certain corporate debt securities, and private equity investments, the fair value is determined using a combination of valuation models including cost models, market models and income models. The valuation estimates are based on valuations of comparable companies, discounting the forecasted cash flows of the portfolio company, estimating the liquidation or collateral value of the portfolio company or its assets, considering offers from third parties to buy the portfolio company, its historical and projected financial results, as well as other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied to the prices of comparable companies for factors such as size, marketability, credit risk and relative performance.
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3 investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Generation gains an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the reasonableness of the valuations. For a sample of its Level 3 investments, Generation reviewed independent valuations and reviewed the assumptions in the detailed pricing models used by the fund managers.

Derivative_Financial_Instrumen

Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments (Exelon, Generation, ComEd, PECO and BGE)	Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations.
	Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)
	To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options and short-term and long-term commitments to purchase and sell energy and energy-related products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to fluctuations in commodity prices.
	Derivative accounting guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings each period. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal sale (NPNS), cash flow hedge, and fair value hedge. For commodity transactions, Generation no longer utilizes the special election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivative economic hedges related to commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 22 — Commitments and Contingencies of the Exelon 2014 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, 2015, the proportion of expected generation hedged is for the major reportable segments was 94%-97%, 67%-70%, and 37%-40% for 2015, 2016, and 2017, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to ComEd, PECO and BGE to serve their retail load.
	On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reductions was approved in March 2014. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information.
	PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.
	PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2014 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 2014 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
	BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes.  BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
	BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.
	Proprietary Trading.    Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 1,808 GWhs and 2,494 GWhs for the three months ended March 31, 2015 and 2014, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes.
	Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants 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, 2015, Exelon had $900 million of notional amounts of fixed-to-floating hedges outstanding, and Exelon and Generation had $3,068 million and $768 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, 2015. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign currency hedges as of March 31, 2015.
			Generation																		Other												Exelon
	Description		Derivatives				Economic				Proprietary			Collateral				Subtotal			Derivatives			Economic			Collateral			Subtotal			Total
			Designated				Hedges				Trading(a)			and							Designated			Hedges			and
			as Hedging											Netting(b)							as Hedging						Netting(b)
			Instruments																		Instruments
	Mark-to-market		$	—			$	13			$	11		$	(10	)		$	14		$	1		$	—		$	—		$	1		$	15
	derivative assets
	(current assets)
	Mark-to-market		—				14				8			(3		)		19			31			2			(31		)	2			21
	derivative assets
	(noncurrent
	assets)
	Total mark-to-market		—				27				19			(13		)		33			32			2			(31		)	3			36
	derivative
	assets
	Mark-to-market		(8		)		(6		)		(8		)	15				(7		)	—			—			—			—			(7		)
	derivative liabilities
	(current liabilities)
	Mark-to-market		(9		)		—				(7		)	6				(10		)	—			(180		)	31			(149		)	(159		)
	derivative liabilities
	(noncurrent
	liabilities)
	Total mark-to-market derivative		(17		)		(6		)		(15		)	21				(17		)	—			(180		)	31			(149		)	(166		)
	liabilities
	Total mark-to-market		$	(17	)		$	21			$	4		$	8			$	16		$	32		$	(178	)	$	—		$	(146	)	$	(130	)
	derivative
	net assets
	(liabilities)
	_____________
	(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 within the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
	(b)	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
	The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2014:
			Generation																		Other												Exelon
	Description		Derivatives				Economic				Proprietary			Collateral				Subtotal			Derivatives			Economic			Collateral			Subtotal			Total
			Designated				Hedges				Trading(a)			and							Designated			Hedges			and
			as Hedging											Netting(b)							as Hedging						Netting(b)
			Instruments																		Instruments
	Mark-to-market		$	7			$	7			$	20		$	(22	)		$	12		$	3		$	—		$	—		$	3		$	15
	derivative assets
	(current assets)
	Mark-to-market		1				5				7			(7		)		6			20			1			(19		)	2			8
	derivative assets
	(noncurrent
	assets)
	Total mark-to-market		8				12				27			(29		)		18			23			1			(19		)	5			23
	derivative
	assets
	Mark-to-market		(8		)		(2		)		(14		)	25				1			—			—			—			—			1
	derivative liabilities
(current liabilities)
Mark-to-market		(4		)		—				(9		)	10				(3		)	(29		)	(101		)	19			(111		)	(114		)
derivative liabilities
(noncurrent
liabilities)
Total mark-to-market derivative		(12		)		(2		)		(23		)	35				(2		)	(29		)	(101		)	19			(111		)	(113		)
liabilities
Total mark-to-market		$	(4	)		$	10			$	4		$	6			$	16		$	(6	)	$	(100	)	$	—		$	(106	)	$	(90	)
derivative
net assets
(liabilities)
_______________
(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 within 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.
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		2015				2014				2015			2014
	Location		Gain (Loss) on Swaps								Gain (Loss) on Borrowings
Generation	Interest expense(a)		$	(1	)		$	(5	)		$	—		$	(1	)
Exelon	Interest expense		9				2				11			4
__________
(a)	For the three months ended March 31, 2015 and 2014, the loss on Generation swaps included $1 million and $4 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.
At March 31, 2015, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $900 million, with a derivative asset of $32 million. At December 31, 2014, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,450 million and $550 million, with a derivative asset of $29 million and $7 million, respectively. During the three months ended March 31, 2015 and 2014, the impact on the results of operations as a result of the ineffectiveness from fair value hedges was a $4 million and a $5 million gain, respectively.
Cash Flow Hedges.  During 2014, Exelon entered into $400 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated refinancing of existing debt. The swaps are designated as cash flow hedges. In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated these swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with a long-term borrowing. See Note 13 — Debt and Credit Agreements of the Exelon 2014 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $504 million as of March 31, 2015 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At March 31, 2015, the subsidiary had a $13 million derivative liability related to the swap.
During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Exelon Generation, entered into floating-to-fixed interest rate swaps to manage a portion its interest rate exposure in connection with long-term borrowings. See Note 13 — Debt and Credit Agreements of the Exelon 2014 Form 10-K for additional information regarding the financing. The swaps have a notional amount of $212 million as of March 31, 2015 and expire in 2020. The swaps are designated as cash flow hedges. At March 31, 2015, the subsidiary had a $3 million derivative liability related to the swaps.
During the three months ended March 31, 2015 and 2014, the impact on the results of operations as a result of ineffectiveness from cash flow hedges in continuing designated hedge relationships were immaterial.
Economic Hedges.  During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13 — Debt and Credit Agreements of the Exelon 2014 Form 10-K for additional information regarding the financing. The swaps have a total notional amount of $26 million as of March 31, 2015 and expire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. During the first quarter of 2015, the swaps were de-designated as the forecasted transaction was no longer probable of occurring. The balance in Accumulated OCI was frozen as of the date of de-designation and will amortize into Interest expense over the remaining term of the forecasted transaction. All future changes in fair value are reflected in Interest expense. At March 31, 2015, the subsidiary had a $3 million derivative liability related to these swaps, which included an immaterial amount that was amortized to Interest expense after de-designation.
During the third quarter of 2012, Constellation Solar Horizon, a subsidiary of Exelon 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 13 — Debt and Credit Agreements of the Exelon 2014 Form 10-K for additional information regarding the financing. The swap has a notional amount of $26 million as of March 31, 2015 and expires in 2030. This swap was designated as a cash flow hedge. During the first quarter of 2015, the swaps were de-designated as the forecasted transaction was no longer probable of occurring. The balance in OCI was frozen as of the date of de-designation and will amortize into Interest expense over the remaining term of the forecasted transaction. All future changes in fair value are reflected in Interest expense. At March 31, 2015, the subsidiary had an immaterial derivative liability related to the swap.
Through March 31, 2015, Exelon entered into $2,300 million of floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed merger with PHI. At March 31, 2015, Exelon had a $178 million derivative liability related to the swaps.
At March 31, 2015, Generation had $271 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $338 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.
Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon, Generation, ComEd, PECO and BGE)
Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted, unless Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including initial margin on exchange positions, is aggregated in the collateral and netting column. As of March 31, 2015 and December 31, 2014, $5 million and $8 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted, unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in a non-affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of March 31, 2015:
		Generation															ComEd			Exelon
Derivatives		Economic				Proprietary				Collateral			Subtotal(b)				Economic			Total
		Hedges				Trading				and							Hedges(c)			Derivatives
										Netting(a)
Mark-to-market derivative assets		$	4,618			$	431			$	(3,947	)	$	1,102			$	—		$	1,102
(current assets)
Mark-to-market derivative assets		2,363				70				(1,541		)	892				—			892
(noncurrent assets)
Total mark-to-market derivative		6,981				501				(5,488		)	1,994				—			1,994
assets
Mark-to-market derivative liabilities		(4,505		)		(437		)		4,852			(90		)		(20		)	(110		)
(current liabilities)
Mark-to-market derivative liabilities		(2,016		)		(77		)		1,982			(111		)		(221		)	(332		)
(noncurrent liabilities)
Total mark-to-market derivative		(6,521		)		(514		)		6,834			(201		)		(241		)	(442		)
liabilities
Total mark-to-market derivative		$	460			$	(13	)		$	1,346		$	1,793			$	(241	)	$	1,552
net assets (liabilities)
_________
(a)	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b)	Current and noncurrent assets are shown net of collateral of $387 million and $192 million, respectively, and current and noncurrent liabilities are shown net of collateral of $519 million and $248 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,346 million at March 31, 2015.
(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2014:
		Generation															ComEd			Exelon
Description		Economic				Proprietary				Collateral			Subtotal(b)				Economic			Total
		Hedges				Trading				and							Hedges(c)			Derivatives
										Netting(a)
Mark-to-market derivative assets		$	4,992			$	456			$	(4,184	)	$	1,264			$	—		$	1,264
(current assets)
Mark-to-market derivative assets		1,821				56				(1,112		)	765				—			765
(noncurrent assets)
Total mark-to-market derivative		6,813				512				(5,296		)	2,029				—			2,029
assets
Mark-to-market derivative liabilities		(4,947		)		(468		)		5,200			(215		)		(20		)	(235		)
(current liabilities)
Mark-to-market derivative liabilities		(1,540		)		(64		)		1,502			(102		)		(187		)	(289		)
(noncurrent liabilities)
Total mark-to-market derivative		(6,487		)		(532		)		6,702			(317		)		(207		)	(524		)
liabilities
Total mark-to-market derivative		$	326			$	(20	)		$	1,406		$	1,712			$	(207	)	$	1,505
net assets (liabilities)
________
(a)	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above.
(b)	Current and noncurrent assets are shown net of collateral of $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.
(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
Cash Flow Hedges (Exelon, Generation and ComEd).    As discussed previously, effective prior to the Constellation merger, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably probable, the fair value of the effective portion of these cash flow hedges was frozen in Accumulated OCI and is reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. Generation began recording prospective changes in the fair value of these instruments through current earnings from the date of de-designation. As of March 31, 2015, no unrealized balance remains in accumulated OCI to be reclassified by Generation.
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three months ended March 31, 2015 and 2014, containing information about the changes in the fair value of cash flow hedges and the reclassification from accumulated OCI into results of operations. The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.
				Total Cash Flow Hedge OCI Activity, Net of Income Tax
				Generation				Exelon
Three Months Ended March 31, 2015		Income  Statement		Total Cash Flow				Total Cash  Flow
		Location		Hedges				Hedges
Accumulated OCI derivative gain at December 31, 2014				$	(18	)		$	(28	)
Effective portion of changes in fair value				(6		)		(11		)
Reclassifications from accumulated OCI to net income		Other, net		—				16			(a)
Reclassifications from accumulated OCI to net income		Interest Expense		3				3
Reclassifications from accumulated OCI to net income		Operating Revenues		(2		)		(2		)
Accumulated OCI derivative gain at March 31, 2015				$	(23	)		$	(22	)
______
(a)	Amount is net of related income tax expense of $10 million for the three months ended March 31, 2015.
				Total Cash
				Flow Hedge OCI Activity,
				Net of Income Tax
				Generation				Exelon
Three Months Ended March 31, 2014		Income  Statement		Total Cash Flow				Total Cash  Flow
		Location		Hedges				Hedges
Accumulated OCI derivative gain at December 31, 2013				$	116			$	120
Effective portion of changes in fair value				(4		)		(1		)
Reclassifications from accumulated OCI to net income		Operating Revenues		(24		)	(a)	(24		)	(a)
Accumulated OCI derivative gain at March 31, 2014				$	88			$	95
__________
(a) Amount is net of related income tax expense of $15 million for the three months ended March 31, 2014.
The effect of Exelon’s and Generation's former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $2 million pre-tax gain for the three months ended March 31, 2015, and a $39 million pre-tax gain for the three months ended March 31, 2014. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as all energy-related cash flow hedge positions were de-designated prior to the merger date.
Economic Hedges (Exelon and Generation).    These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed PHI acquisition. For the three months ended March 31, 2015 and 2014, the following 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															HoldCo			Exelon
Three Months Ended March 31, 2015		Operating				Purchased				Interest			Total				Interest			Total
		Revenues				Power				Expense							Expense
						and Fuel
Change in fair value of commodity positions		$	164			$	(79	)		$	—		$	85			$	—		$	85
Reclassification to realized at settlement of		(21		)		87				—			66				—			66
commodity positions
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		(2		)		—				—			(2		)		—			(2		)
positions
Net treasury mark-to-market gains (losses)		11				—				—			11				(78		)	(67		)
Total Net mark-to-market gains (losses)		$	154			$	8			$	—		$	162			$	(78	)	$	84
		Generation															HoldCo			Exelon
Three Months Ended March 31, 2014		Operating				Purchased				Interest Expense			Total				Interest			Total
		Revenues				Power											Expense
						and Fuel
Change in fair value of commodity positions		$	(852	)		$	171			$	—		$	(681	)		$	—		$	(681	)
Reclassification to realized at settlement of		93				(141		)		—			(48		)		—			(48		)
commodity positions
Net commodity mark-to-market gains (losses)		(759		)		30				—			(729		)		—			(729		)
Change in fair value of treasury positions		(1		)		—				(1		)	(2		)		—			(2		)
Reclassification to realized at settlement of treasury		—				—				—			—				—			—
positions
Net treasury mark-to-market gains (losses)		(1		)		—				(1		)	(2		)		—			(2		)
Total Net mark-to-market gains (losses)		$	(760	)		$	30			$	(1	)	$	(731	)		$	—		$	(731	)
Proprietary Trading Activities (Exelon and Generation).    For the three months ended March 31, 2015 and 2014, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate derivative contracts to hedge risk associated with the interest rate component of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
	Location on Income		Three Months Ended March 31,
	Statement		2015				2014
Change in fair value of commodity positions	Operating Revenues		$	1			$	(3	)
Reclassification to realized at settlement	Operating Revenues		2				1
of commodity positions
Net commodity mark-to-market gains (losses)	Operating Revenues		3				(2		)
Change in fair value of treasury positions	Operating Revenues		4				—
Reclassification to realized at settlement	Operating Revenues		(4		)		—
of treasury positions
Net treasury mark-to-market gains (losses)	Operating Revenues		—				—
Total Net mark-to-market gains (losses)	Operating Revenues		$	3			$	(2	)
Credit Risk (Exelon, Generation, ComEd, PECO and BGE)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of March 31, 2015. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the table 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 and BGE of $52 million, $36 million and $26 million, as of March 31, 2015, respectively.
Rating as of March 31, 2015		Total				Credit				Net			Number  of			Net Exposure of
		Exposure				Collateral(a)				Exposure			Counterparties			Counterparties
		Before Credit											Greater than  10%			Greater than 10%
		Collateral											of Net Exposure			of Net Exposure
Investment grade		$	1,570			$	56			$	1,514		1			$	442
Non-investment grade		63				16				47			—			—
No external ratings
Internally rated — investment grade		495				—				495			—			—
Internally rated — non-investment		68				3				65			—			—
grade
Total		$	2,196			$	75			$	2,121		1			$	442
Net Credit Exposure by Type of Counterparty		As of March 31, 2015
Financial institutions		$	324
Investor-owned utilities, marketers, power producers		897
Energy cooperatives and municipalities		869
Other		31
Total		$	2,121
_____________________
(a)	As of March 31, 2015, credit collateral held from counterparties where Generation had credit exposure included $62 million of cash and $14 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, 2015, ComEd’s net credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters of the Exelon 2014 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, 2015, PECO is currently holding $2 million in collateral from 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, 2015, 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 5 — Regulatory Matters for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of March 31, 2015, BGE had no net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At March 31, 2015, BGE had credit exposure of $4 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers.
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
Credit-Risk Related Contingent Feature		31-Mar-15				31-Dec-14
Gross Fair Value of Derivative Contracts Containing this Feature(a)		$	(1,420	)		$	(1,433	)
Offsetting Fair Value of In-the-Money Contracts Under Master		1,138				1,140
Netting Arrangements(b)
Net Fair Value of Derivative Contracts Containing This Feature(c)		$	(282	)		$	(293	)
__________
(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
Generation had cash collateral posted of $1,428 million and letters of credit posted of $626 million and cash collateral held of $69 million and letters of credit held of $22 million as of March 31, 2015 for counterparties with derivative positions. Generation had cash collateral posted of $1,497 million and letters of credit posted of $672 million and cash collateral held of $77 million and letters of credit held of $24 million at December 31, 2014 for counterparties with derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody’s), Generation would have been required to post additional collateral of $2.3 billion and $2.4 billion as of March 31, 2015 and December 31, 2014, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of March 31, 2015, Generation’s swaps were in an asset with a fair value of $16 million and Exelon's swaps were in a liability position, with a fair value of $(130) million, respectively.
See Note 24 — Segment Information of the Exelon 2014 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, 2015, ComEd held approximately $2 million 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, 2015, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 3 — Regulatory Matters of the Exelon 2014 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, 2015, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of March 31, 2015, PECO could have been required to post approximately $36 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, 2015, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of March 31, 2015, BGE could have been required to post approximately $111 million of collateral to its counterparties.

Debt_and_Credit_Agreements_Exe

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

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

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

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

Short-Term Borrowings

Exelon, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money pool.

The Registrants had the following amounts of commercial paper borrowings outstanding as of March 31, 2015 and December 31, 2014:

Commercial Paper Borrowings

31-Mar-15

31-Dec-14

Exelon Corporate

$

—

$

—

Generation

—

—

ComEd

283

304

PECO

—

—

BGE

—

120

Credit Facilities

Exelon had bank lines of credit under committed credit facilities at March 31, 2015 for short-term financial needs, as follows:

Type of Credit Facility

Amount(a)

Expiration Dates

Capacity Type

(In billions)

Exelon Corporate

Syndicated Revolver(b)

$

0.5

May-19

Letters of credit and cash

Generation

Syndicated Revolver

5.1

May-19

Letters of credit and cash

Syndicated Revolver

0.2

Aug-18

Letters of credit and cash

Bilateral

0.3

December 2015 and April 2016

Letters of credit and cash

Bilateral

0.1

Jan-17

Letters of credit

Bilateral

0.1

Oct-15

Letters of credit and cash

ComEd

Syndicated Revolver

1

Mar-19

Letters of credit and cash

PECO

Syndicated Revolver(b)

0.6

May-19

Letters of credit and cash

BGE

Syndicated Revolver(b)

0.6

May-19

Letters of credit and cash

Total

$

8.5

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 16, 2015. These facilities are solely utilized to issue letters of credit. As of March 31, 2015, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $16 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion to support the PHI transaction discussed below.

(b)

Syndicated revolvers include credit facility commitments of $22 million, $27 million and $27 million for Exelon Corporate, PECO and BGE, respectively, which expire in August 2018.

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

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

Credit Agreements

In May 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $3.2 billion as a result of the June 2014 $1.15 billion Junior Subordinated note issuance and equity offering discussed below, as well as the net after-tax proceeds from generation asset divestitures during the second half of 2014. During the three months ended March 31, 2015, Exelon recorded $11 million to interest expense in connection with the bridge facility. It is not currently expected that Exelon will be required to draw upon this credit facility.

Long-Term Debt

Issuance of Long-Term Debt

During the three months ended March 31, 2015, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Senior Unsecured Notes (a)

2.95

%

15-Jan-20

$

750

Fund the optional redemption of Exelon's $550 million, 4.550% Senior Notes and for general corporate purposes

Generation

AVSR DOE Nonrecourse Debt

2.293 - 2.559 %

5-Jan-37

$

14

Antelope Valley solar development

Generation

Energy Efficiency Project Financing

3.71

%

1-Oct-35

$

42

Funding to install energy conservation measures in Coleman, Florida

ComEd

Mortgage Bonds Series 118

3.7

%

1-Mar-45

$

400

Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes

_____________

(a)

In connection with the issuance of Senior Unsecured Notes, Exelon terminated floating-to-fixed interest rate swaps that had been designated as cash flow hedges. See Note 8 — Derivative Financial Instruments for further information on the swap termination.

On April 1, 2015, Generation issued $7 million of 2.464% AVSR DOE nonrecourse debt, maturing on January 5, 2037. The proceeds are used to fund the Antelope Valley Solar development.

On April 28, 2015, Generation issued $18 million of 2.544% AVSR DOE nonrecourse debt, maturing on January 5, 2037. The proceeds are used to fund the Antelope Valley Solar development.

During the three months ended March 31, 2014, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

ExGen Renewables I Nonrecourse Debt

LIBOR + 4.25%

February 6, 2021

$

300

General corporate purposes

ComEd

First Mortgage Bonds Series 115

2.15

%

15-Jan-19

$

300

Refinance maturing mortgage bonds and general corporate purposes

ComEd

First Mortgage Bonds Series 116

4.7

%

January 15, 2044

$

350

Refinance maturing mortgage bonds and general corporate purposes

Retirement and Redemptions of Current and Long-Term Debt

During the three months ended March 31, 2015, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Exelon Corporate(a)

Unsecured Notes

4.55

%

June 15, 2015

$

550

Generation(a)

Unsecured Notes

4.55

%

15-Jun-15

$

550

Generation

CEU Upstream Nonrecourse Debt

LIBOR + 2.25%

22-Jul-16

$

2

Generation

AVSR DOE Nonrecourse Debt

2.29%-3.56%

5-Jan-37

$

4

Generation

Kennett Square Capital Lease

7.83

%

20-Sep-20

$

1

Generation

Continental Wind Nonrecouse Debt

6

%

28-Feb-33

$

10

Generation

ExGen Texas Power Nonrecouse Debt

LIBOR + 4.75%

18-Sep-21

$

2

____________

(a)

As part of the 2012 Constellation merger, Exelon and subsidiaries of Generation assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon, resulting in intercompany notes payable at Generation and Exelon Corporate.

On April 1, 2015, BGE retired $37 million aggregate principal of its 5.720% Rate Stabilization Bonds due 2017.

On April 6, 2015, Generation paid down $2 million of principal and interest of its 2.29% - 3.55% AVSR DOE Nonrecourse debt.

On April 15, 2015, ComEd retired $260 million aggregate principal of its 4.700% First Mortgage Bonds, Series 101.

During the three months ended March 31, 2014, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Generation

2003 Senior Notes

5.35

%

January 15, 2014

$

500

Generation

Pollution Control Loan

4.1

%

July 1, 2014

$

20

Generation

Continental Wind Nonrecourse Debt

6

%

February 28, 2033

$

11

Generation

Kennett Square Capital Lease

7.83

%

September 20, 2020

$

1

ComEd

Mortgage Bonds Series 110

1.63

%

January 15, 2014

$

600

ComEd

Pollution Control Series 1994C

5.85

%

January 15, 2014

$

17

Junior Subordinated Notes

In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Net proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds are being used to finance a portion of the acquisition of PHI and for general corporate purposes. Each equity unit represents an undivided beneficial ownership interest in Exelon’s 2.50% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017.

At the time of issuance, Exelon determined that the forward equity purchase contract had no value and therefore the entire $1.15 billion of junior subordinated notes were allocated to debt and recorded within Long-term debt on Exelon’s Consolidated Balance Sheet. Additionally, at the time of issuance, the present value of the contract payments of $131 million were recorded to Long-term debt, representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments will be accreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income. The Long-term debt recorded for the contract payments is considered a non-cash financing transaction that was excluded from Exelon’s Consolidated Statements of Cash Flows. Until settlement of the equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method.

For further information about the terms of the remarketing of the junior subordinated notes, see Note 13—Debt and Credit Agreements of the Exelon 2014 Form 10-K.

Income_Taxes_Exelon_Generation

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
	The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
	For the Three Months Ended March 31, 2015	Exelon		Generation		ComEd		PECO		BGE
	U.S. Federal statutory rate	35	%	35	%	35	%	35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	2.6		2.7		5		1.2		5.3
	Qualified nuclear decommissioning trust fund income	1.9		3		—		—		—
	Domestic production activities deduction	(2.2	)	(3.4	)	—		—		—
	Health care reform legislation	—		—		—		—		0.2
	Amortization of investment tax credit, net deferred taxes	(0.9	)	(1.4	)	(0.3	)	(0.1	)	—
	Plant basis differences	(1.3	)	—		(0.3	)	(6.7	)	(0.3	)
	Production tax credits and other credits	(1.8	)	(2.8	)	—		—		—
	Noncontrolling interest	(0.7	)	(1.1	)	—		—		—
	Other	0.4		(0.2	)	0.2		—		0.2
	Effective income tax rate	33	%	31.8	%	39.6	%	29.4	%	40.4	%
	For the Three Months Ended March 31, 2014	Exelon		Generation(a)		ComEd		PECO		BGE
	U.S. Federal statutory rate	35	%	35	%	35	%	35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	(57.6	)	9.7		5.5		1.2		5.2
	Qualified nuclear decommissioning trust fund income	44.2		(4.6	)	—		—		—
	Domestic production activities deduction	(27.8	)	2.9		—		—		—
	Health care reform legislation	1.3		—		0.1		—		0.2
	Amortization of investment tax credit, net deferred taxes	(18.0	)	1.7		(0.3	)	(0.1	)	(0.2	)
	Plant basis differences	(31.4	)	—		(0.6	)	(8.7	)	(0.6	)
	Production tax credits and other credits	(36.5	)	3.8		—		—		—
	Noncontrolling interest	—		—		—		—		—
	Other	(47.7	)	3.3		0.2		0.2		0.1
	Effective income tax rate	(138.5	)%	51.8	%	39.9	%	27.6	%	39.7	%
	(a)	Generation recognized a loss before income taxes for the three months ended March 31, 2014. As a result, positive percentages represent an income tax benefit for Generation for the three months ended March 31, 2014.
	Accounting for Uncertainty in Income Taxes
	Exelon, Generation, ComEd, PECO, and BGE have $1,282 million, $733 million, $147 million, $0 million, and $120 million, of unrecognized tax benefits as of March 31, 2015, respectively, and $1,829 million, $1,357 million, $149 million, $44 million, and $0 million, of unrecognized tax benefits as of December 31, 2014, respectively. The unrecognized tax benefits as of March 31, 2015 reflect a decrease at Exelon, Generation, and PECO primarily attributable to the disallowed AmerGen claims discussed below. The unrecognized tax benefits as of March 31, 2015 reflect an increase at BGE and Generation attributable to a state income tax opportunity. A portion of the benefits associated with uncertain tax positions for utilities, if recognized, may be included in future base rates.
	Nuclear Decommissioning Liabilities (Exelon and Generation)
	AmerGen filed income tax refund claims taking the position that nuclear decommissioning liabilities assumed as part of its acquisition of nuclear power plants are taken into account in determining the tax basis in the assets it acquired. The additional basis results primarily in reduced capital gains or increased capital losses on the sale of assets in nonqualified decommissioning funds and increased tax depreciation and amortization deductions. The IRS disagrees with this position and disallowed AmerGen's claims. In early 2009, Generation filed a complaint in the United States Court of Federal Claims to contest this determination. On September 17, 2013, the Court granted the government’s motion denying AmerGen’s claims for refund. In the first quarter of 2014, Exelon filed an appeal of the decision to the United States Court of Appeals for the Federal Circuit. On March 11, 2015, the Federal Circuit affirmed the lower court’s decision to deny AmerGen’s claims for refund. Exelon will not be pursuing further appeals with respect to this issue and, as a result, has reduced its total unrecognized tax benefits by $661 million. This change in unrecognized tax benefits had no impact on Exelon’s or Generation’s effective tax rate.
	Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
	Settlement of Income Tax Audits
	As of March 31, 2015, Exelon, Generation, and BGE have approximately $345 million, $225 million, and $120 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, and expected statute of limitation expirations. Of the above unrecognized tax benefits, Exelon and Generation have $225 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to BGE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
	Other Income Tax Matters
	Like-Kind Exchange
	Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.
	Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $90 million for a substantial understatement of tax.
	Exelon disagrees with the IRS and continues to believe that its like-kind exchange transaction is not the same as or substantially similar to a SILO. Although Exelon has been and remains willing to settle the disagreement on terms commensurate with the hazards of litigation, Exelon does not believe a settlement is possible. Because Exelon believed, as of December 31, 2012, that it was more-likely-than-not that Exelon would prevail in litigation, Exelon and ComEd had no liability for unrecognized tax benefits with respect to the like-kind exchange position.
	On January 9, 2013, the U.S. Court of Appeals for the Federal Circuit reversed the U.S. Court of Federal Claims and reached a decision for the government in Consolidated Edison v. United States. The Court disallowed Consolidated Edison’s deductions stemming from its participation in a LILO transaction that the IRS also has characterized as a tax shelter.
	In accordance with applicable accounting standards, Exelon is required to assess whether it is more-likely-than-not that it will prevail in litigation. Exelon continues to believe that its transaction is not a SILO and that it has a strong case on the merits. However, in light of the Consolidated Edison decision and Exelon’s current determination that settlement is unlikely, Exelon has concluded that subsequent to December 31, 2012, it is no longer more-likely-than-not that its position will be sustained. As a result, in the first quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represents the amount of interest expense (after-tax) and incremental state income tax expense for periods through March 31, 2013 that would be payable in the event that Exelon is unsuccessful in litigation. Of this amount, approximately $170 million was recorded at ComEd. Exelon intends to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts on ComEd’s equity. As such, ComEd recorded on its consolidated balance sheet as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Exelon and ComEd will continue to accrue interest on the unpaid tax liabilities related to the uncertain tax position, and the charges arising from future interest accruals are not expected to be material to the annual operating earnings of Exelon or ComEd. In addition, ComEd will continue to record non-cash equity contributions from Exelon in the amount of the net after-tax interest charges attributable to ComEd in connection with the like-kind exchange position. Exelon continues to believe that it is unlikely that the IRS's assertion of penalties will ultimately be sustained and therefore no liability for the penalty has been recorded.
	On September 30, 2013, the 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 has been scheduled for August of 2015. Exelon was not required to remit any part of the asserted tax or penalty in order to litigate the issue. The litigation could take three to five years including appeals, if necessary. Decisions in the Tax Court are not controlled by the Federal Circuit’s decision in Consolidated Edison.
	In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, the potential tax and after-tax interest, exclusive of penalties, that could become currently payable as of March 31, 2015 may be as much as $810 million, of which approximately $310 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless, and the balance at Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.
	In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. The termination will result in a 2014 tax payment of approximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon will be required to pay the full amount of tax and after-tax interest discussed in the preceding paragraph but will ultimately be entitled to a refund of the 2014 tax payment.

Nuclear_Decommissioning_Exelon

Nuclear Decommissioning (Exelon and Generation)	3 Months Ended
	Mar. 31, 2015
Environmental Remediation Obligations [Abstract]
Nuclear Decommissioning (Exelon and Generation)	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, 2014 to March 31, 2015:
	Nuclear decommissioning ARO at December 31, 2014(a)	$	6,961
	Net increase due to changes in, and timing of, estimated future cash flows(b)	55
	Accretion expense	94
	Nuclear decommissioning ARO at March 31, 2015(a)	$	7,110
	(a)	Includes $8 million as the current portion of the ARO at March 31, 2015 and December 31, 2014, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
	(b)	Represents a purchase accounting adjustment to the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
	Nuclear Decommissioning Trust Fund Investments
	NDT funds have been established for each generating station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
	The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately $24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. Aside from the former PECO units, Generation does not currently collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from utility customers. Apart from the contributions made to the NDT funds from amounts previously collected from ComEd and currently collected from PECO customers, Generation has not made contributions to the NDT funds.
	Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation, will not be allowed to collect amounts associated with the first $50 million of any shortfall of trust funds, compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts for any of Generation's other nuclear units, including the CENG units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG’s acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to nuclear decommissioning trust funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
	At March 31, 2015 and December 31, 2014, Exelon and Generation had NDT fund investments totaling $10,712 million and $10,537 million, respectively.
	The following table provides unrealized gains on NDT funds for the three months ended March 31, 2015 and 2014:
		Exelon and Generation
		Three Months Ended March 31,
		2015		2014
	Net unrealized gains on decommissioning trust	$	48	$	61
	funds — Regulatory Agreement Units(a)
	Net unrealized gains on decommissioning trust	40		13
	funds — Non-Regulatory Agreement Units(b)(c)
	(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 $10 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2015 and 2014. 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 25 — Related Party Transactions of the Exelon 2014 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
	Zion Station Decommissioning
	On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 15 — Asset Retirement Obligations of the Exelon 2014 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, will be recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $87 million, which is included within the nuclear decommissioning ARO at March 31, 2015. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at March 31, 2015 and December 31, 2014:
		Exelon and Generation
		31-Mar-15		31-Dec-14
	Carrying value of Zion Station pledged assets	$	308	$	319
	Payable to Zion Solutions(a)	281		292
	Current portion of payable to Zion Solutions(b)	145		137
	Cumulative withdrawals by Zion Solutions to pay decommissioning costs	687		666
	(a)	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
	(b)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
	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.

Retirement_Benefits_Exelon_Gen

Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)	Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)
	Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees.
	Defined Benefit Pension and Other Postretirement Benefits
	During the first quarter of 2015, Exelon received an updated valuation of its pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2015. This valuation resulted in an increase to the pension obligation of $45 million and an increase to the other postretirement benefit obligation of $57 million. Additionally, accumulated other comprehensive loss increased by approximately $27 million (after tax), regulatory assets increased by approximately $48 million, and regulatory liabilities decreased by approximately $11 million.
	The majority of the 2015 pension benefit cost for Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.94%. The majority of the 2015 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.46% for funded plans and a discount rate of 3.92%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the three months ended March 31, 2015 and 2014.
		Pension Benefits						Other
		Three Months Ended						Postretirement Benefits
		March 31,						Three Months Ended
								March 31,
		2015(a)			2014(a)			2015(a)			2014(a)
	Service cost	$	82		$	69		$	30		$	33
	Interest cost	178			183			42			55
	Expected return on assets	(257		)	(241		)	(38		)	(38		)
	Amortization of:
	Prior service cost (benefit)	3			3			(43		)	(4		)
	Actuarial loss	143			105			20			8
	Net periodic benefit cost	$	149		$	119		$	11		$	54
	______________
	(a)	For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.
	The amounts below represent Generation’s, ComEd’s, PECO’s, BGE’s and BSC's allocated portion of the pension and postretirement benefit plan costs, which were included in 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, 2015 and 2014.
		Three Months Ended March 31,
	Pension and Other Postretirement Benefit Costs	2015			2014
	Generation(a)	$	67		$	75
	ComEd	52			56
	PECO	10			12
	BGE	17			16
	BSC(b)	14			14
	______________
	(a)	For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.
	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.
	Defined Contribution Savings Plans
	The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three months ended March 31, 2015 and 2014:
			Three Months Ended March 31,
	Savings Plan Matching Contributions		2015			2014
	Exelon(a)		$	22		$	29
	Generation(a)		13			14
	ComEd		5			7
	PECO		1			2
	BGE		2			3
	BSC(b)		1			3
	_______________
	(a)	Includes $2 million related to CENG for the three months ended March 31, 2015. CENG is not included in the 2014 amounts.
	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Severance_Exelon_Generation_Co

Severance (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Restructuring Charges [Abstract]
Severance (Exelon, Generation, ComEd, PECO and BGE)	Severance (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or, if future service is required to receive the termination benefit, ratably over the required service period.
	Ongoing Severance Plans
	The Registrants provide severance, health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business, which were not directly related to the merger with Constellation or with the integration of CENG. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.
	For the three months ended March 31, 2015 and 2014, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
		Exelon		Generation		ComEd		PECO		BGE
	Severance Benefits
	Severance charges - 2015	$	20	$	20	$	—	$	—	$	—
	Severance charges - 2014	$	4	$	4	$	—	$	—	$	—
	The severance liability balances associated with these ongoing severance benefits as of March 31, 2015 and December 31, 2014 are not material.

Changes_in_Accumulated_Other_C

Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Changes in Accumulated Other Comprehensive Income [Abstract]
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE)	Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO)
	The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2015 and 2014:
	Three Months Ended March 31, 2015		Gains				Unrealized			Pension and			Foreign			AOCI of		Total
			and				Gains and			Non-Pension			Currency			Equity
			(Losses)				(Losses) on			Postretirement			Items			Investments
			on Hedging				Marketable			Benefit Plan
			Activity				Securities			Items
	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
	______________
	(a)	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.
	(b)	See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.
	Three Months Ended March 31, 2014		Gains				Unrealized			Pension and			Foreign			AOCI of		Total
			and				Gains and			Non-Pension			Currency			Equity
			(Losses)				(Losses) on			Postretirement			Items			Investments
			on Hedging				Marketable			Benefit Plan
			Activity				Securities			Items
	Exelon(a)
	Beginning balance		$	120			$	2		$	(2,260	)	$	(10	)	$	108	$	(2,040	)
	OCI before reclassifications		(1		)		—			(13		)	(5		)	11		(8		)
	Amounts reclassified from AOCI(b)		(24		)		—			35			—			1		12
	Net current-period OCI		(25		)		—			22			(5		)	12		4
	Ending balance		$	95			$	2		$	(2,238	)	$	(15	)	$	120	$	(2,036	)
	Generation(a)
	Beginning balance		$	114			$	2		$	—		$	(10	)	$	108	$	214
	OCI before reclassifications		(1		)		(3		)	—			(5		)	11		2
	Amounts reclassified from AOCI(b)		(24		)		—			—			—			1		(23		)
	Net current-period OCI		(25		)		(3		)	—			(5		)	12		(21		)
	Ending balance		$	89			$	(1	)	$	—		$	(15	)	$	120	$	193
	PECO(a)
	Beginning balance		$	—			$	1		$	—		$	—		$	—	$	1
	OCI before reclassifications		—				—			—			—			—		—
	Amounts reclassified from AOCI(b)		—				—			—			—			—		—
	Net current-period OCI		—				—			—			—			—		—
	Ending balance		$	—			$	1		$	—		$	—		$	—	$	1
	_______________
	(a)	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.
	(b)	See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.
	ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net income during the three months ended March 31, 2015 and 2014. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the three months ended March 31, 2015 and 2014.
	Three Months Ended March 31, 2015
	Details about AOCI components		Items reclassified out of AOCI(a)							Affected line item in the Statements of Operations and Comprehensive Income
			Exelon				Generation
	Gains (losses) on hedging activity
	Terminated interest rate swaps (c)		$	(26	)		$	—		Other, net
	Energy related hedges		2				2			Operating revenues
	Other cash flow hedges		(3		)		(3		)	Interest expense
			(27		)		(1		)	Total before tax
			10				—			Tax benefit
		$	(17	)		$	(1	)	Net of tax
Amortization of pension and other postretirement benefit plan items
Prior service costs (b)		$	19			$	—
Actuarial losses (b)		(90		)		—
		(71		)		—			Total before tax
		28				—			Tax benefit
		$	(43	)		$	—		Net of tax
Total Reclassifications for the period		$	(60	)		$	(1	)	Net of Tax
Three months ended March 31, 2014
Details about AOCI components		Items reclassified out of AOCI(a)							Affected line item in the Statements of Operations and Comprehensive Income
		Exelon				Generation
Gains on hedging activity
Energy related hedges		$	39			$	39		Operating revenues
		39				39			Total before tax
		(15		)		(15		)	Tax (expense)
		$	24			$	24		Net of tax
Amortization of pension and other postretirement benefit plan items
Prior service costs (b)		$	(2	)		$	—
Actuarial losses (b)		(56		)		—
		(58		)		—			Total before tax
		23				—			Tax benefit
		$	(35	)		$	—		Net of tax
Equity investments
Capital activity		$	(1	)		$	(1	)	Equity in losses of unconsolidated affiliates
		(1		)		(1		)	Total before tax
		—				—			Tax benefit
		$	(1	)		$	(1	)	Net of tax
Total reclassifications for the period		$	(12	)		$	23		Net of Tax
____________
(a)	All amounts are net of tax. Amounts in parentheses represent a decrease in net income.
(b)	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 12— Retirement Benefits for additional details).
(c)	In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three months ended March 31, 2015 and 2014:
	Three Months Ended March 31,
	2015				2014
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	8			$	(1	)
Actuarial gain (loss) reclassified to periodic cost	(35		)		(23		)
Pension and non-pension postretirement benefit plans valuation adjustment	17				7
Change in unrealized gain (loss) on cash flow hedges	(2		)		18
Change in unrealized income on equity investments	—				(7		)
Total	$	(12	)		$	(6	)
Generation
Change in unrealized gain (loss) on cash flow hedges	$	5			$	19
Change in unrealized income on equity investments	—				(7		)
Change in marketable securities	—				(2		)
Total	$	5			$	10

Common_Stock_Exelon_Generation

Common Stock (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Common Stock [Abstract]
Common Stock (Exelon, Generation, ComEd, PECO and BGE)	15.    Common Stock (Exelon, Generation, ComEd, PECO and BGE)
	Equity Securities Offering
	In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements requiring Exelon to settle the transaction prior to October 29, 2015. No amounts have or will be recorded in Exelon’s consolidated financial statements with respect to the equity offering until settlement of the forward sale agreements occurs. Based on the average stock price for the quarter ended March 31, 2015, if Exelon had elected to net settle the contract, Exelon would have been required to issue approximately 2.5 million shares at a forward price of $33.21. If Exelon elects to cash settle the contract, the transaction costs will be recorded as a charge to earnings in the period in which it becomes probable that Exelon will cash settle. Otherwise, all transaction costs will be reflected as a reduction to the value of the common stock issued in Exelon’s Consolidated Balance Sheet. The net proceeds received upon settlement are expected to be used to finance a portion of the proposed acquisition of PHI and for general corporate purposes. Until settlement, earnings per share dilution resulting from the forward sales agreement, if any, will be determined under the treasury stock method. For further information on the options Exelon has to settle the transaction, refer to note 19—Common Stock of the Exelon 2014 Form 10-K
	Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. See Note 9 — Debt and Credit Agreements for further information on the equity units.

Earnings_Per_Share_and_Equity_

Earnings Per Share and Equity (Exelon)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Earnings Per Share and Equity (Exelon)	Earnings Per Share and Equity (Exelon)
	Earnings per Share (Exelon)
	Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding adjusted to include the potentially dilutive effect of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share:
		Three Months Ended March 31,
		2015		2014
	Net income attributable to common shareholders	$	693	$	90
	Average common shares outstanding — basic	862		858
	Potentially dilutive effect of stock options, performance share awards and restricted stock	5		3
	Average common shares outstanding — diluted	867		861
	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 15 million and 18 million for the three months ended March 31, 2015 and 2014, 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 less than 1 million for the three months ended March 31, 2015 since issuance. Additionally, there were no forward units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect for the three months ended March 31, 2015 and since issuance. Refer to Note 15 — Common Stock for further information regarding the equity units and equity forward units.
	Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of March 31, 2015. In 2008, Exelon management decided to defer indefinitely any share repurchases.

Commitments_and_Contingencies_

Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)	Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)
	The following is an update to the current status of commitments and contingencies set forth in Note 22 of the Exelon 2014 Form 10-K.
	Commitments
	Energy Commitments
	As of March 31, 2015, Generation’s commitments relating to its purchases from unaffiliated utilities and others of energy, capacity, transmission rights and RECs, are as indicated in the following table:
		Net Capacity			REC			Transmission			Total
		Purchases(a)			Purchases(b)			Rights
								Purchases(c)
	2015	$	317		$	124		$	13		$	454
	2016	287			258			15			560
	2017	219			153			15			387
	2018	109			52			16			177
	2019	113			9			16			138
	Thereafter	276			1			35			312
	Total	$	1,321		$	597		$	110		$	2,028
	____________________
	(a)	Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at March 31, 2015, net of fixed capacity payments expected to be received ("capacity offsets") by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of March 31, 2015, capacity offsets were $107 million, $133 million, $136 million, $137, million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.
	(b)	The table excludes renewable energy purchases that are contingent in nature.
	(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
	ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments, as applicable, as of March 31, 2015 are as follows:
					Expiration within
		Total			2015			2016			2017			2018			2019		2020
																			and beyond
	ComEd
	Electric supply procurement(a)(b)	$	473		$	182		$	151		$	140		$	—		$	—	$	—
	Renewable energy and RECs(c)	1,498			56			76			77			78			84		1,127
	PECO
	Electric supply procurement(d)	832			532			268			32			—			—		—
	AECs(e)	13			2			2			2			2			2		3
	BGE
	Electric supply procurement(f)	1,074			538			448			88			—			—		—
	Curtailment services(g)	105			30			34			29			12			—		—
	___________________
	(a)	ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2018. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of March 31, 2015, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017.
	(b)	Excludes electric supply commitments associated with the Spring 2015 procurement process approved by the ICC on April 1, 2015, for the years 2015-2018 in the amount of $179 million, $112 million, $23 million, and $21 million, respectively.
	(c)	Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms.
	(d)	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2017. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 — Regulatory Matters for additional information.
	(e)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information.
	(f)	BGE entered into various contracts for the procurement of electricity that expire between 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters of the Exelon 2014 10-K for additional information.
	(g)	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. See Note 3 —Regulatory Matters of the Exelon 2014 Form 10-K for additional information.
	Fuel Purchase Obligations
	In addition to the energy commitments described above, Generation has commitments to purchase fuel supplies for nuclear and fossil generation. Since the second quarter of 2014, 100% of CENG’s nuclear fuel commitments are disclosed within the Generation line below, since CENG is now fully consolidated by Generation. PECO and BGE have commitments to purchase natural gas related to transportation, storage capacity and services to serve customers in their gas distribution service territory. As of March 31, 2015, these net commitments were as follows:
					Expiration within
		Total			2015			2016			2017			2018			2019		2020
																			and beyond
	Generation	$	8,479		$	1,015		$	1,145		$	1,151		$	987		$	869	$	3,312
	PECO	392			109			104			61			34			13		71
	BGE	614			82			87			74			64			61		246
	Other Purchase Obligations
	The Registrants’ other purchase obligations as of March 31, 2015, which primarily represent commitments for services, materials and information technology, are as follows:
					Expiration within
		Total			2015			2016			2017			2018			2019		2020
																			and beyond
	Exelon	$	840		$	258		$	279		$	152		$	38		$	30	$	83
	Generation(a)	364			123			81			43			31			23		63
	ComEd(b)	152			53			82			2			2			2		11
	PECO(b)	11			5			6			—			—			—		—
	BGE(b)	313			77			110			107			5			5		9
	_____________________
	(a) Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information.
	(b) Purchase obligations include commitments related to smart meter installation. See Note 5 — Regulatory Matters for additional information.
	Construction Commitments
	Generation’s ongoing investments in renewables development and new natural gas construction illustrates Generation’s growth strategy to provide for diversification opportunities while leveraging its expertise and strengths.
	On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with at least 120 MW of new natural gas-fired generation. The remaining commitment is approximately $17 million under the contract and achievement of commercial operations is expected in 2015. This project will satisfy a portion of Exelon's commitment to Maryland. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger.
During the third and fourth quarter of 2014, Generation executed contracts associated with the construction of new combined-cycle gas turbine units in Texas. The remaining commitment is approximately $816 million under these contracts and achievement of commercial operations is expected in 2017.
During the fourth quarter of 2014, Generation executed contracts associated with the construction of the 30 MW Fair Wind project in western Maryland. The remaining commitment is approximately $26 million under these contracts and achievement of commercial operations is expected in 2015. This project will satisfy a portion of Exelon’s 125 MW Tier I land-based renewables commitment made to Maryland. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger.
During the fourth quarter of 2014, Generation executed contracts associated with the construction of the 78 MW Sendero Wind project in southern Texas. The remaining commitment is approximately $34 million under these contracts and achievement of commercial operations is expected in 2015.
Refer to Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for information on investment programs associated with regulatory mandates, such as ComEd’s Infrastructure Investment Plan under EIMA, PECO’s Smart Meter Procurement and Installation Plan and BGE’s comprehensive smart grid initiative.
Constellation Merger Commitments
In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.
The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. Generation's total commitments under the lease agreement are $0 million, $5 million, $12 million, $13 million, $13 million, and $285 million, related to 2015, 2016, 2017, 2018, 2019 and thereafter.
The direct investment commitment also includes $600 million to $650 million relating to Exelon and Generation’s development or assistance in the development of 285 — 300 MWs of new generation in Maryland, which is expected to be completed over a period of 10 years. The MDPSC order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. However, during the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that Exelon and Generation now believe that the most likely outcome will involve making subsidy payments and/or liquidated damages payments rather than constructing the specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. 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. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for additional information regarding the Constellation merger commitments.
Equity Investment Commitments
As part of Generation's recent investments in technology development, Generation has entered into equity purchase agreements that include commitments to purchase additional equity through incremental payments. The additional equity is provided by the agreements to fund the anticipated needs of the planned operations of the associated companies. The commitment includes approximately $20 million of in-kind services. As of March 31, 2015, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:
	Total
2015	$	77
2016	37
2017	19
2018	14
Total	$	147
Contingencies
Commercial Commitments
The Registrants’ commercial commitments as of March 31, 2015, representing commitments potentially triggered by future events were as follows:
	Exelon			Generation			ComEd			PECO			BGE
Letters of credit (non-debt)(a)	$	1,740		$	1,673		$	18		$	22		$	1
Guarantees	5,453		(b)	2,678		(c)	202		(d)	196		(e)	263		(f)
Nuclear insurance premiums(g)	3,014			3,014			—			—			—
Underwriters discount(h)	60			—			—			—			—
Total commercial commitments	$	10,267		$	7,365		$	220		$	218		$	264
___________________
(a)	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
(b)	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $642 million at March 31, 2015, which represents the total amount Exelon could be required to fund based on March 31, 2015 market prices.
(c)	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $429 million at March 31, 2015, which represents the total amount Generation could be required to fund based on March 31, 2015 market prices.
(d)	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.
(e)	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
(f)	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.
(g)	Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
(h)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 15 — Common Stock for further details of the equity securities offering.
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has 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, 2015, the current liability limit per incident was $13.6 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors. An inflation adjustment must be made at least once every 5 years and the last inflation adjustment was made effective September 10, 2013. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. As of March 31, 2015, the amount of nuclear energy liability insurance purchased is $375 million for each operating site. Additionally, the Price-Anderson Act requires a second layer of protection through the mandatory participation in a retrospective rating plan for power reactors (currently 104 reactors) resulting in an additional $13.2 billion in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Under the Price-Anderson Act, the maximum assessment in the event of an incident for each nuclear operator, per reactor, per incident (including a 5% surcharge), is $127.3 million, payable at no more than $19 million per reactor per incident per year. Exelon’s maximum liability per incident is approximately $2.7 billion, including CENG's related liability.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.6 billion limit for a single incident.
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 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
NEIL 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
General.    The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•	ComEd has identified 42 sites, 17 of which 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 2019.
•	PECO has identified 26 sites, 16 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The remaining 10 sites are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2021.
•	BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. An investigation of an additional gas purification site was completed during the first quarter of 2015 at the direction of the MDE. BGE has established a reserve, which is not material, representing the low end of a reasonably possible estimated range of loss. Management is unable to estimate the maximum exposure of potential remediation efforts at this time, which may have a material impact on BGE's results of operations and cash flows.
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. BGE has not established a regulatory asset for the costs associated with the gas purification site as of March 31, 2015.
As of March 31, 2015 and December 31, 2014, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
31-Mar-15	Total Environmental			Portion of Total Related to
	Investigation and			MGP Investigation and
	Remediation Reserve			Remediation
Exelon	$	340		$	272
Generation	62			—
ComEd	231			228
PECO	44			42
BGE	3			2
December 31, 2014	Total Environmental			Portion of Total Related to
	Investigation and			MGP Investigation  and
	Remediation Reserve			Remediation
Exelon	$	347		$	277
Generation	63			—
ComEd	238			235
PECO	45			42
BGE	1			—
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 $13 million at both March 31, 2015 and December 31, 2014. In addition, a private party asserted claims relating to groundwater contamination. In February 2014, Generation settled these private party claims for an amount that was not material to the financial condition of Generation.
Air Quality
Notices and Finding of Violations and Midwest Generation Bankruptcy.   In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale. In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business, including its rights and obligations under the sale agreement with Midwest Generation and EME.
Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement.
On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code.
In 2012, the Bankruptcy Court approved the rejection of an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations thereunder. A settlement was reached in January 2015, to resolve the claims related to the coal rail car lease for approximately $14 million and Exelon recorded a gain upon receipt of the funds, within Operating and maintenance expense in Exelon and Generation's Consolidated Statement of Operations and Comprehensive Income. No further action is expected related to the rail car lease.
On March 11, 2014, the Bankruptcy Court for the Northern District of Illinois entered its Order Confirming Debtors’ Joint Chapter 11 Plan of Reorganization. On April 1, 2014 (Effective Date), NRG Energy purchased EME’s portfolio of generation, including Midwest Generation and the Joint Chapter 11 Plan of Reorganization (Plan) became effective. As part of the Plan, the sale agreement, including the environmental indemnity, and the asbestos cost-sharing agreement were rejected.
Generation increased its reserve for asbestos-related bodily injury claims pertaining to Midwest Generations’ share of liability as a result of the rejection of the asbestos cost sharing agreement in the bankruptcy proceedings. Exelon and Generation may be entitled to damages associated with the rejection of the agreement and a claim has been filed by Exelon for such damages. These amounts are considered to be contingent gains and would not be recognized until realized.
As a prior owner of the generating stations, ComEd (and Generation, through its agreement in Exelon’s 2001 corporate restructuring to assume ComEd’s rights and obligations associated with its former generation business) could face liability (along with any other potentially responsible parties) for environmental conditions at the stations requiring remediation, with the determination of the allocation among the parties subject to many uncertain factors. ComEd and Generation are unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations and as a result no liability has been recorded as of March 31, 2015. Any liability imposed on ComEd or Generation for environmental matters relating to the generating stations could have a material adverse impact on their future results of operations and cash flows.
Solid and Hazardous Waste
Cotter Corporation.   The U.S. EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. On February 18, 2000, ComEd sold Cotter to an unaffiliated third- party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. On May 29, 2008, the U.S. EPA issued a Record of Decision approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. By letter dated January 11, 2010, the U.S. EPA requested that the PRPs perform a supplemental feasibility study for a remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the final supplemental feasibility study to the U.S. EPA for review. In June 2012, the U.S. EPA requested that the PRPs perform additional analysis and groundwater sampling as part of the supplemental feasibility study, and subsequently requested additional analysis sampling and modeling that will be conducted throughout 2015. In light of these additional requests, it is unknown when the U.S EPA will propose a remedy for public comment, but will likely be sometime in 2016 at the earliest. Thereafter the U.S. EPA will select a final remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. A complete excavation remedy would be significantly more expensive than the previously selected additional cover remedy; however, Generation believes the likelihood that the U.S. EPA would require a complete excavation remedy is remote. The current estimated cost of the landfill cover remediation for the site is approximately $50 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million. The DOJ and the PRPs agreed to toll the statute of limitations until August 2015 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this liability.
On February 28, 2012, and April 12, 2012, two lawsuits were filed in the U.S. District Court for the Eastern District of Missouri against 15 and 14 defendants, respectively, including Exelon, Generation and ComEd (the Exelon defendants) and Cotter. The suits allege that individuals living in the North St. Louis area developed some form of cancer due to the Exelon defendants’ negligent or reckless conduct in processing, transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs have asserted claims for negligence, strict liability, emotional distress, medical monitoring, and violations of the Price-Anderson Act. The complaints do not contain specific damage claims. On May 30, 2012, the plaintiffs filed voluntary motions to dismiss the Exelon defendants from both lawsuits which were subsequently granted. Since May 30, 2012, several related lawsuits have been filed in the same court on behalf of various plaintiffs against Cotter and other defendants, but not Exelon. The allegations in these related lawsuits mirror the initially filed lawsuits. In the event of a finding of liability, it is reasonably possible that Exelon would be considered liable due to its indemnification responsibilities of Cotter described above. On March 27, 2013, the U.S. District Court dismissed all state common law actions brought under the initial two lawsuits; and also found that the plaintiffs had not properly brought the actions under the Price-Anderson Act. On July 8, 2013, the plaintiffs filed amended complaints under the Price-Anderson Act. Cotter moved to dismiss the amended complaints and has motions currently pending before the court. At this stage of the litigation, Exelon, Generation, and ComEd cannot estimate a range of loss, if any.
68th Street Dump.   In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities List, and notified BGE and 19 others that they are PRPs at the site. In March 2004, BGE and other PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and 19 of the PRPs, including BGE, with respect to investigation of the site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs estimated range of costs noted above. Based on Generation’s preliminary review, it appears probable that Generation has liability and has established an appropriate accrual for its share of the estimated clean-up costs. A wholly owned subsidiary of Generation has agreed to indemnify BGE for most of the costs related to this settlement and clean-up of the site.
Rossville Ash Site.    The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG). 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 $10 million, which has been fully reserved as of March 31, 2015.
Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk, Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at the site. On March 11, 2013, BGE and three other PRP’s signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA which requires the PRP’s to conduct a Remedial Investigation and Feasibility Study at the site to determine what, if any, are the appropriate and recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s reasonably possible loss, if any, cannot be determined.
Litigation and Regulatory Matters
Except to the extent noted below, the circumstances set forth in Note 22 of the Exelon 2014 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.
Asbestos Personal Injury Claims (Exelon, Generation, PECO and BGE)
Exelon and Generation.    Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.
At March 31, 2015 and December 31, 2014, Generation had reserved approximately $97 million and $100 million, respectively, in total for asbestos-related bodily injury claims. As of March 31, 2015, approximately $20 million of this amount related to 224 open claims presented to Generation, while the remaining $77 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary.
On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300 weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Currently, Exelon, Generation and PECO are unable to predict whether and to what extent they may experience additional claims in the future as a result of this ruling; as such no increase to the asbestos-related bodily injury liability has been recorded as of March 31, 2015. Increased claims activity resulting from this ruling could have a material adverse effect on Exelon’s, Generation’s and PECO’s future results of operations and cash flows.
BGE.  Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos. The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.
Approximately 467 individuals who were never employees of BGE or certain Constellation subsidiaries have pending claims each seeking several million dollars in compensatory and punitive damages. Cross-claims and third-party claims brought by other defendants may also be filed against BGE and certain Constellation subsidiaries in these actions. To date, most asbestos claims which have been resolved have been dismissed or resolved without any payment by BGE or certain Constellation subsidiaries and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s financial results.
Discovery begins in these cases after they are placed on the trial docket. At present, only two of the pending cases are set for trial. Given the limited discovery in these cases, BGE and Generation do not know the specific facts that are necessary to provide an estimate of the reasonably possible loss relating to these claims; as such, no accrual has been made and a range of loss is not estimable. The specific facts not known include:
•	the identity of the facilities at which the plaintiffs allegedly worked as contractors;
•	the names of the plaintiffs’ employers;
•	the dates on which and the places where the exposure allegedly occurred; and
•	the facts and circumstances relating to the alleged exposure.
Insurance and hold harmless agreements from contractors who employed the plaintiffs may cover a portion of any awards in the actions.
Continuous Power Interruption (ComEd)
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power interruption of four hours or more that affects (in ComEd’s case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the law.
On August 18, 2011, ComEd sought from the ICC a determination that ComEd is not liable for damage compensation to customers in connection with the July 11, 2011 storm system that produced multiple power interruptions that in the aggregate affected more than 900,000 customers in ComEd’s service territory, as well as for five other storm systems that affected ComEd’s customers during June and July 2011 (Summer 2011 Storm Docket). In addition, on September 29, 2011, ComEd sought from the ICC a determination that it was not liable for damage compensation related to the February 1, 2011 blizzard (February 2011 Blizzard Docket).
On June 5, 2013, the ICC approved a complete waiver of liability for five of the six summer storms and the February 2011 blizzard. The ICC held that for the July 11, 2011 storm, 34,559 interruptions were preventable and therefore no waiver should apply. As required by the ICC’s Order, ComEd notified relevant customers that they may be entitled to seek reimbursement of incurred costs in accordance with a claims procedure established under ICC rules and regulations. On July 31, 2014, the Illinois Appellate Court reaffirmed the ICC’s decision in ComEd’s appeal of the Summer 2011 Storm Docket and dismissed ComEd’s appeal of the February 2011 Blizzard Docket. The Illinois Supreme Court denied ComEd's request to hear the matter. The ICC's order is now final and claims from impacted customers and municipalities are now eligible for review and reimbursement. ComEd is processing claims received to date.
In the second quarter of 2013, ComEd established a liability, which is not material, for potential reimbursements for actual damages incurred by the 34,559 customers covered by the ICC’s June 5, 2013 Order. The liability recorded represents the low end of a range of potential losses given that no amount within the range represents a better estimate. ComEd’s ultimate liability will be based on actual claims eligible for reimbursement. Although reimbursements for actual damages will differ from the estimated accrual recorded, at this time ComEd does not expect the difference to be material to ComEd’s results of operations or cash flows.
ComEd has not recorded an accrual for reimbursement of local governmental emergency and contingency expenses as a range of loss, if any, cannot be reasonably estimated at this time, but may be material to ComEd’s results of operations and cash flows.
Telephone Consumer Protection Act Lawsuit (ComEd)
On November 19, 2013, a class action complaint was filed in the Northern District of Illinois on behalf of a single individual and a presumptive class that would include all customers that ComEd enrolled in its Outage Alert text message program. The complaint alleges that ComEd violated the Telephone Consumer Protection Act (TCPA) by sending approximately 1.2 million text messages to customers without first obtaining their consent to receive such messages. The complaint seeks certification of a class along with statutory damages, attorneys’ fees, and an order prohibiting ComEd from sending additional text messages. Such statutory damages could range from $500 to $1,500 per text. In February 2014, ComEd filed a motion to dismiss this class action complaint, which was denied in June 2014. On February 19, 2015, ComEd and the plaintiff agreed in principle to settle the suit for $5 million, which ComEd has recorded as a liability as of March 31, 2015.  The parties are in process of obtaining the approval of the court and the class of customers represented in the suit.  As ComEd is unable to predict the ultimate outcome of this proceeding, actual damages may differ from the estimated amount recorded, which may be material to ComEd’s results of operations, cash flows, and financial position.
Baltimore City Franchise Taxes (BGE)
The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City's claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.
General (Exelon, Generation, ComEd, PECO and BGE)
The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
See Note 10 — 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_Informa

Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Supplemental Financial Information [Abstract]
Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)	Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)
	Supplemental Statement of Operations Information
	The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2015 and 2014:
	Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
	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	(106		)		(106		)		—			—				—
	activities(b)
	Total decommissioning-related activities	92				92				—			—				—
	Investment income (expense)	1				1				—			—				1			(c)
	Long-term lease income	4				—				—			—				—
	Interest income related to uncertain income tax positions	—				1				—			—				—
	AFUDC — Equity	5				—				—			2				3
	Terminated interest rate swaps (d)	(23		)		3				—			—				—
	Other	1				(3		)		3			—				—
	Other, net	$	80			$	94			$	3		$	2			$	4
	Three Months Ended March 31, 2014	Exelon				Generation				ComEd			PECO				BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust funds(a)
	Regulatory agreement units	$	43			$	43			$	—		$	—			$	—
	Non-regulatory agreement units	25				25				—			—				—
	Net unrealized gains on decommissioning trust funds
	Regulatory agreement units	61				61				—			—				—
	Non-regulatory agreement units	13				13				—			—				—
	Net unrealized losses on pledged assets
	Zion Station decommissioning	10				10				—			—				—
	Regulatory offset to decommissioning trust fund-related	(94		)		(94		)		—			—				—
	activities(b)
	Total decommissioning-related activities	58				58				—			—				—
	Investment income (expense)	1				1				—			—				2			(c)
	Long-term lease income	6				—				—			—				—
	Interest income related to uncertain income tax positions	10				14				—			—				—
	AFUDC — Equity	6				—				3			1				3
	Other	17				12				2			1				(1		)
	Other, net	$	98			$	85			$	5		$	2			$	4
	________
	(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.
	(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2014 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 2014 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 are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
	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, 2015 and 2014:
	Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
	Depreciation, amortization, accretion and depletion
	Property, plant and equipment	$	540			$	242			$	154		$	58			$	71
	Regulatory assets	58				—				21			4				35
	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
	Three Months Ended March 31, 2014	Exelon				Generation				ComEd			PECO				BGE
	Depreciation, amortization, accretion and depletion
	Property, plant and equipment	$	481			$	200			$	143		$	56			$	70
	Regulatory assets	72				—				30			2				38
Amortization of intangible assets, net	11				11				—			—				—
Amortization of energy contract assets and liabilities(a)	42				44				—			—				—
Nuclear fuel(b)	234				234				—			—				—
ARO accretion(c)	68				68				—			—				—
Total depreciation, amortization, accretion and depletion	$	908			$	557			$	173		$	58			$	108
_________
(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.
Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	159			$	67			$	52		$	10			$	16
Provision for uncollectible accounts	84				4				22			33				25
Stock-based compensation costs	39				—				—			—				—
Other decommissioning-related activity(a)	(44		)		(44		)		—			—				—
Energy-related options(b)	9				9				—			—				—
Amortization of regulatory asset related to debt costs	3				—				2			1				—
Amortization of rate stabilization deferral	25				—				—			—				25
Amortization of debt fair value adjustment	(9		)		(4		)		—			—				—
Discrete impacts of 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		)
Total other non-cash operating activities	$	344			$	45			$	126		$	44			$	64
Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	65			$	—			$	—		$	26			$	39
Other regulatory assets and liabilities	92				—				2			(5		)		25
Cash deposits(d)	226				226				—			—				—
Other current assets	(155		)		(100		)		(1		)	(95		)	(e)	30
Other noncurrent assets and liabilities	(113		)		(41		)		(10		)	2				(1		)
Total changes in other assets and liabilities	$	115			$	85			$	(9	)	$	(72	)		$	93
Non-cash investing and financing activities:
Indemnification of like-kind exchange position(f)	—				—				2			—				—
Total non-cash investing and financing activities:	$	—			$	—			$	2		$	—			$	—
Three Months Ended March 31, 2014	Exelon				Generation				ComEd			PECO				BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	173			$	75			$	56		$	12			$	16
Equity method investments	19				19				—			—				—
Provision for uncollectible accounts	35				1				(11		)	35				11
Stock-based compensation costs	46				—				—			—				—
Other decommissioning-related activity(a)	(35		)		(35		)		—			—				—
Energy-related options(b)	31				31				—			—				—
Amortization of regulatory asset related to debt costs	3				—				2			1				—
Amortization of rate stabilization deferral	20				—				—			—				20
Amortization of debt fair value adjustment	(12		)		(5		)		—			—				—
Discrete impacts from EIMA(c)	(4		)		—				(4		)	—				—
Amortization of debt costs	5				3				(5		)	1				—
Increase in inventory reserve	2				2				—			—				—
Other	(7		)		(2		)		(2		)	—				(4		)
Total other non-cash operating activities	$	276			$	89			$	36		$	49			$	43
Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(15	)		$	—			$	4		$	(17	)		$	23
Other regulatory assets and liabilities	(4		)		—				(10		)	(3		)		6
Other current assets	(209		)		(80		)		(29		)	(105		)	(e)	18
Other noncurrent assets and liabilities	(50		)		(23		)		11			(2		)		(3		)
Total changes in other assets and liabilities	$	(278	)		$	(103	)		$	(24	)	$	(127	)		$	44
Non-cash investing and financing activities:
Indemnification of like-kind exchange position(f)	—				—				2			—				—
Total non-cash investing and financing activities	$	—			$	—			$	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 15 — Asset Retirement Obligations of the Exelon 2014 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.
(d)	Relates primarily to cash deposits recalled from ISOs/RTOs and replaced with letters of credit.
(e)	Relates primarily to prepaid utility taxes.
(f)	See Note 10 — Income Taxes for discussion of the like-kind exchange tax position.
DOE Smart Grid Investment Grant (Exelon and PECO).    For the three months ended March 31, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $2 million related to PECO’s DOE SGIG programs. For the three months ended March 31, 2015 PECO had no capital expenditures or reimbursements, as the DOE SGIG program was completed during 2014. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information regarding the DOE SGIG.
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants as of March 31, 2015 and December 31, 2014.
31-Mar-15	Exelon				Generation				ComEd			PECO				BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	15,207		(a)	$	7,905		(a)	$	3,247		$	2,989			$	2,905
Accounts receivable:
Allowance for uncollectible accounts	$	365			$	61			$	100		$	127			$	84
31-Dec-14	Exelon				Generation				ComEd			PECO				BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	14,742		(b)	$	7,612		(b)	$	3,432		$	2,917			$	2,868
Accounts receivable:
Allowance for uncollectible accounts	$	311			$	60			$	84		$	100			$	67
_______
(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,772 million.
(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 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, 2015 and December 31, 2014, 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 2014 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at March 31, 2015 of $14 million consists of $1 million, $4 million and $9 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2014 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of March 31, 2015 and December 31, 2014 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2014 Form 10-K.

Segment_Information_Exelon_Gen

Segment Information (Exelon, Generation, ComEd, PECO and BGE)	3 Months Ended
	Mar. 31, 2015
Segment Reporting [Abstract]
Segment Information (Exelon, Generation, ComEd, PECO and BGE)	Segment Information (Exelon, Generation, ComEd, PECO and BGE)
	Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to evaluate performance and allocate resources at each of the Registrants.
	Exelon has nine reportable segments, ComEd, PECO, BGE and Generation’s six power marketing reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions not considered individually significant and referred to collectively as “Other Power Regions”; which includes activities in the South, West and Canada. ComEd, PECO and BGE each represent a single reportable segment; as such, no separate segment information is provided for these Registrants. Exelon’s CODM evaluates the performance of and allocates resources to ComEd, PECO and BGE based on net income and return on equity.
	The CODMs for ComEd, PECO, and BGE evaluate performance and allocate resources for their respective companies based on net income and return on equity for ComEd, PECO, and BGE each as single integrated businesses.
	The foundation of Generation’s six reportable segments is based on the geographic location of its assets, and is largely representative of the footprints of an ISO / RTO and/or NERC region. Descriptions of each of Generation’s six reportable segments are as follows:
	•	Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of North Carolina.
	•	Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and Tennessee, and the United States footprint of MISO excluding MISO’s Southern Region, which covers all or most of North Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM, and parts of Montana, Missouri and Kentucky.
	•	New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode Island and Vermont.
	•	New York represents operations within ISO-NY, which covers the state of New York in its entirety.
	•	ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
	•	Other Power Regions not considered individually significant:
	◦	South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP, covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
	◦	West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington, Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.
	◦	Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of MISO.
	The CODMs for Exelon and Generation evaluate the performance of Generation’s power marketing activities and allocate resources based on revenue net of purchased power and fuel expense. Generation believes that revenue net of purchased power and fuel expense is a useful measurement of operational performance. Revenue net of purchased power and fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all sales to third parties and sales to its affiliates, ComEd, PECO and BGE. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. Generation's other business activities, including retail and wholesale gas, investments in gas and oil exploration and production activities, proprietary trading, compressed natural gas fueling stations, energy efficiency and cogeneration projects, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, indoor quality systems and home improvements, and investments in energy-related proprietary technology are not allocated to regions. Further, Generation’s other miscellaneous revenues, unrealized mark-to-market impact of economic hedging activities, and amortization of certain intangible assets relating to commodity contracts recorded at fair value from prior acquisitions are also not allocated to a region. 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, 2015 and 2014 is as follows:
		Generation(a)				ComEd				PECO			BGE				Other(b)				Intersegment Eliminations				Exelon
	Total revenues(c):
	2015	$	5,840			$	1,185			$	985		$	1,036			$	318			$	(534	)		$	8,830
	2014	4,390				1,134				993			1,054				290				(624		)		7,237
	Intersegment revenues(d):
	2015	$	210			$	1			$	—		$	7			$	316			$	(533	)		$	1
	2014	316				1				1			16				290				(623		)		1
	Net income (loss):
	2015	$	485			$	90			$	139		$	109			$	(84	)		$	(1	)		$	738
	2014	(185		)		98				89			88				4				(1		)		93
	Total assets:
	March 31, 2015	$	45,318			$	25,731			$	10,169		$	8,130			$	10,457			$	(12,414	)		$	87,391
	December 31, 2014	45,348				25,392				9,943			8,078				9,794				(11,741		)		86,814
	__________
	(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, 2015 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. For the three months ended March 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $88 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $108 million in the Midwest region.
	(b)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
	(c)	For the three months ended March 31, 2015 and 2014, utility taxes of $27 million and $24 million, respectively, are included in revenues and expenses for Generation. For the three months ended March 31, 2015 and 2014, utility taxes of $62 million and $63 million, respectively, are included in revenues and expenses for ComEd. For the three months ended March 31, 2015 and 2014, utility taxes of $35 million and $35 million, respectively, are included in revenues and expenses for PECO. For the three months ended March 31, 2015 and 2014, utility taxes of $52 million and $20 million, respectively, are included in revenues and expenses for BGE.
	(d)	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
	Generation total revenues:
		Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
		Revenues				Intersegment				Total			Revenues				Intersegment				Total
		from external				revenues				Revenues(a)			from external				revenues				Revenues
		customers(b)											customers(b)
	Mid-Atlantic	$	1,517			$	(4	)		$	1,513		$	1,441			$	(23	)		$	1,418
	Midwest	1,275				1				1,276			1,258				12				1,270
	New England	858				1				859			545				4				549
	New York	310				—				310			190				(3		)		187
	ERCOT	182				(2		)		180			243				—				243
	Other Power Regions(c)	212				2				214			334				7				341
	Total Revenues for Reportable Segments	4,354				(2		)		4,352			4,011				(3		)		4,008
	Other(d)	1,486				2				1,488			379				3				382
	Total Generation Consolidated Operating Revenues	$	5,840			$	—			$	5,840		$	4,390			$	—			$	4,390
	__________
	(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, the 2015 financial results include CENG's revenues on a fully consolidated basis.
	(b)	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
	(c)	Other Power Regions include the South, West and Canada, which are not considered individually significant.
	(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $40 million increase to revenues and $93 million decrease to revenues, for the three months ended March 31, 2015 and 2014, respectively, unrealized mark-to-market gains of $154 million and losses of $760 million for the three months ended March 31, 2015 and 2014, respectively, and elimination of intersegment revenues.
	Generation total revenues net of purchased power and fuel expense:
		Three Months Ended March 31, 2015												Three Months Ended March 31, 2014
		RNF					Intersegment				Total			RNF				Intersegment				Total
		from external					RNF				RNF(a)			from external				RNF				RNF
		customers(b)												customers(b)
	Mid-Atlantic	$	784				$	(2	)		$	782		$	784			$	(89	)		$	695
	Midwest	701					(1		)		700			530				26				556
	New England	177					(19		)		158			154				(18		)		136
	New York	174					14				188			(29		)		8				(21		)
	ERCOT	88					(33		)		55			155				(72		)		83
	Other Power Regions(c)	99					(53		)		46			150				(45		)		105
Total Revenues net of purchased power and fuel expense for Reportable Segments	2,023			—		(94		)		1,929			1,744				(190		)		1,554
Other(d)	384					94				478			(711		)		190				(521		)
Total Generation Revenues net of purchased power and fuel expense	$	2,407		—		$	—			$	2,407		$	1,033			$	—			$	1,033
__________
(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, the 2015 financial results include CENG's revenue net of purchased power and fuel expense on a fully consolidated basis.
(b)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
(c)	Other Power Regions include the South, West and Canada, which are not considered individually significant.
(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $38 million increase to RNF and $42 million decrease to RNF for the three months ended March 31, 2015 and 2014, respectively, unrealized mark-to-market gains of $162 million and losses of $730 million for the three months ended March 31, 2015 and 2014, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

Subsequent_Events_Exelon_and_G

Subsequent Events (Exelon and Generation)	3 Months Ended
	Mar. 31, 2015
Subsequent Events [Abstract]
Subsequent Events (Exelon and Generation)	Subsequent Event (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_Basis_of

Basis of Presentation Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2015
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Fair Value Assets Measured On Recurring Basis Investments Valuation Techniques	.
Fair Value Assets Measured On Recurring Basis Cash And Cash Equivalents Valuation Techniques
Fair Value Assets Measured On Recurring Basis Nuclear Decommissioning Trust Fund Investments Valuation Techniques	As of March 31, 2015, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $265 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.
Fair Value Assets And Liabilities Measured On Recurring Basis Derivative Financial Instruments Assets And Liabilities Valuation Techniques	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 8 - Derivative Financial Instruments for further discussion on mark-to-market derivatives.
Fair Value Liabilities Measured On Recurring Basis Obligations Valuation Techniques	Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE).    The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

New_Accounting_Pronouncements_1

New Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 2015
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]
New Accounting Pronouncements	New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)
	The following recently issued accounting standards are not yet required to be reflected in the combined financial statements of the Registrants.
	Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement
	In April 2015, the FASB issued authoritative guidance that clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any time during the hosting period without significant penalty and (2) it is feasible for the customer to either run the software on its own hardware or contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be accounted for as a service contract. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted. The guidance can be applied retrospectively to each prior reporting period presented or prospectively to arrangements entered into, or materially modified, after the effective date. The Registrants are currently assessing the impact this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance.
	Simplifying the Presentation of Debt Issuance Costs
	In April 2015, the FASB issued authoritative guidance that changes the presentation of debt issuance costs in financial statements. The new guidance requires entity’s to present such costs in the balance sheet as a direct reduction to the related debt liability rather than as a deferred cost (i.e., an asset) as required by current guidance. The new standard does not change the recognition or measurement of debt issuance costs. The guidance is effective for the Registrants for fiscal years beginning after December 15, 2015. Early adoption is permitted for financial statements that have not been previously issued. The guidance is required to be applied retrospectively to all prior periods presented. The Registrants are currently assessing the impact this guidance may have on their financial positions and disclosures, as well as whether to early adopt. The standard will not impact the results of operations and cash flows of the Registrants.
	Amendments to the Consolidation Analysis
	In February 2015, the FASB issued authoritative guidance that amends the consolidation analysis for variable interest entities (VIEs) as well as voting interest entities. The new guidance primarily (1) changes the assessment of limited partnerships as VIEs, (2) amends the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group) have power over an entity and (5) provides a scope exception for registered and similar unregistered money market funds. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2015. Early adoption is permitted. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method). The Registrants are currently assessing the impact this guidance may have on their financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. The Registrants do not plan to early adopt the standard.
	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 guidance 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 financial positions, results of operations, cash flows and disclosures as well as the transition method that they will use to adopt the guidance. The guidance is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016; and early adoption would not be permitted.  However, in April 2015, FASB proposed a one year deferral of the effective date to annual reporting periods beginning on or after December 15, 2017. In addition, the FASB proposal would include an option to early adopt the guidance for annual periods beginning on or after December 15, 2016.

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	3 Months Ended
	Mar. 31, 2015
Variable Interest Entity [Abstract]
Schedule of Variable Interest Entities	The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
	31-Mar-15	Commercial			Equity			Total
		Agreement			Investment
		VIEs			VIEs
	Total assets(a)	$	259		$	85		$	344
	Total liabilities(a)	32			47			79
	Exelon's ownership interest in VIE(a)	—			9			9
	Other ownership interests in VIE(a)	227			29			256
	Registrants’ maximum exposure to loss:
	Carrying amount of equity method investments	—			13			13
	Contract intangible asset	9			—			9
	Debt and payment guarantees	—			3			3
	Net assets pledged for Zion Station decommissioning(b)	27			—			27
	31-Dec-14	Commercial			Equity			Total
		Agreement			Investment
		VIEs			VIEs
	Total assets(a)	$	506		$	91		$	597
	Total liabilities(a)	237			49			286
	Exelon's ownership interest in VIE(a)	—			9			9
	Other ownership interests in VIE(a)	269			33			302
	Registrants’ maximum exposure to loss:
	Carrying amount of equity method investments	—			13			13
	Contract intangible asset	9			—			9
	Debt and payment guarantees	—			3			3
	Net assets pledged for Zion Station decommissioning(b)	27			—			27
	___________________
	(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
	(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 include, gross pledged assets of $308 million and $319 million as of March 31, 2015 and December 31, 2014, respectively; offset by payables to ZionSolutions, LLC of $281 million and $292 million as of March 31, 2015 and December 31, 2014, respectively. These items are included to provide information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE.
	The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in Exelon’s, Generation’s, and BGE’s consolidated financial statements at March 31, 2015 and December 31, 2014 are as follows:
		31-Mar-15									31-Dec-14
		Exelon(a)			Generation			BGE			Exelon(a)			Generation			BGE
	Current assets	$	1,185		$	1,134		$	46		$	1,271		$	1,242		$	21
	Noncurrent assets	7,676			7,664			3			7,580			7,566			3
	Total assets	$	8,861		$	8,798		$	49		$	8,851		$	8,808		$	24
	Current liabilities	$	520		$	434		$	80		$	611		$	526		$	77
	Noncurrent liabilities	2,812			2,682			120			2,730			2,600			120
	Total liabilities	$	3,332		$	3,116		$	200		$	3,341		$	3,126		$	197
	_______________________
	(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
			March 31, 2015									December 31, 2014
			Exelon			Generation			BGE			Exelon			Generation				BGE
	Cash and cash equivalents		$	334		$	334		$	—		$	392		$	392		$	—
	Restricted cash			159			113			46			117			96			21
	Accounts receivable, net
		Customer		296			296			—			297			297			—
		Other		33			33			—			57			57			—
	Mark-to-market derivatives assets			130			130			—			171			171			—
	Inventory
		Materials and supplies		168			168			—			172			172			—
	Other current assets			40			34			—			33			26			—
		Total current assets		1,160			1,108			46			1,239			1,211			21
	Property, plant and equipment, net			4,720			4,720			—			4,638			4,638			—
	Nuclear decommissioning trust funds			2,114			2,114			—			2,097			2,097			—
	Goodwill			47			47			—			47			47			—
	Mark-to-market derivatives assets			51			51			—			44			44			—
	Other noncurrent assets			90			78			3			95			82			3
	Total noncurrent assets			7,022			7,010			3			6,921			6,908			3
		Total assets	$	8,182		$	8,118		$	49		$	8,160		$	8,119		$	24
	Long-term debt due within one year		$	85		$	5		$	75		$	87		$	5		$	75
	Accounts payable			268			268			—			292			292			—
	Accrued expenses			77			71			5			111			108			2
	Mark-to-market derivative liabilities			10			10			—			24			24			—
	Unamortized energy contract liabilities			9			9			—			22			22			—
	Other current liabilities			18			18			—			25			25			—
	Total current liabilities		467			381			80			561			476			77
Long-term debt			211			81			120			212			81			120
Asset retirement obligations			1,843			1,843			—			1,763			1,763			—
Pension obligation(a)			9			9			—			9			9			—
Unamortized energy contract liabilities			48			48			—			51			51			—
	Other noncurrent liabilities		124			124			—			127			127			—
	Noncurrent liabilities		2,235			2,105			120			2,162			2,031			120
	Total liabilities	$	2,702		$	2,486		$	200		$	2,723		$	2,507		$	197
______________
(a)	Includes 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 12 — Retirement Benefits for additional details.

Regulatory_Matters_Tables

Regulatory Matters (Tables)	3 Months Ended
	Mar. 31, 2015
Regulated Operations [Abstract]
Schedule of Regulatory Assets
	31-Mar-15		Exelon			ComEd			PECO			BGE
	Regulatory liabilities
	Other postretirement benefits		$	72		$	—		$	—		$	—
	Nuclear decommissioning		2,920			2,420			500			—
	Removal costs		1,567			1,351			—			216
	Energy efficiency and demand response programs		27			25			2			—
	DLC Program Costs		10			—			10			—
	Energy efficiency Phase 2		38			—			38			—
	Electric distribution tax repairs		106			—			106			—
	Gas distribution tax repairs		34			—			34			—
	Energy and transmission programs(b)(c)(d)		142			23			84			35
	Over-recovered electric universal service fund costs		3			—			3			—
	Revenue subject to refund		3			3			—			—
	Over-recovered revenue decoupling(e)		56			—			—			56
	Other		9			1			4			4
	Total regulatory liabilities		4,987			3,823			781			311
	Less: current portion		421			131			119			124
	Total noncurrent regulatory liabilities		$	4,566		$	3,692		$	662		$	187
	31-Dec-14		Exelon			ComEd			PECO			BGE
	Regulatory assets
	Pension and other postretirement benefits		$	3,256		$	—		$	—		$	—
	Deferred income taxes		1,542			64			1,400			78
	AMI programs		296			91			77			128
	Under-recovered distribution service costs(a)		371			371			—			—
	Debt costs		57			53			4			9
	Fair value of BGE long-term debt		190			—			—			—
	Severance		12			—			—			12
	Asset retirement obligations		116			74			26			16
	MGP remediation costs		257			219			37			1
	Under-recovered uncollectible accounts		67			67			—			—
	Renewable energy		207			207			—			—
	Energy and transmission programs(b)(c)		48			33			—			15
	Deferred storm costs		3			—			—			3
	Electric generation-related regulatory asset		30			—			—			30
	Rate stabilization deferral		160			—			—			160
	Energy efficiency and demand response programs		248			—			—			248
	Merger integration costs		8			—			—			8
	Conservation voltage reduction		2			—			—			2
	Under recovered electric revenue decoupling		7			—			—			7
	Other		46			22			14			7
	Total regulatory assets		6,923			1,201			1,558			724
	Less: current portion		847			349			29			214
	Total noncurrent regulatory assets		$	6,076		$	852		$	1,529		$	510
	31-Dec-14		Exelon			ComEd			PECO			BGE
	Regulatory liabilities
	Other postretirement benefits		$	88		$	—		$	—		$	—
	Nuclear decommissioning		2,879			2,389			490			—
	Removal costs		1,566			1,343			—			223
	Energy efficiency and demand response programs		27			25			2			—
	DLC Program Costs		10			—			10			—
	Energy efficiency phase II		32			—			32			—
	Electric distribution tax repairs		102			—			102			—
	Gas distribution tax repairs		49			—			49			—
	Energy and transmission programs(b)(c)(d)		84			19			58			7
	Over-recovered electric universal service fund costs		2			—			2			—
	Revenue subject to refund		3			3			—			—
	Over-recovered revenue decoupling(e)		12			—			—			12
	Other		6			1			2			2
	Total regulatory liabilities		4,860			3,780			747			244
	Less: current portion		310			125			90			44
	Total noncurrent regulatory liabilities		$	4,550		$	3,655		$	657		$	200
	________________
	(a)	As of March 31, 2015, ComEd’s regulatory asset of $316 million was comprised of $240 million for the applicable annual reconciliations and $76 million related to significant one-time events including $59 million of deferred storm costs and $17 million of Constellation merger and integration related costs.  As of December 31, 2014, ComEd’s regulatory asset of $371 million was comprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events, including $66 million of deferred storm costs and $19 million of Constellation merger and integration related costs. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for further information.
(b)	As of March 31, 2015, ComEd’s regulatory asset of $37 million included $5 million related to under-recovered energy costs for non-hourly customers, $25 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, 2015, ComEd’s regulatory liability of $23 million included $5 million related to over-recovered energy costs for hourly customers and $18 million associated with revenues received for renewable energy requirements. As of December 31, 2014, ComEd’s regulatory asset of $33 million included $4 million related to under-recovered energy costs for non-hourly customers, $22 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, 2014, ComEd’s regulatory liability of $19 million included $3 million related to over-recovered energy costs for hourly customers and $16 million associated with revenues received for renewable energy requirements.
(c)	As of March 31, 2015, BGE's regulatory asset of $4 million included $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval, partially offset by $1 million related to over-recovered electric energy costs. As of March 31, 2015, BGE's regulatory liability of $35 million related to $31 million of over-recovered natural gas supply costs and $4 million of over-recovered electric energy costs. As of December 31, 2014, BGE's regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE's regulatory liability of $7 million related to over-recovered natural gas supply costs.
(d)	At PECO, includes $42 million related to the DSP program, $34 million related to the over-recovered natural gas costs under the PGC and $8 million related to over-recovered electric transmission costs as of March 31, 2015. As of December 31, 2014, includes $39 million related to the DSP program, $16 million related to the over-recovered electric transmission costs and $3 million related to the over-recovered natural gas costs under the PGC.
(e)	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2015, BGE had a regulatory liability of $19 million related to over-recovered electric revenue decoupling and a regulatory liability of $37 million related to over-recovered natural gas revenue decoupling. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling.
Schedule of Regulatory Liabilities
	31-Mar-15		Exelon			ComEd			PECO			BGE
	Regulatory liabilities
	Other postretirement benefits		$	72		$	—		$	—		$	—
	Nuclear decommissioning		2,920			2,420			500			—
	Removal costs		1,567			1,351			—			216
	Energy efficiency and demand response programs		27			25			2			—
	DLC Program Costs		10			—			10			—
	Energy efficiency Phase 2		38			—			38			—
	Electric distribution tax repairs		106			—			106			—
	Gas distribution tax repairs		34			—			34			—
	Energy and transmission programs(b)(c)(d)		142			23			84			35
	Over-recovered electric universal service fund costs		3			—			3			—
	Revenue subject to refund		3			3			—			—
	Over-recovered revenue decoupling(e)		56			—			—			56
	Other		9			1			4			4
	Total regulatory liabilities		4,987			3,823			781			311
	Less: current portion		421			131			119			124
	Total noncurrent regulatory liabilities		$	4,566		$	3,692		$	662		$	187
	31-Dec-14		Exelon			ComEd			PECO			BGE
	Regulatory assets
	Pension and other postretirement benefits		$	3,256		$	—		$	—		$	—
	Deferred income taxes		1,542			64			1,400			78
	AMI programs		296			91			77			128
	Under-recovered distribution service costs(a)		371			371			—			—
	Debt costs		57			53			4			9
	Fair value of BGE long-term debt		190			—			—			—
	Severance		12			—			—			12
	Asset retirement obligations		116			74			26			16
	MGP remediation costs		257			219			37			1
	Under-recovered uncollectible accounts		67			67			—			—
	Renewable energy		207			207			—			—
	Energy and transmission programs(b)(c)		48			33			—			15
	Deferred storm costs		3			—			—			3
	Electric generation-related regulatory asset		30			—			—			30
	Rate stabilization deferral		160			—			—			160
	Energy efficiency and demand response programs		248			—			—			248
	Merger integration costs		8			—			—			8
	Conservation voltage reduction		2			—			—			2
	Under recovered electric revenue decoupling		7			—			—			7
	Other		46			22			14			7
	Total regulatory assets		6,923			1,201			1,558			724
	Less: current portion		847			349			29			214
	Total noncurrent regulatory assets		$	6,076		$	852		$	1,529		$	510
	31-Dec-14		Exelon			ComEd			PECO			BGE
	Regulatory liabilities
	Other postretirement benefits		$	88		$	—		$	—		$	—
	Nuclear decommissioning		2,879			2,389			490			—
	Removal costs		1,566			1,343			—			223
	Energy efficiency and demand response programs		27			25			2			—
	DLC Program Costs		10			—			10			—
	Energy efficiency phase II		32			—			32			—
	Electric distribution tax repairs		102			—			102			—
	Gas distribution tax repairs		49			—			49			—
	Energy and transmission programs(b)(c)(d)		84			19			58			7
	Over-recovered electric universal service fund costs		2			—			2			—
	Revenue subject to refund		3			3			—			—
	Over-recovered revenue decoupling(e)		12			—			—			12
	Other		6			1			2			2
	Total regulatory liabilities		4,860			3,780			747			244
	Less: current portion		310			125			90			44
	Total noncurrent regulatory liabilities		$	4,550		$	3,655		$	657		$	200
	________________
	(a)	As of March 31, 2015, ComEd’s regulatory asset of $316 million was comprised of $240 million for the applicable annual reconciliations and $76 million related to significant one-time events including $59 million of deferred storm costs and $17 million of Constellation merger and integration related costs.  As of December 31, 2014, ComEd’s regulatory asset of $371 million was comprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events, including $66 million of deferred storm costs and $19 million of Constellation merger and integration related costs. See Note 4 — Mergers, Acquisitions, and Dispositions of the Exelon 2014 Form 10-K for further information.
(b)	As of March 31, 2015, ComEd’s regulatory asset of $37 million included $5 million related to under-recovered energy costs for non-hourly customers, $25 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, 2015, ComEd’s regulatory liability of $23 million included $5 million related to over-recovered energy costs for hourly customers and $18 million associated with revenues received for renewable energy requirements. As of December 31, 2014, ComEd’s regulatory asset of $33 million included $4 million related to under-recovered energy costs for non-hourly customers, $22 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, 2014, ComEd’s regulatory liability of $19 million included $3 million related to over-recovered energy costs for hourly customers and $16 million associated with revenues received for renewable energy requirements.
(c)	As of March 31, 2015, BGE's regulatory asset of $4 million included $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval, partially offset by $1 million related to over-recovered electric energy costs. As of March 31, 2015, BGE's regulatory liability of $35 million related to $31 million of over-recovered natural gas supply costs and $4 million of over-recovered electric energy costs. As of December 31, 2014, BGE's regulatory asset of $15 million included $10 million related to under-recovered electric energy costs, $4 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2014, BGE's regulatory liability of $7 million related to over-recovered natural gas supply costs.
(d)	At PECO, includes $42 million related to the DSP program, $34 million related to the over-recovered natural gas costs under the PGC and $8 million related to over-recovered electric transmission costs as of March 31, 2015. As of December 31, 2014, includes $39 million related to the DSP program, $16 million related to the over-recovered electric transmission costs and $3 million related to the over-recovered natural gas costs under the PGC.
(e)	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of March 31, 2015, BGE had a regulatory liability of $19 million related to over-recovered electric revenue decoupling and a regulatory liability of $37 million related to over-recovered natural gas revenue decoupling. As of December 31, 2014, BGE had a regulatory asset of $7 million related to under-recovered electric revenue decoupling and a regulatory liability of $12 million related to over-recovered natural gas revenue decoupling.
Purchase Of Receivables
	As of December 31, 2014	Exelon			ComEd			PECO			BGE
	Purchased receivables(a)	$	290		$	139		$	76		$	75
	Allowance for uncollectible accounts(b)	(42		)	(21		)	(8		)	(13		)
	Purchased receivables, net	$	248		$	118		$	68		$	62
	_________
	(a)	PECO’s gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.
	(b)	For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

Investment_in_Constellation_En1

Investment in Constellation Energy Nuclear Group, LLC (Tables) (Exelon Generation Co L L C [Member])	Mar. 31, 2014
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	50.01%

Fair_Value_of_Financial_Assets1

Fair Value of Financial Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2015
Fair Value Tables [Line Items]
Fair value of financial liabilities recorded at the carrying amount	The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of March 31, 2015 and December 31, 2014:
	Exelon
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	312			$	3			$	309			$	—			$	312
	Long-term debt (including amounts due within one year)	21,779				1,119				21,486				1,380				23,985
	Long-term debt to financing trusts	648				—				—				672				672
	SNF obligation	1,021				—				843				—				843
		31-Dec-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	463			$	3			$	448			$	12			$	463
	Long-term debt (including amounts due within one year)	21,164				1,208				20,417				1,311				22,936
	Long-term debt to financing trusts	648				—				—				648				648
	SNF obligation	1,021				—				833				—				833
Assets and liabilities measured and recorded at fair value on recurring basis	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, 2015 and December 31, 2014:
			Generation																Exelon
	As of March 31, 2015		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
	Assets
	Cash equivalents(a)		$	220			$	—			$	—			$	220			$	1,107				$	—				$	—				$	1,107
	Nuclear decommissioning trust fund investments
	Cash equivalents		224				40				—				264				224					40					—					264
	Equity
	Domestic		2,459				2,227				—				4,686				2,459					2,227					—					4,686
	Foreign		639				—				—				639				639					—					—					639
	Equity funds subtotal		3,098				2,227				—				5,325				3,098					2,227					—					5,325
	Fixed income
	Corporate debt		—				1,911				248				2,159				—					1,911					248					2,159
	U.S. Treasury and agencies		1,201				—				—				1,201				1,201					—					—					1,201
	Foreign governments		—				89				—				89				—					89					—					89
	State and municipal debt		—				423				—				423				—					423					—					423
	Other		—				488				—				488				—			—		488			—		—			—		488
	Fixed income subtotal		1,201				2,911				248				4,360				1,201					2,911					248					4,360
	Middle market lending		—				—				363				363				—					—					363					363
	Private Equity		—				—				95				95				—					—					95					95
	Real Estate		—				—				9				9				—			—		—			—		9					9
	Other		—				323				—				323				—					323					—					323
	Nuclear decommissioning trust fund investments subtotal(b)		4,523				5,501				715				10,739				4,523					5,501					715					10,739
			Generation																Exelon
	As of March 31, 2015		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
	Pledged assets for Zion Station decommissioning
	Cash equivalents		—				19				—				19				—					19					—					19
	Equities		6				1				—				7				6					1					—					7
	Fixed income
	U.S. Treasury and agencies		2				3				—				5				2					3					—					5
	Corporate debt		—				84				—				84				—					84					—					84
	State and municipal debt		—				10				—				10				—					10					—					10
	Other		—				4				—				4				—			—		4			—		—					4
	Fixed income subtotal		2				101				—				103				2					101					—					103
	Middle market lending		—				—				178				178				—					—					178					178
	Pledged assets for Zion Station		8				121				178				307				8					121					178					307
	decommissioning subtotal(c)
	Rabbi trust investments in mutual funds(d)(e)		16				—				—				16				48					—					—					48
	Commodity derivative assets
	Economic hedges		1,510				3,554				1,917				6,981				1,510					3,554					1,917					6,981
	Proprietary trading		176				286				39				501				176					286					39					501
	Effect of netting and allocation of collateral(f)		(1,899		)		(2,849		)		(740		)		(5,488		)		(1,899		)			(2,849		)			(740		)			(5,488		)
	Commodity derivative assets subtotal		(213		)		991				1,216				1,994				(213		)			991					1,216					1,994
	Interest rate and foreign currency derivative
	assets
	Derivatives designated as hedging instruments		—				—				—				—				—					32					—					32
	Economic hedges		—				27				—				27				—					29					—					29
	Proprietary trading		18				1				—				19				18					1					—					19
	Effect of netting and allocation of collateral		(8		)		(5		)		—				(13		)		(8		)			(36		)			—					(44		)
	Interest rate and foreign currency derivative		10				23				—				33				10					26					—					36
	assets subtotal
	Other investments		—				—				3				3				2					—					3					5
	Total assets		4,564				6,636				2,112				13,312				5,485					6,639					2,112					14,236
	Liabilities
	Commodity derivative liabilities
	Economic hedges		(2,126		)		(3,370		)		(1,025		)		(6,521		)		(2,126		)			(3,370		)			(1,266		)			(6,762		)
	Proprietary trading		(169		)		(295		)		(50		)		(514		)		(169		)			(295		)			(50		)			(514		)
	Effect of netting and allocation of collateral(f)		2,324				3,585				925				6,834				2,324					3,585					925					6,834
	Commodity derivative liabilities subtotal		29				(80		)		(150		)		(201		)		29					(80		)			(391		)			(442		)
	Interest rate and foreign currency derivative
	liabilities
	Derivatives designated as hedging instruments		—				(17		)		—				(17		)		—					(17		)			—					(17		)
	Economic hedges		—				(6		)		—				(6		)		—					(186		)			—					(186		)
	Proprietary trading		(1		)		(14		)		—				(15		)		(1		)			(14		)			—					(15		)
Effect of netting and allocation of collateral		15				6				—				21				15					37					—					52
Interest rate and foreign currency derivative		14				(31		)		—				(17		)		14					(180		)			—					(166		)
liabilities subtotal
Deferred compensation obligation		—				(30		)		—				(30		)		—					(103		)			—					(103		)
Total liabilities		43				(141		)		(150		)		(248		)		43					(363		)			(391		)			(711		)
Total net assets		$	4,607			$	6,495			$	1,962			$	13,064			$	5,528				$	6,276				$	1,721				$	13,525
		Generation																Exelon
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3				Total
Assets
Cash equivalents(a)		$	405			$	—			$	—			$	405			$	1,119				$	—				$	—			$	1,119
Nuclear decommissioning trust fund investments
Cash equivalents		208				37				—				245				208					37					—				245
		Generation																Exelon
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3				Total
Equity
Domestic		2,423				2,207				—				4,630				2,423					2,207					—				4,630
Foreign		612				—				—				612				612					—					—				612
Equity funds subtotal		3,035				2,207				—				5,242				3,035					2,207					—				5,242
Fixed income
Corporate debt		—				2,023				239				2,262				—					2,023					239				2,262
U.S. Treasury and agencies		996				—				—				996				996					—					—				996
Foreign governments		—				95				—				95				—					95					—				95
State and municipal debt		—				438				—				438				—					438					—				438
Other		—				511				—				511				—			—		511			—		—				511
Fixed income subtotal		996				3,067				239				4,302				996					3,067					239				4,302
Middle market lending		—				—				366				366				—					—					366				366
Private Equity		—				—				83				83				—					—					83				83
Real Estate		—				—				3				3				—			—		—			—		3				3
Other		—				301				—				301				—					301					—				301
Nuclear decommissioning trust fund investments subtotal(b)		4,239				5,612				691				10,542				4,239					5,612					691				10,542
Pledged assets for Zion Station
decommissioning
Cash equivalents		—				15				—				15				—					15					—				15
Equities		6				1				—				7				6					1					—				7
Fixed income
U.S. Treasury and agencies		5				3				—				8				5					3					—				8
Corporate debt		—				89				—				89				—					89					—				89
State and municipal debt		—				10				—				10				—					10					—				10
Other		—				3				—				3				—			—		3			—		—				3
Fixed income subtotal		5				105				—				110				5					105					—				110
Middle market lending		—				—				184				184				—					—					184				184
Pledged assets for Zion Station		11				121				184				316				11					121					184				316
decommissioning subtotal(c)
Rabbi trust investments(d)
Cash equivalents		—				—				—				—				1					—					—				1
Mutual funds(e)		16				—				—				16				46					—					—				46
Rabbi trust investments subtotal		16				—				—				16				47					—					—				47
Commodity derivative assets
Economic hedges		1,667				3,465				1,681				6,813				1,667					3,465					1,681				6,813
Proprietary trading		201				284				27				512				201					284					27				512
Effect of netting and allocation of collateral(f)		(1,982		)		(2,757		)		(557		)		(5,296		)		(1,982		)			(2,757		)			(557		)		(5,296		)
Commodity derivative assets subtotal		(114		)		992				1,151				2,029				(114		)			992					1,151				2,029
Interest rate and foreign currency derivative
assets
Derivatives designated as hedging instruments		—				8				—				8				—					31					—				31
Economic hedges		—				12				—				12				—					13					—				13
Proprietary trading		18				9				—				27				18					9					—				27
Effect of netting and allocation of collateral		(17		)		(12		)		—				(29		)		(17		)			(31		)			—				(48		)
Interest rate and foreign currency derivative		1				17				—				18				1					22					—				23
assets subtotal
Other investments		—				—				3				3				2					—					3				5
Total assets		4,558				6,742				2,029				13,329				5,305					6,747					2,029				14,081
		Generation																Exelon
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3				Total
Liabilities
Commodity derivative liabilities
Economic hedges		(2,241		)		(3,458		)		(788		)		(6,487		)		(2,241		)			(3,458		)			(995		)		(6,694		)
Proprietary trading		(195		)		(295		)		(42		)		(532		)		(195		)			(295		)			(42		)		(532		)
Effect of netting and allocation of collateral(f)		2,416				3,557				729				6,702				2,416					3,557					729				6,702
Commodity derivative liabilities subtotal		(20		)		(196		)		(101		)		(317		)		(20		)			(196		)			(308		)		(524		)
Interest rate and foreign currency derivative
liabilities
Derivatives designated as hedging instruments		—				(12		)		—				(12		)		—					(41		)			—				(41		)
Economic hedges		—				(2		)		—				(2		)		—					(103		)			—				(103		)
Proprietary trading		(14		)		(9		)		—				(23		)		(14		)			(9		)			—				(23		)
Effect of netting and allocation of collateral		25				10				—				35				25					29					—				54
Interest rate and foreign currency derivative		11				(13		)		—				(2		)		11					(124		)			—				(113		)
liabilities subtotal
Deferred compensation obligation		—				(31		)		—				(31		)		—					(107		)			—				(107		)
Total liabilities		(9		)		(240		)		(101		)		(350		)		(9		)			(427		)			(308		)		(744		)
Total net assets		$	4,549			$	6,502			$	1,928			$	12,979			$	5,296				$	6,320				$	1,721			$	13,337
______________
(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
(b)	Excludes net (liabilities) of $(27) million and $(5) million at March 31, 2015 and December 31, 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(c)	Excludes net assets of $1 million and $3 million at March 31, 2015 and December 31, 2014, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(d)	Excludes $36 million and $35 million of cash surrender value of life insurance investment at March 31, 2015 and December 31, 2014, respectively, at Exelon Consolidated. Excludes $12 million and $11 million and of cash surrender value of life insurance investment at March 31, 2015 and December 31, 2014, respectively, at Generation.
(e)	The mutual funds held by the Rabbi trusts at Exelon include $47 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at March 31, 2015, and $45 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2014.
(f)	Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $425 million, $736 million and $185 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of March 31, 2015. Collateral posted (received) from counterparties, net of collateral paid to counterparties, totaled $434 million, $800 million and $172 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2014.
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value on the utility Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of March 31, 2015 and December 31, 2014:
		ComEd																PECO																BGE
As of March 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		$	67			$	—			$	—			$	67			$	5			$	—			$	—			$	5			$	75	$	—		$	—	$	75
Rabbi trust investments in mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		5
Total assets		67				—				—				67				14				—				—				14				80		—			—		80
Liabilities
Deferred compensation		—				(8		)		—				(8		)		—				(14		)		—				(14		)		—		(4		)	—		(4		)
obligation
Mark-to-market derivative		—				—				(241		)		(241		)		—				—				—				—				—		—			—		—
liabilities (b)
Total liabilities		—				(8		)		(241		)		(249		)		—				(14		)		—				(14		)		—		(4		)	—		(4		)
Total net assets (liabilities)		$	67			$	(8	)		$	(241	)		$	(182	)		$	14			$	(14	)		$	—			$	—			$	80	$	(4	)	$	—	$	76
		ComEd																PECO																BGE
As of December 31, 2014		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total				Level 1		Level 2			Level 3		Total
Assets
Cash equivalents		$	25			$	—			$	—			$	25			$	12			$	—			$	—			$	12			$	103	$	—		$	—	$	103
Rabbi trust investments in mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		$	5
Total assets		25				—				—				25				21				—				—				21				108		—			—		108
Liabilities
Deferred compensation obligation		—				(8		)		—				(8		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Mark-to-market derivative liabilities (b)		—				—				(207		)		(207		)		—				—				—				—				—		—			—		—
Total liabilities		—				(8		)		(207		)		(215		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Total net assets (liabilities)		$	25			$	(8	)		$	(207	)		$	(190	)		$	21			$	(15	)		$	—			$	6			$	108	$	(5	)	$	—	$	103
______________
(a)	At PECO, excludes $14 million of the cash surrender value of life insurance investments at both March 31, 2015 and December 31, 2014.
(b)	The Level 3 balance includes the current and noncurrent liability of $20 million and $221 million at March 31, 2015, respectively, and $20 million and $187 million at December 31, 2014, respectively, 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 table presents 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, 2015 and 2014:
			Generation																				ComEd								Exelon
	Three Months Ended March 31, 2015		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Eliminated in Consolidation				Total
			Decommissioning				for Zion Station				Derivatives				Investments
			Trust Fund				Decommissioning
			Investments
	Balance as of December 31, 2014		$	691			$	184			$	1,050			$	3			$	1,928			$	(207	)		$	—			$	1,721
	Total realized / unrealized gains (losses)
	Included in net income		2				—				(32		)	(a)	—				(30		)		—				—				(30		)
	Included in noncurrent payables to affiliates		8				—				—				—				8				—				(8		)		—
	Included in payable for Zion Station decommissioning		—				3				—				—				3				—				—				3
	Included in regulatory assets		—				—				—				—				—				(34		)		8				(26		)
	Change in collateral		—				—				12				—				12				—				—				12
	Purchases, sales, issuances and settlements																										—
	Purchases		47				5				41				—				93				—				—				93
	Sales		(8		)		(14		)		—				—				(22		)		—				—				(22		)
	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		$	715			$	178			$	1,066			$	3			$	1,962			$	(241	)		$	—			$	1,721
	The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended March 31, 2015		$	1			$	—			$	180			$	—			$	181			$	—			$	—			$	181
			Generation																					ComEd								Exelon
	Three Months Ended March 31, 2014		Nuclear					Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Eliminated in Consolidation				Total
			Decommissioning					for Zion Station				Derivatives				Investments
			Trust Fund					Decommissioning
			Investments
	Balance as of December 31, 2013		$	350				$	112			$	465			$	15			$	942			$	(193	)		$	—			$	749
	Total realized / unrealized gains (losses)
	Included in net income		1					—				(312		)	(a)	—				(311		)		—				—				(311		)
	Included in noncurrent payables to affiliates		3					—				—				—				3				—				(3		)		—
	Included in payable for Zion Station decommissioning		—					(1		)		—				—				(1		)		—				—				(1		)
	Included in regulatory assets		—					—								—				—				25				3				28
	Change in collateral		—			—		—				144				—				144				—				—				144
	Purchases, sales, issuances and settlements
	Purchases		139					30				10				2				181				—				—				181
	Sales		(1		)			(4		)		(2		)		—				(7		)		—				—				(7		)
	Settlements		(6		)			—				—				—				(6		)		—				—				(6		)
	Transfers into Level 3		—					—				(26		)		—				(26		)		—				—				(26		)
	Transfers out of Level 3		—					—				8				(7		)		1				—				—				1
	Balance as of March 31, 2014		$	486				$	137			$	287			$	10			$	920			$	(168	)		$	—			$	752
	The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended March 31, 2014		$	—				$	—			$	(446	)		$	—			$	(446	)		$	—			$	—			$	(446	)
	______________
	(a) Includes the reclassification of $212 million and $(134) million of realized gains (losses) due to the settlement of derivative contracts for the three months ended March 31, 2015 and 2014, respectively.
	(b) Includes $36 million of decreases in fair value and realized losses due to settlements of $2 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended March 31, 2015. Includes $30 million of increases in fair value and realized gains due to settlements of $5 million for the three months ended March 31, 2014.
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis	The following 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, 2015 and 2014:
			Generation									Exelon
			Operating			Purchased			Other, net(a)			Operating			Purchased			Other, net(a)
			Revenues			Power and						Revenues			Power and
						Fuel									Fuel
	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
		Generation												Exelon
		Operating				Purchased				Other, net(a)				Operating				Purchased				Other, net(a)
		Revenues				Power and								Revenues				Power and
						Fuel												Fuel
	Total gains (losses) included in net income for the three months ended March 31, 2014	$	(268	)		$	(44	)		$	1			$	(268	)		$	(44	)		$	1
	Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended March 31, 2014	(425		)		(21		)		—				(425		)		(21		)		—
	______________
	(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique	The table below discloses the significant inputs to the forward curve used to value these positions.
	Type of trade		Fair Value at March 31, 2015				Valuation		Unobservable		Range
							Technique		Input
	Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	892			Discounted		Forward power		$17	-	$121	(d)
							Cash Flow		price
									Forward gas		$1.68	-	$13.69	(d)
									price
							Option Model		Volatility		8%	-	172%
									percentage
	Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	(11	)		Discounted		Forward power		$17	-	$95	(d)
							Cash Flow		price
	Mark-to-market derivatives (ComEd)		$	(241	)		Discounted		Forward heat		8x	-	9x
							Cash Flow		rate(b)
									Marketability		3.50%	-	8%
									reserve
									Renewable		86%	-	126%
									factor
	______________
	(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 $185 million as of March 31, 2015.
	(d)	The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas economic hedges would be approximately $107 and $8.19, respectively, and would be approximately $55 for power proprietary trading.
	Type of trade		Fair Value at December 31, 2014				Valuation		Unobservable		Range
							Technique		Input
	Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	893			Discounted		Forward power		$15	-	$120	(d)
							Cash Flow		price
									Forward gas		$1.52	-	$14.02	(d)
									price
							Option Model		Volatility		8%	-	257%
									percentage
	Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	(15	)		Discounted		Forward power		$15	-	$117	(d)
							Cash Flow		price
	Mark-to-market derivatives (ComEd)		$	(207	)		Discounted		Forward heat		8x	-	9x
							Cash Flow		rate(b)
									Marketability		3.50%	-	8%
									reserve
									Renewable		86%	-	126%
									factor
	______________
	(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 $172 million as of December 31, 2014.
	(d)	The upper ends of the ranges are driven by the winter power and gas prices in the New England region. Without the New England region, the upper ends of the ranges for power and gas would be approximately $97 and $8.14, respectively, and would be approximately $76 for power proprietary trading.
Exelon Generation Co L L C [Member]
Fair Value Tables [Line Items]
Fair value of financial liabilities recorded at the carrying amount	Generation
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	25			$	—			$	25			$	—			$	25
	Long-term debt (including amounts due within one year)	8,492				—				7,885				1,380				9,265
	SNF obligation	1,021				—				843				—				843
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	36			$	—			$	24			$	12			$	36
	Long-term debt (including amounts due within one year)	8,266				—				7,511				1,311				8,822
	SNF obligation	1,021				—				833				—				833
Commonwealth Edison Co [Member]
Fair Value Tables [Line Items]
Fair value of financial liabilities recorded at the carrying amount	ComEd
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	283			$	—			$	283			$	—			$	283
	Long-term debt (including amounts due within one year)	6,359				—				7,347				—				7,347
	Long-term debt to financing trust	206				—				—				206				206
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	304			$	—			$	304			$	—			$	304
	Long-term debt (including amounts due within one year)	5,958				—				6,788				—				6,788
	Long-term debt to financing trust	206				—				—				213				213
PECO Energy Co [Member]
Fair Value Tables [Line Items]
Fair value of financial liabilities recorded at the carrying amount	PECO
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Long-term debt (including amounts due within one year)	$	2,246			$	—			$	2,602			$	—			$	2,602
	Long-term debt to financing trusts	184				—				—				201				201
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Long-term debt (including amounts due within one year)	$	2,246			$	—			$	2,537			$	—			$	2,537
	Long-term debt to financing trusts	184				—				—				199				199
Baltimore Gas and Electric Company [Member]
Fair Value Tables [Line Items]
Fair value of financial liabilities recorded at the carrying amount	BGE
		31-Mar-15
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	3			$	3			$	—			$	—			$	3
	Long-term debt (including amounts due within one year)	1,942				—				2,234				—				2,234
	Long-term debt to financing trusts	258				—				—				265				265
		December 31, 2014
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	123			$	3			$	120			$	—			$	123
	Long-term debt (including amounts due within one year)	1,942				—				2,178				—				2,178
	Long-term debt to financing trusts	258				—				—				236				236

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
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		2015				2014				2015			2014
		Location		Gain (Loss) on Swaps								Gain (Loss) on Borrowings
	Generation	Interest expense(a)		$	(1	)		$	(5	)		$	—		$	(1	)
	Exelon	Interest expense		9				2				11			4
	__________
	(a)	For the three months ended March 31, 2015 and 2014, the loss on Generation swaps included $1 million and $4 million realized in earnings with an immaterial amount excluded from hedge effectiveness testing.
	The following table provides a summary of the derivative fair value balances recorded by the Registrants as of March 31, 2015:
			Generation															ComEd			Exelon
	Derivatives		Economic				Proprietary				Collateral			Subtotal(b)				Economic			Total
			Hedges				Trading				and							Hedges(c)			Derivatives
											Netting(a)
	Mark-to-market derivative assets		$	4,618			$	431			$	(3,947	)	$	1,102			$	—		$	1,102
	(current assets)
	Mark-to-market derivative assets		2,363				70				(1,541		)	892				—			892
	(noncurrent assets)
	Total mark-to-market derivative		6,981				501				(5,488		)	1,994				—			1,994
	assets
	Mark-to-market derivative liabilities		(4,505		)		(437		)		4,852			(90		)		(20		)	(110		)
	(current liabilities)
	Mark-to-market derivative liabilities		(2,016		)		(77		)		1,982			(111		)		(221		)	(332		)
	(noncurrent liabilities)
	Total mark-to-market derivative		(6,521		)		(514		)		6,834			(201		)		(241		)	(442		)
	liabilities
	Total mark-to-market derivative		$	460			$	(13	)		$	1,346		$	1,793			$	(241	)	$	1,552
	net assets (liabilities)
	_________
	(a)	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
	(b)	Current and noncurrent assets are shown net of collateral of $387 million and $192 million, respectively, and current and noncurrent liabilities are shown net of collateral of $519 million and $248 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,346 million at March 31, 2015.
	(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
	The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2014:
			Generation															ComEd			Exelon
	Description		Economic				Proprietary				Collateral			Subtotal(b)				Economic			Total
			Hedges				Trading				and							Hedges(c)			Derivatives
											Netting(a)
	Mark-to-market derivative assets		$	4,992			$	456			$	(4,184	)	$	1,264			$	—		$	1,264
	(current assets)
	Mark-to-market derivative assets		1,821				56				(1,112		)	765				—			765
	(noncurrent assets)
	Total mark-to-market derivative		6,813				512				(5,296		)	2,029				—			2,029
	assets
	Mark-to-market derivative liabilities		(4,947		)		(468		)		5,200			(215		)		(20		)	(235		)
	(current liabilities)
	Mark-to-market derivative liabilities		(1,540		)		(64		)		1,502			(102		)		(187		)	(289		)
	(noncurrent liabilities)
	Total mark-to-market derivative		(6,487		)		(532		)		6,702			(317		)		(207		)	(524		)
	liabilities
	Total mark-to-market derivative		$	326			$	(20	)		$	1,406		$	1,712			$	(207	)	$	1,505
	net assets (liabilities)
	________
	(a)	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, and letters of credit. These are not reflected in the table above.
	(b)	Current and noncurrent assets are shown net of collateral of $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.
	(c)	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
	Below is a summary of the interest rate and foreign currency hedges as of March 31, 2015.
			Generation																		Other												Exelon
	Description		Derivatives				Economic				Proprietary			Collateral				Subtotal			Derivatives			Economic			Collateral			Subtotal			Total
			Designated				Hedges				Trading(a)			and							Designated			Hedges			and
			as Hedging											Netting(b)							as Hedging						Netting(b)
			Instruments																		Instruments
	Mark-to-market		$	—			$	13			$	11		$	(10	)		$	14		$	1		$	—		$	—		$	1		$	15
	derivative assets
	(current assets)
	Mark-to-market		—				14				8			(3		)		19			31			2			(31		)	2			21
derivative assets
(noncurrent
assets)
Total mark-to-market		—				27				19			(13		)		33			32			2			(31		)	3			36
derivative
assets
Mark-to-market		(8		)		(6		)		(8		)	15				(7		)	—			—			—			—			(7		)
derivative liabilities
(current liabilities)
Mark-to-market		(9		)		—				(7		)	6				(10		)	—			(180		)	31			(149		)	(159		)
derivative liabilities
(noncurrent
liabilities)
Total mark-to-market derivative		(17		)		(6		)		(15		)	21				(17		)	—			(180		)	31			(149		)	(166		)
liabilities
Total mark-to-market		$	(17	)		$	21			$	4		$	8			$	16		$	32		$	(178	)	$	—		$	(146	)	$	(130	)
derivative
net assets
(liabilities)
_____________
(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 within the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
(b)	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2014:
		Generation																		Other												Exelon
Description		Derivatives				Economic				Proprietary			Collateral				Subtotal			Derivatives			Economic			Collateral			Subtotal			Total
		Designated				Hedges				Trading(a)			and							Designated			Hedges			and
		as Hedging											Netting(b)							as Hedging						Netting(b)
		Instruments																		Instruments
Mark-to-market		$	7			$	7			$	20		$	(22	)		$	12		$	3		$	—		$	—		$	3		$	15
derivative assets
(current assets)
Mark-to-market		1				5				7			(7		)		6			20			1			(19		)	2			8
derivative assets
(noncurrent
assets)
Total mark-to-market		8				12				27			(29		)		18			23			1			(19		)	5			23
derivative
assets
Mark-to-market		(8		)		(2		)		(14		)	25				1			—			—			—			—			1
derivative liabilities
(current liabilities)
Mark-to-market		(4		)		—				(9		)	10				(3		)	(29		)	(101		)	19			(111		)	(114		)
derivative liabilities
(noncurrent
liabilities)
Total mark-to-market derivative		(12		)		(2		)		(23		)	35				(2		)	(29		)	(101		)	19			(111		)	(113		)
liabilities
Total mark-to-market		$	(4	)		$	10			$	4		$	6			$	16		$	(6	)	$	(100	)	$	—		$	(106	)	$	(90	)
derivative
net assets
(liabilities)
_______________
(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 within 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 activity of accumulated OCI related to cash flow hedges	The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.
					Total Cash Flow Hedge OCI Activity, Net of Income Tax
					Generation				Exelon
	Three Months Ended March 31, 2015		Income  Statement		Total Cash Flow				Total Cash  Flow
			Location		Hedges				Hedges
	Accumulated OCI derivative gain at December 31, 2014				$	(18	)		$	(28	)
	Effective portion of changes in fair value				(6		)		(11		)
	Reclassifications from accumulated OCI to net income		Other, net		—				16			(a)
	Reclassifications from accumulated OCI to net income		Interest Expense		3				3
	Reclassifications from accumulated OCI to net income		Operating Revenues		(2		)		(2		)
	Accumulated OCI derivative gain at March 31, 2015				$	(23	)		$	(22	)
	______
	(a)	Amount is net of related income tax expense of $10 million for the three months ended March 31, 2015.
					Total Cash
					Flow Hedge OCI Activity,
					Net of Income Tax
					Generation				Exelon
	Three Months Ended March 31, 2014		Income  Statement		Total Cash Flow				Total Cash  Flow
			Location		Hedges				Hedges
	Accumulated OCI derivative gain at December 31, 2013				$	116			$	120
	Effective portion of changes in fair value				(4		)		(1		)
	Reclassifications from accumulated OCI to net income		Operating Revenues		(24		)	(a)	(24		)	(a)
	Accumulated OCI derivative gain at March 31, 2014				$	88			$	95
	__________
	(a) Amount is net of related income tax expense of $15 million for the three months ended March 31, 2014.
Other Derivatives - Gain (loss) and reclassification	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															HoldCo			Exelon
	Three Months Ended March 31, 2015		Operating				Purchased				Interest			Total				Interest			Total
			Revenues				Power				Expense							Expense
							and Fuel
	Change in fair value of commodity positions		$	164			$	(79	)		$	—		$	85			$	—		$	85
	Reclassification to realized at settlement of		(21		)		87				—			66				—			66
	commodity positions
	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		(2		)		—				—			(2		)		—			(2		)
	positions
	Net treasury mark-to-market gains (losses)		11				—				—			11				(78		)	(67		)
	Total Net mark-to-market gains (losses)		$	154			$	8			$	—		$	162			$	(78	)	$	84
			Generation															HoldCo			Exelon
	Three Months Ended March 31, 2014		Operating				Purchased				Interest Expense			Total				Interest			Total
			Revenues				Power											Expense
							and Fuel
	Change in fair value of commodity positions		$	(852	)		$	171			$	—		$	(681	)		$	—		$	(681	)
	Reclassification to realized at settlement of		93				(141		)		—			(48		)		—			(48		)
	commodity positions
	Net commodity mark-to-market gains (losses)		(759		)		30				—			(729		)		—			(729		)
	Change in fair value of treasury positions		(1		)		—				(1		)	(2		)		—			(2		)
	Reclassification to realized at settlement of treasury		—				—				—			—				—			—
	positions
	Net treasury mark-to-market gains (losses)		(1		)		—				(1		)	(2		)		—			(2		)
	Total Net mark-to-market gains (losses)		$	(760	)		$	30			$	(1	)	$	(731	)		$	—		$	(731	)
	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		Three Months Ended March 31,
		Statement		2015				2014
	Change in fair value of commodity positions	Operating Revenues		$	1			$	(3	)
	Reclassification to realized at settlement	Operating Revenues		2				1
	of commodity positions
	Net commodity mark-to-market gains (losses)	Operating Revenues		3				(2		)
	Change in fair value of treasury positions	Operating Revenues		4				—
	Reclassification to realized at settlement	Operating Revenues		(4		)		—
	of treasury positions
	Net treasury mark-to-market gains (losses)	Operating Revenues		—				—
	Total Net mark-to-market gains (losses)	Operating Revenues		$	3			$	(2	)
Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements	The 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		31-Mar-15				31-Dec-14
	Gross Fair Value of Derivative Contracts Containing this Feature(a)		$	(1,420	)		$	(1,433	)
	Offsetting Fair Value of In-the-Money Contracts Under Master		1,138				1,140
	Netting Arrangements(b)
	Net Fair Value of Derivative Contracts Containing This Feature(c)		$	(282	)		$	(293	)
	__________
	(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
	(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
	(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
Disclosure of Credit Derivatives [Table Text Block]	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, 2015. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the table 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 and BGE of $52 million, $36 million and $26 million, as of March 31, 2015, respectively.
	Rating as of March 31, 2015		Total				Credit				Net			Number  of			Net Exposure of
			Exposure				Collateral(a)				Exposure			Counterparties			Counterparties
			Before Credit											Greater than  10%			Greater than 10%
			Collateral											of Net Exposure			of Net Exposure
	Investment grade		$	1,570			$	56			$	1,514		1			$	442
	Non-investment grade		63				16				47			—			—
	No external ratings
	Internally rated — investment grade		495				—				495			—			—
	Internally rated — non-investment		68				3				65			—			—
	grade
	Total		$	2,196			$	75			$	2,121		1			$	442
	Net Credit Exposure by Type of Counterparty		As of March 31, 2015
	Financial institutions		$	324
	Investor-owned utilities, marketers, power producers		897
	Energy cooperatives and municipalities		869
	Other		31
	Total		$	2,121
	_____________________
	(a)	As of March 31, 2015, credit collateral held from counterparties where Generation had credit exposure included $62 million of cash and $14 million of letters of credit.

Debt_and_Credit_Agreements_Tab

Debt and Credit Agreements (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Schedule of Short-term Debt

Exelon had bank lines of credit under committed credit facilities at March 31, 2015 for short-term financial needs, as follows:

Type of Credit Facility

Amount(a)

Expiration Dates

Capacity Type

(In billions)

Exelon Corporate

Syndicated Revolver(b)

$

0.5

May-19

Letters of credit and cash

Generation

Syndicated Revolver

5.1

May-19

Letters of credit and cash

Syndicated Revolver

0.2

Aug-18

Letters of credit and cash

Bilateral

0.3

December 2015 and April 2016

Letters of credit and cash

Bilateral

0.1

Jan-17

Letters of credit

Bilateral

0.1

Oct-15

Letters of credit and cash

ComEd

Syndicated Revolver

1

Mar-19

Letters of credit and cash

PECO

Syndicated Revolver(b)

0.6

May-19

Letters of credit and cash

BGE

Syndicated Revolver(b)

0.6

May-19

Letters of credit and cash

Total

$

8.5

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 16, 2015. These facilities are solely utilized to issue letters of credit. As of March 31, 2015, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $16 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion to support the PHI transaction discussed below.

(b)

Syndicated revolvers include credit facility commitments of $22 million, $27 million and $27 million for Exelon Corporate, PECO and BGE, respectively, which expire in August 2018.

The Registrants had the following amounts of commercial paper borrowings outstanding as of March 31, 2015 and December 31, 2014:

Commercial Paper Borrowings

31-Mar-15

31-Dec-14

Exelon Corporate

$

—

$

—

Generation

—

—

ComEd

283

304

PECO

—

—

BGE

—

120

Schedule Of Issuance Of Long Term Debt

During the three months ended March 31, 2015, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Senior Unsecured Notes (a)

2.95

%

15-Jan-20

$

750

Fund the optional redemption of Exelon's $550 million, 4.550% Senior Notes and for general corporate purposes

Generation

AVSR DOE Nonrecourse Debt

2.293 - 2.559 %

5-Jan-37

$

14

Antelope Valley solar development

Generation

Energy Efficiency Project Financing

3.71

%

1-Oct-35

$

42

Funding to install energy conservation measures in Coleman, Florida

ComEd

Mortgage Bonds Series 118

3.7

%

1-Mar-45

$

400

Refinance maturing mortgage bonds, repay a portion of ComEd's outstanding commercial paper obligations and for general corporate purposes

_____________

(a)

In connection with the issuance of Senior Unsecured Notes, Exelon terminated floating-to-fixed interest rate swaps that had been designated as cash flow hedges. See Note 8 — Derivative Financial Instruments for further information on the swap termination.

Schedule of Long-term Debt Instruments

During the three months ended March 31, 2014, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

ExGen Renewables I Nonrecourse Debt

LIBOR + 4.25%

February 6, 2021

$

300

General corporate purposes

ComEd

First Mortgage Bonds Series 115

2.15

%

15-Jan-19

$

300

Refinance maturing mortgage bonds and general corporate purposes

ComEd

First Mortgage Bonds Series 116

4.7

%

January 15, 2044

$

350

Refinance maturing mortgage bonds and general corporate purposes

Retirement and Redemptions of Current and Long-Term Debt

During the three months ended March 31, 2014, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Generation

2003 Senior Notes

5.35

%

January 15, 2014

$

500

Generation

Pollution Control Loan

4.1

%

July 1, 2014

$

20

Generation

Continental Wind Nonrecourse Debt

6

%

February 28, 2033

$

11

Generation

Kennett Square Capital Lease

7.83

%

September 20, 2020

$

1

ComEd

Mortgage Bonds Series 110

1.63

%

January 15, 2014

$

600

ComEd

Pollution Control Series 1994C

5.85

%

January 15, 2014

$

17

During the three months ended March 31, 2015, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Exelon Corporate(a)

Unsecured Notes

4.55

%

June 15, 2015

$

550

Generation(a)

Unsecured Notes

4.55

%

15-Jun-15

$

550

Generation

CEU Upstream Nonrecourse Debt

LIBOR + 2.25%

22-Jul-16

$

2

Generation

AVSR DOE Nonrecourse Debt

2.29%-3.56%

5-Jan-37

$

4

Generation

Kennett Square Capital Lease

7.83

%

20-Sep-20

$

1

Generation

Continental Wind Nonrecouse Debt

6

%

28-Feb-33

$

10

Generation

ExGen Texas Power Nonrecouse Debt

LIBOR + 4.75%

18-Sep-21

$

2

Income_Taxes_Tables

Income Taxes (Tables)	3 Months Ended
	Mar. 31, 2015
Income Tax Disclosure [Abstract]
Effective Income Tax Rate Reconciliation
	For the Three Months Ended March 31, 2015	Exelon		Generation		ComEd		PECO		BGE
	U.S. Federal statutory rate	35	%	35	%	35	%	35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	2.6		2.7		5		1.2		5.3
	Qualified nuclear decommissioning trust fund income	1.9		3		—		—		—
	Domestic production activities deduction	(2.2	)	(3.4	)	—		—		—
	Health care reform legislation	—		—		—		—		0.2
	Amortization of investment tax credit, net deferred taxes	(0.9	)	(1.4	)	(0.3	)	(0.1	)	—
	Plant basis differences	(1.3	)	—		(0.3	)	(6.7	)	(0.3	)
	Production tax credits and other credits	(1.8	)	(2.8	)	—		—		—
	Noncontrolling interest	(0.7	)	(1.1	)	—		—		—
	Other	0.4		(0.2	)	0.2		—		0.2
	Effective income tax rate	33	%	31.8	%	39.6	%	29.4	%	40.4	%
	For the Three Months Ended March 31, 2014	Exelon		Generation(a)		ComEd		PECO		BGE
	U.S. Federal statutory rate	35	%	35	%	35	%	35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	(57.6	)	9.7		5.5		1.2		5.2
	Qualified nuclear decommissioning trust fund income	44.2		(4.6	)	—		—		—
	Domestic production activities deduction	(27.8	)	2.9		—		—		—
	Health care reform legislation	1.3		—		0.1		—		0.2
	Amortization of investment tax credit, net deferred taxes	(18.0	)	1.7		(0.3	)	(0.1	)	(0.2	)
	Plant basis differences	(31.4	)	—		(0.6	)	(8.7	)	(0.6	)
	Production tax credits and other credits	(36.5	)	3.8		—		—		—
	Noncontrolling interest	—		—		—		—		—
	Other	(47.7	)	3.3		0.2		0.2		0.1
	Effective income tax rate	(138.5	)%	51.8	%	39.9	%	27.6	%	39.7	%

Nuclear_Decommissioning_Tables

Nuclear Decommissioning (Tables) (Exelon Generation Co L L C [Member])	3 Months Ended
	Mar. 31, 2015
Exelon Generation Co L L C [Member]
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, 2014 to March 31, 2015:
	Nuclear decommissioning ARO at December 31, 2014(a)	$	6,961
	Net increase due to changes in, and timing of, estimated future cash flows(b)	55
	Accretion expense	94
	Nuclear decommissioning ARO at March 31, 2015(a)	$	7,110
	(a)	Includes $8 million as the current portion of the ARO at March 31, 2015 and December 31, 2014, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
	(b)	Represents a purchase accounting adjustment to the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
Unrealized Gains (Losses) on nuclear decommissioning trust funds	The following table provides unrealized gains on NDT funds for the three months ended March 31, 2015 and 2014:
		Exelon and Generation
		Three Months Ended March 31,
		2015		2014
	Net unrealized gains on decommissioning trust	$	48	$	61
	funds — Regulatory Agreement Units(a)
	Net unrealized gains on decommissioning trust	40		13
	funds — Non-Regulatory Agreement Units(b)(c)
	(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 $10 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2015 and 2014. 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	The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at March 31, 2015 and December 31, 2014:
		Exelon and Generation
		31-Mar-15		31-Dec-14
	Carrying value of Zion Station pledged assets	$	308	$	319
	Payable to Zion Solutions(a)	281		292
	Current portion of payable to Zion Solutions(b)	145		137
	Cumulative withdrawals by Zion Solutions to pay decommissioning costs	687		666
	(a)	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
	(b)	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

Retirement_Benefits_Tables

Retirement Benefits (Tables)	3 Months Ended
	Mar. 31, 2015
Compensation and Retirement Disclosure [Abstract]
Schedule of Defined Benefit Plans Disclosures	The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the three months ended March 31, 2015 and 2014.
		Pension Benefits						Other
		Three Months Ended						Postretirement Benefits
		March 31,						Three Months Ended
								March 31,
		2015(a)			2014(a)			2015(a)			2014(a)
	Service cost	$	82		$	69		$	30		$	33
	Interest cost	178			183			42			55
	Expected return on assets	(257		)	(241		)	(38		)	(38		)
	Amortization of:
	Prior service cost (benefit)	3			3			(43		)	(4		)
	Actuarial loss	143			105			20			8
	Net periodic benefit cost	$	149		$	119		$	11		$	54
	______________
	(a)	For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.
Schedule Of Pension And Other Postretirement Benefit Costs	The amounts below represent Generation’s, ComEd’s, PECO’s, BGE’s and BSC's allocated portion of the pension and postretirement benefit plan costs, which were included in 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, 2015 and 2014.
		Three Months Ended March 31,
	Pension and Other Postretirement Benefit Costs	2015			2014
	Generation(a)	$	67		$	75
	ComEd	52			56
	PECO	10			12
	BGE	17			16
	BSC(b)	14			14
	______________
	(a)	For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.
	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.
Schedule Of Defined Contributions	The following table presents the matching contributions to the savings plans during the three months ended March 31, 2015 and 2014:
			Three Months Ended March 31,
	Savings Plan Matching Contributions		2015			2014
	Exelon(a)		$	22		$	29
	Generation(a)		13			14
	ComEd		5			7
	PECO		1			2
	BGE		2			3
	BSC(b)		1			3
	_______________
	(a)	Includes $2 million related to CENG for the three months ended March 31, 2015. CENG is not included in the 2014 amounts.
	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Severance_Tables

Severance (Tables)	3 Months Ended
	Mar. 31, 2015
Restructuring and Related Activities [Abstract]
Activity of severance obligations for the corporate restructuring (excluding obligations recorded in equity)	.
	.
Restructuring and Related Costs	For the three months ended March 31, 2015 and 2014, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
		Exelon		Generation		ComEd		PECO		BGE
	Severance Benefits
	Severance charges - 2015	$	20	$	20	$	—	$	—	$	—
	Severance charges - 2014	$	4	$	4	$	—	$	—	$	—

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Income (Tables)	3 Months Ended
	Mar. 31, 2015
Changes in Accumulated Other Comprehensive Income [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the three months ended March 31, 2015 and 2014:
	Three Months Ended March 31, 2015		Gains				Unrealized			Pension and			Foreign			AOCI of		Total
			and				Gains and			Non-Pension			Currency			Equity
			(Losses)				(Losses) on			Postretirement			Items			Investments
			on Hedging				Marketable			Benefit Plan
			Activity				Securities			Items
	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
	______________
	(a)	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.
	(b)	See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.
	Three Months Ended March 31, 2014		Gains				Unrealized			Pension and			Foreign			AOCI of		Total
			and				Gains and			Non-Pension			Currency			Equity
			(Losses)				(Losses) on			Postretirement			Items			Investments
			on Hedging				Marketable			Benefit Plan
			Activity				Securities			Items
	Exelon(a)
	Beginning balance		$	120			$	2		$	(2,260	)	$	(10	)	$	108	$	(2,040	)
	OCI before reclassifications		(1		)		—			(13		)	(5		)	11		(8		)
	Amounts reclassified from AOCI(b)		(24		)		—			35			—			1		12
	Net current-period OCI		(25		)		—			22			(5		)	12		4
	Ending balance		$	95			$	2		$	(2,238	)	$	(15	)	$	120	$	(2,036	)
	Generation(a)
	Beginning balance		$	114			$	2		$	—		$	(10	)	$	108	$	214
	OCI before reclassifications		(1		)		(3		)	—			(5		)	11		2
	Amounts reclassified from AOCI(b)		(24		)		—			—			—			1		(23		)
	Net current-period OCI		(25		)		(3		)	—			(5		)	12		(21		)
	Ending balance		$	89			$	(1	)	$	—		$	(15	)	$	120	$	193
	PECO(a)
	Beginning balance		$	—			$	1		$	—		$	—		$	—	$	1
	OCI before reclassifications		—				—			—			—			—		—
	Amounts reclassified from AOCI(b)		—				—			—			—			—		—
	Net current-period OCI		—				—			—			—			—		—
	Ending balance		$	—			$	1		$	—		$	—		$	—	$	1
	_______________
	(a)	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.
	(b)	See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.
Reclassification out of Accumulated Other Comprehensive Income	The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the three months ended March 31, 2015 and 2014.
	Three Months Ended March 31, 2015
	Details about AOCI components		Items reclassified out of AOCI(a)							Affected line item in the Statements of Operations and Comprehensive Income
			Exelon				Generation
	Gains (losses) on hedging activity
	Terminated interest rate swaps (c)		$	(26	)		$	—		Other, net
	Energy related hedges		2				2			Operating revenues
	Other cash flow hedges		(3		)		(3		)	Interest expense
			(27		)		(1		)	Total before tax
			10				—			Tax benefit
			$	(17	)		$	(1	)	Net of tax
	Amortization of pension and other postretirement benefit plan items
	Prior service costs (b)		$	19			$	—
	Actuarial losses (b)		(90		)		—
			(71		)		—			Total before tax
			28				—			Tax benefit
			$	(43	)		$	—		Net of tax
	Total Reclassifications for the period		$	(60	)		$	(1	)	Net of Tax
	Three months ended March 31, 2014
	Details about AOCI components		Items reclassified out of AOCI(a)							Affected line item in the Statements of Operations and Comprehensive Income
			Exelon				Generation
	Gains on hedging activity
	Energy related hedges		$	39			$	39		Operating revenues
			39				39			Total before tax
			(15		)		(15		)	Tax (expense)
			$	24			$	24		Net of tax
	Amortization of pension and other postretirement benefit plan items
	Prior service costs (b)		$	(2	)		$	—
	Actuarial losses (b)		(56		)		—
			(58		)		—			Total before tax
			23				—			Tax benefit
			$	(35	)		$	—		Net of tax
	Equity investments
	Capital activity		$	(1	)		$	(1	)	Equity in losses of unconsolidated affiliates
			(1		)		(1		)	Total before tax
			—				—			Tax benefit
			$	(1	)		$	(1	)	Net of tax
	Total reclassifications for the period		$	(12	)		$	23		Net of Tax
	____________
	(a)	All amounts are net of tax. Amounts in parentheses represent a decrease in net income.
	(b)	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 12— 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, 2015 and 2014:
		Three Months Ended March 31,
		2015				2014
	Exelon
	Pension and non-pension postretirement benefit plans:
	Prior service benefit reclassified to periodic benefit cost	$	8			$	(1	)
	Actuarial gain (loss) reclassified to periodic cost	(35		)		(23		)
	Pension and non-pension postretirement benefit plans valuation adjustment	17				7
	Change in unrealized gain (loss) on cash flow hedges	(2		)		18
	Change in unrealized income on equity investments	—				(7		)
	Total	$	(12	)		$	(6	)
	Generation
	Change in unrealized gain (loss) on cash flow hedges	$	5			$	19
	Change in unrealized income on equity investments	—				(7		)
	Change in marketable securities	—				(2		)
	Total	$	5			$	10

Earnings_Per_Share_and_Equity_1

Earnings Per Share and Equity (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Reconciliation of basic and diluted earnings per share	The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share:
		Three Months Ended March 31,
		2015		2014
	Net income attributable to common shareholders	$	693	$	90
	Average common shares outstanding — basic	862		858
	Potentially dilutive effect of stock options, performance share awards and restricted stock	5		3
	Average common shares outstanding — diluted	867		861

Commitments_and_Contingencies_1

Commitments and Contingencies (Tables)	3 Months Ended
	Mar. 31, 2015
Commitments And Contingencies Tables Disclosure [Line Items]
Energy Commitments	As of March 31, 2015, Generation’s commitments relating to its purchases from unaffiliated utilities and others of energy, capacity, transmission rights and RECs, are as indicated in the following table:
		Net Capacity			REC			Transmission			Total
		Purchases(a)			Purchases(b)			Rights
								Purchases(c)
	2015	$	317		$	124		$	13		$	454
	2016	287			258			15			560
	2017	219			153			15			387
	2018	109			52			16			177
	2019	113			9			16			138
	Thereafter	276			1			35			312
	Total	$	1,321		$	597		$	110		$	2,028
	____________________
	(a)	Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at March 31, 2015, net of fixed capacity payments expected to be received ("capacity offsets") by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of March 31, 2015, capacity offsets were $107 million, $133 million, $136 million, $137, million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.
	(b)	The table excludes renewable energy purchases that are contingent in nature.
	(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
Utility Energy Purchase Commitments	ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments, as applicable, as of March 31, 2015 are as follows:
					Expiration within
		Total			2015			2016			2017			2018			2019		2020
																			and beyond
	ComEd
	Electric supply procurement(a)(b)	$	473		$	182		$	151		$	140		$	—		$	—	$	—
	Renewable energy and RECs(c)	1,498			56			76			77			78			84		1,127
	PECO
	Electric supply procurement(d)	832			532			268			32			—			—		—
	AECs(e)	13			2			2			2			2			2		3
	BGE
	Electric supply procurement(f)	1,074			538			448			88			—			—		—
	Curtailment services(g)	105			30			34			29			12			—		—
	___________________
	(a)	ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2018. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of March 31, 2015, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017.
	(b)	Excludes electric supply commitments associated with the Spring 2015 procurement process approved by the ICC on April 1, 2015, for the years 2015-2018 in the amount of $179 million, $112 million, $23 million, and $21 million, respectively.
	(c)	Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms.
	(d)	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2017. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 — Regulatory Matters for additional information.
	(e)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information.
	(f)	BGE entered into various contracts for the procurement of electricity that expire between 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters of the Exelon 2014 10-K for additional information.
	(g)	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. See Note 3 —Regulatory Matters of the Exelon 2014 Form 10-K for additional information.
Fuel Purchase Commitments	As of March 31, 2015, these net commitments were as follows:
					Expiration within
		Total			2015			2016			2017			2018			2019		2020
																			and beyond
	Generation	$	8,479		$	1,015		$	1,145		$	1,151		$	987		$	869	$	3,312
	PECO	392			109			104			61			34			13		71
	BGE	614			82			87			74			64			61		246
Other Purchase Obligation	The Registrants’ other purchase obligations as of March 31, 2015, which primarily represent commitments for services, materials and information technology, are as follows:
					Expiration within
		Total			2015			2016			2017			2018			2019		2020
																			and beyond
	Exelon	$	840		$	258		$	279		$	152		$	38		$	30	$	83
	Generation(a)	364			123			81			43			31			23		63
	ComEd(b)	152			53			82			2			2			2		11
	PECO(b)	11			5			6			—			—			—		—
	BGE(b)	313			77			110			107			5			5		9
	_____________________
	(a) Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information.
	(b) Purchase obligations include commitments related to smart meter installation. See Note 5 — Regulatory Matters for additional information.
Commercial Commitments	The Registrants’ commercial commitments as of March 31, 2015, representing commitments potentially triggered by future events were as follows:
		Exelon			Generation			ComEd			PECO			BGE
	Letters of credit (non-debt)(a)	$	1,740		$	1,673		$	18		$	22		$	1
	Guarantees	5,453		(b)	2,678		(c)	202		(d)	196		(e)	263		(f)
	Nuclear insurance premiums(g)	3,014			3,014			—			—			—
	Underwriters discount(h)	60			—			—			—			—
	Total commercial commitments	$	10,267		$	7,365		$	220		$	218		$	264
	___________________
	(a)	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
	(b)	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $642 million at March 31, 2015, which represents the total amount Exelon could be required to fund based on March 31, 2015 market prices.
	(c)	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $429 million at March 31, 2015, which represents the total amount Generation could be required to fund based on March 31, 2015 market prices.
	(d)	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.
	(e)	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
	(f)	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.
	(g)	Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
	(h)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 15 — Common Stock for further details of the equity securities offering.
Accrued environmental liabilities	As of March 31, 2015 and December 31, 2014, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
	31-Mar-15	Total Environmental			Portion of Total Related to
		Investigation and			MGP Investigation and
		Remediation Reserve			Remediation
	Exelon	$	340		$	272
	Generation	62			—
	ComEd	231			228
	PECO	44			42
	BGE	3			2
	December 31, 2014	Total Environmental			Portion of Total Related to
		Investigation and			MGP Investigation  and
		Remediation Reserve			Remediation
	Exelon	$	347		$	277
	Generation	63			—
	ComEd	238			235
	PECO	45			42
	BGE	1			—
Exelon Generation Co L L C [Member] | Equity Method Investments [Member]
Commitments And Contingencies Tables Disclosure [Line Items]
Other Commitments	As of March 31, 2015, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:
		Total
	2015	$	77
	2016	37
	2017	19
	2018	14
	Total	$	147

Supplemental_Financial_Informa1

Supplemental Financial Information (Tables)	3 Months Ended
	Mar. 31, 2015
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, 2015 and 2014:
	Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
	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	(106		)		(106		)		—			—				—
	activities(b)
	Total decommissioning-related activities	92				92				—			—				—
	Investment income (expense)	1				1				—			—				1			(c)
	Long-term lease income	4				—				—			—				—
	Interest income related to uncertain income tax positions	—				1				—			—				—
	AFUDC — Equity	5				—				—			2				3
	Terminated interest rate swaps (d)	(23		)		3				—			—				—
	Other	1				(3		)		3			—				—
	Other, net	$	80			$	94			$	3		$	2			$	4
	Three Months Ended March 31, 2014	Exelon				Generation				ComEd			PECO				BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust funds(a)
	Regulatory agreement units	$	43			$	43			$	—		$	—			$	—
	Non-regulatory agreement units	25				25				—			—				—
	Net unrealized gains on decommissioning trust funds
	Regulatory agreement units	61				61				—			—				—
	Non-regulatory agreement units	13				13				—			—				—
	Net unrealized losses on pledged assets
	Zion Station decommissioning	10				10				—			—				—
	Regulatory offset to decommissioning trust fund-related	(94		)		(94		)		—			—				—
	activities(b)
	Total decommissioning-related activities	58				58				—			—				—
	Investment income (expense)	1				1				—			—				2			(c)
	Long-term lease income	6				—				—			—				—
	Interest income related to uncertain income tax positions	10				14				—			—				—
	AFUDC — Equity	6				—				3			1				3
	Other	17				12				2			1				(1		)
	Other, net	$	98			$	85			$	5		$	2			$	4
	________
	(a)	Includes investment income and realized gains and losses on sales of investments of the trust funds.
	(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2014 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 2014 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 are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
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, 2015 and 2014:
	Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
	Depreciation, amortization, accretion and depletion
	Property, plant and equipment	$	540			$	242			$	154		$	58			$	71
	Regulatory assets	58				—				21			4				35
	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
	Three Months Ended March 31, 2014	Exelon				Generation				ComEd			PECO				BGE
	Depreciation, amortization, accretion and depletion
	Property, plant and equipment	$	481			$	200			$	143		$	56			$	70
	Regulatory assets	72				—				30			2				38
	Amortization of intangible assets, net	11				11				—			—				—
	Amortization of energy contract assets and liabilities(a)	42				44				—			—				—
	Nuclear fuel(b)	234				234				—			—				—
	ARO accretion(c)	68				68				—			—				—
	Total depreciation, amortization, accretion and depletion	$	908			$	557			$	173		$	58			$	108
	_________
	(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.
	Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	159			$	67			$	52		$	10			$	16
	Provision for uncollectible accounts	84				4				22			33				25
	Stock-based compensation costs	39				—				—			—				—
	Other decommissioning-related activity(a)	(44		)		(44		)		—			—				—
	Energy-related options(b)	9				9				—			—				—
	Amortization of regulatory asset related to debt costs	3				—				2			1				—
	Amortization of rate stabilization deferral	25				—				—			—				25
	Amortization of debt fair value adjustment	(9		)		(4		)		—			—				—
	Discrete impacts of 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		)
	Total other non-cash operating activities	$	344			$	45			$	126		$	44			$	64
	Changes in other assets and liabilities:
	Under/over-recovered energy and transmission costs	$	65			$	—			$	—		$	26			$	39
	Other regulatory assets and liabilities	92				—				2			(5		)		25
	Cash deposits(d)	226				226				—			—				—
	Other current assets	(155		)		(100		)		(1		)	(95		)	(e)	30
	Other noncurrent assets and liabilities	(113		)		(41		)		(10		)	2				(1		)
	Total changes in other assets and liabilities	$	115			$	85			$	(9	)	$	(72	)		$	93
	Non-cash investing and financing activities:
	Indemnification of like-kind exchange position(f)	—				—				2			—				—
	Total non-cash investing and financing activities:	$	—			$	—			$	2		$	—			$	—
Cash Flow Supplemental Disclosures
	Three Months Ended March 31, 2015	Exelon				Generation				ComEd			PECO				BGE
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	159			$	67			$	52		$	10			$	16
	Provision for uncollectible accounts	84				4				22			33				25
	Stock-based compensation costs	39				—				—			—				—
	Other decommissioning-related activity(a)	(44		)		(44		)		—			—				—
	Energy-related options(b)	9				9				—			—				—
	Amortization of regulatory asset related to debt costs	3				—				2			1				—
	Amortization of rate stabilization deferral	25				—				—			—				25
	Amortization of debt fair value adjustment	(9		)		(4		)		—			—				—
	Discrete impacts of 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		)
	Total other non-cash operating activities	$	344			$	45			$	126		$	44			$	64
	Changes in other assets and liabilities:
	Under/over-recovered energy and transmission costs	$	65			$	—			$	—		$	26			$	39
	Other regulatory assets and liabilities	92				—				2			(5		)		25
	Cash deposits(d)	226				226				—			—				—
	Other current assets	(155		)		(100		)		(1		)	(95		)	(e)	30
	Other noncurrent assets and liabilities	(113		)		(41		)		(10		)	2				(1		)
	Total changes in other assets and liabilities	$	115			$	85			$	(9	)	$	(72	)		$	93
	Non-cash investing and financing activities:
	Indemnification of like-kind exchange position(f)	—				—				2			—				—
	Total non-cash investing and financing activities:	$	—			$	—			$	2		$	—			$	—
	Three Months Ended March 31, 2014	Exelon				Generation				ComEd			PECO				BGE
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	173			$	75			$	56		$	12			$	16
	Equity method investments	19				19				—			—				—
	Provision for uncollectible accounts	35				1				(11		)	35				11
	Stock-based compensation costs	46				—				—			—				—
	Other decommissioning-related activity(a)	(35		)		(35		)		—			—				—
	Energy-related options(b)	31				31				—			—				—
	Amortization of regulatory asset related to debt costs	3				—				2			1				—
	Amortization of rate stabilization deferral	20				—				—			—				20
	Amortization of debt fair value adjustment	(12		)		(5		)		—			—				—
	Discrete impacts from EIMA(c)	(4		)		—				(4		)	—				—
	Amortization of debt costs	5				3				(5		)	1				—
	Increase in inventory reserve	2				2				—			—				—
	Other	(7		)		(2		)		(2		)	—				(4		)
	Total other non-cash operating activities	$	276			$	89			$	36		$	49			$	43
	Changes in other assets and liabilities:
	Under/over-recovered energy and transmission costs	$	(15	)		$	—			$	4		$	(17	)		$	23
	Other regulatory assets and liabilities	(4		)		—				(10		)	(3		)		6
	Other current assets	(209		)		(80		)		(29		)	(105		)	(e)	18
	Other noncurrent assets and liabilities	(50		)		(23		)		11			(2		)		(3		)
	Total changes in other assets and liabilities	$	(278	)		$	(103	)		$	(24	)	$	(127	)		$	44
	Non-cash investing and financing activities:
	Indemnification of like-kind exchange position(f)	—				—				2			—				—
	Total non-cash investing and financing activities	$	—			$	—			$	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 15 — Asset Retirement Obligations of the Exelon 2014 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
	(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
	(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 — Regulatory Matters for more information.
	(d)	Relates primarily to cash deposits recalled from ISOs/RTOs and replaced with letters of credit.
	(e)	Relates primarily to prepaid utility taxes.
	(f)	See Note 10 — 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, 2015 and December 31, 2014.
	31-Mar-15	Exelon				Generation				ComEd			PECO				BGE
	Property, plant and equipment:
	Accumulated depreciation and amortization	$	15,207		(a)	$	7,905		(a)	$	3,247		$	2,989			$	2,905
	Accounts receivable:
	Allowance for uncollectible accounts	$	365			$	61			$	100		$	127			$	84
	31-Dec-14	Exelon				Generation				ComEd			PECO				BGE
	Property, plant and equipment:
	Accumulated depreciation and amortization	$	14,742		(b)	$	7,612		(b)	$	3,432		$	2,917			$	2,868
	Accounts receivable:
	Allowance for uncollectible accounts	$	311			$	60			$	84		$	100			$	67
	_______
	(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,772 million.
	(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million.

Segment_Information_Tables

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2015
Segment Reporting Information [Line Items]
Analysis and reconciliation of reportable segment information	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, 2015 and 2014 is as follows:
		Generation(a)				ComEd				PECO			BGE				Other(b)				Intersegment Eliminations				Exelon
	Total revenues(c):
	2015	$	5,840			$	1,185			$	985		$	1,036			$	318			$	(534	)		$	8,830
	2014	4,390				1,134				993			1,054				290				(624		)		7,237
	Intersegment revenues(d):
	2015	$	210			$	1			$	—		$	7			$	316			$	(533	)		$	1
	2014	316				1				1			16				290				(623		)		1
	Net income (loss):
	2015	$	485			$	90			$	139		$	109			$	(84	)		$	(1	)		$	738
	2014	(185		)		98				89			88				4				(1		)		93
	Total assets:
	March 31, 2015	$	45,318			$	25,731			$	10,169		$	8,130			$	10,457			$	(12,414	)		$	87,391
	December 31, 2014	45,348				25,392				9,943			8,078				9,794				(11,741		)		86,814
	__________
	(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, 2015 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. For the three months ended March 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $88 million and sales to BGE of $120 million in the Mid-Atlantic region, and sales to ComEd of $108 million in the Midwest region.
	(b)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
	(c)	For the three months ended March 31, 2015 and 2014, utility taxes of $27 million and $24 million, respectively, are included in revenues and expenses for Generation. For the three months ended March 31, 2015 and 2014, utility taxes of $62 million and $63 million, respectively, are included in revenues and expenses for ComEd. For the three months ended March 31, 2015 and 2014, utility taxes of $35 million and $35 million, respectively, are included in revenues and expenses for PECO. For the three months ended March 31, 2015 and 2014, utility taxes of $52 million and $20 million, respectively, are included in revenues and expenses for BGE.
	(d)	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Analysis and reconciliation of reportable segment revenues for Generation
		Three Months Ended March 31, 2015											Three Months Ended March 31, 2014
		Revenues				Intersegment				Total			Revenues				Intersegment				Total
		from external				revenues				Revenues(a)			from external				revenues				Revenues
		customers(b)											customers(b)
	Mid-Atlantic	$	1,517			$	(4	)		$	1,513		$	1,441			$	(23	)		$	1,418
	Midwest	1,275				1				1,276			1,258				12				1,270
	New England	858				1				859			545				4				549
	New York	310				—				310			190				(3		)		187
	ERCOT	182				(2		)		180			243				—				243
	Other Power Regions(c)	212				2				214			334				7				341
	Total Revenues for Reportable Segments	4,354				(2		)		4,352			4,011				(3		)		4,008
	Other(d)	1,486				2				1,488			379				3				382
	Total Generation Consolidated Operating Revenues	$	5,840			$	—			$	5,840		$	4,390			$	—			$	4,390
	__________
	(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, the 2015 financial results include CENG's revenues on a fully consolidated basis.
	(b)	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
	(c)	Other Power Regions include the South, West and Canada, which are not considered individually significant.
	(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $40 million increase to revenues and $93 million decrease to revenues, for the three months ended March 31, 2015 and 2014, respectively, unrealized mark-to-market gains of $154 million and losses of $760 million for the three months ended March 31, 2015 and 2014, respectively, and elimination of intersegment revenues.
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Analysis and reconciliation of reportable segment revenues for Generation
		Three Months Ended March 31, 2015												Three Months Ended March 31, 2014
		RNF					Intersegment				Total			RNF				Intersegment				Total
		from external					RNF				RNF(a)			from external				RNF				RNF
		customers(b)												customers(b)
	Mid-Atlantic	$	784				$	(2	)		$	782		$	784			$	(89	)		$	695
	Midwest	701					(1		)		700			530				26				556
	New England	177					(19		)		158			154				(18		)		136
	New York	174					14				188			(29		)		8				(21		)
	ERCOT	88					(33		)		55			155				(72		)		83
	Other Power Regions(c)	99					(53		)		46			150				(45		)		105
	Total Revenues net of purchased power and fuel expense for Reportable Segments	2,023			—		(94		)		1,929			1,744				(190		)		1,554
	Other(d)	384					94				478			(711		)		190				(521		)
	Total Generation Revenues net of purchased power and fuel expense	$	2,407		—		$	—			$	2,407		$	1,033			$	—			$	1,033
	__________
	(a)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet. As a result, the 2015 financial results include CENG's revenue net of purchased power and fuel expense on a fully consolidated basis.
	(b)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
	(c)	Other Power Regions include the South, West and Canada, which are not considered individually significant.
	(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value of $38 million increase to RNF and $42 million decrease to RNF for the three months ended March 31, 2015 and 2014, respectively, unrealized mark-to-market gains of $162 million and losses of $730 million for the three months ended March 31, 2015 and 2014, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

Basis_of_Presentation_Narrativ

Basis of Presentation - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Total interest expense to affiliates, net	$10	$10
Pretax decrease in operating and maintenance expense	-2,081	-1,858
Pretax increase in taxes other than income	304	293
Income (Loss) from Equity Method Investments		-19
Income (Loss) from Equity Method Investments, Net of Dividends or Distributions	1
Exelon Generation Co L L C [Member]
Purchased power and fuel from affiliates	7	349
Total interest expense to affiliates, net	12	12
Pretax decrease in operating and maintenance expense	-1,162	-938
Pretax increase in taxes other than income	122	105
Income (Loss) from Equity Method Investments		-19
Baltimore Gas and Electric Company [Member]
Total interest expense to affiliates, net	4	4
Purchased power and fuel	350	409
Pretax decrease in operating and maintenance expense	-156	-163
Pretax increase in taxes other than income	57	60
Income (Loss) from Equity Method Investments		$0

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014	Apr. 01, 2014
			VIE
Variable Interest Entity [Line Items]
Number of Variable Interest Entities not consolidated by equity holders	7		6
Number Of Variable Interest Entities Consolidated	6
Guarantor Obligations, Current Carrying Value	$75,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	10,267,000,000
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Equity Method Investment, Ownership Percentage		50.01%
Related Party Transaction Required Purchase Of Power Percentage	85.00%
Guarantor Obligations, Current Carrying Value	7,000,000
Related Party Purchase Of Nuclear Output By Third Party Percentage	49.99%
Payables to affiliates	110,000,000		107,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	7,365,000,000
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
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Current Carrying Value	637,000,000
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	264,000,000
Baltimore Gas and Electric Company [Member] | RSB Bond Co LLC [Member]
Variable Interest Entity [Line Items]
Remittance of payments received from customers for rate stabilization to BondCo.	21,000,000	21,000,000
Constellation Energy Nuclear Group [Member]
Variable Interest Entity [Line Items]
Severance Benefits Obligations Balance				6,000,000
Severance Costs	2,000,000
Constellation Energy Nuclear Group [Member] | Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Due from Affiliates	288,000,000			400,000,000
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

Variable_Interest_Entities_Car

Variable Interest Entities - Carrying Amounts and Classification of Consolidated VIE Assets and Liabilities (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014
In Millions, unless otherwise specified
Variable Interest Entity [Line Items]
Current Assets	$1,185	[1],[2]	$1,271	[1]
Non Current Assets	7,676	[1],[2]	7,580	[1]
Total Assets	8,861	[1],[2]	8,851	[1]
Current Liabilities	520	[1],[2]	611	[1]
Non Current Liabilities	2,812	[1],[2]	2,730	[1]
Total Liabilities	3,332	[1],[2]	3,341	[1]
Assets	87,391		86,814		86,814
Total liabilities	62,753	[3]	62,681	[3]
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Assets	8,182		8,160
Total liabilities	2,702		2,723
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Current Assets	1,134	[2]	1,242
Non Current Assets	7,664	[2]	7,566
Total Assets	8,798	[2]	8,808
Current Liabilities	434	[2]	526
Non Current Liabilities	2,682	[2]	2,600
Total Liabilities	3,116	[2]	3,126
Assets	45,318	[4]	45,348	[4]
Total liabilities	32,150	[4]	31,297	[4]
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Assets	8,118		8,119
Total liabilities	2,486		2,507
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Current Assets	46		21
Non Current Assets	3		3
Total Assets	49		24
Current Liabilities	80		77
Non Current Liabilities	120		120
Total Liabilities	200		197
Assets	8,130		8,078
Total liabilities	5,307	[5]	5,325	[5]
Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Assets	49		24
Total liabilities	$200		$197
[1]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[2]	.
[3]	Exelon’s consolidated assets include $8,182 million and $8,160 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,702 million and $2,723 million at March 31, 2015 and December 31, 2014, 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 $8,118 million and $8,119 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,486 million and $2,507 million at March 31, 2015 and December 31, 2014, 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 $49 million and $24 million at March 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $200 million and $197 million at March 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 — Variable Interest Entities.

Variable_Interest_Entities_Ass

Variable Interest Entities - Assets and Liabilities of VIES which Creditors or Beneficiaries have no Recourse (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014		Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Variable Interest Entity [Line Items]
Cash and cash equivalents	$1,825		$1,878		$914	$1,609
Restricted cash	297		271
Accounts receivable, net
Customer	3,702		3,482
Other	1,077		1,227
Inventory
Materials and supplies	1,035		1,024
Other current assets	793		865
Mark-to-market derivative assets (current assets)	1,117		1,279
Total current assets	11,357		12,097
Property, plant and equipment, net	53,001		52,087
Nuclear decommissioning trust funds	10,712		10,537
Goodwill	2,672		2,672
Mark-to-market derivative assets	913		773
Other noncurrent assets	1,234		1,160
Total assets	87,391		86,814		86,814
Short-term borrowings	309		460
Long-term debt due within one year	1,260		1,802
Accounts payable	2,839		3,048
Accrued expenses	1,230		1,539
Mark-to-market derivative liabilities (current liabilities)	117		234
Other current liabilities	172		238
Other	1,018		1,123
Total current liabilities	7,374		8,762
Long-term debt	20,519		19,362
Asset retirement obligations	7,446		7,295
Pension obligation(a)	3,154		3,366
Energy Marketing Contract Liabilities, Noncurrent	189		211
Other noncurrent liabilities	2,166		2,147
Total deferred credits and other liabilities	34,212		33,909
Total liabilities	62,753	[1]	62,681	[1]
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	334		392
Restricted cash	159		117
Accounts receivable, net
Customer	296		297
Other	33		57
Inventory
Materials and supplies	168		172
Other current assets	40		33
Mark-to-market derivative assets (current assets)	130		171
Total current assets	1,160		1,239
Property, plant and equipment, net	4,720		4,638
Nuclear decommissioning trust funds	2,114		2,097
Goodwill	47		47
Mark-to-market derivative assets	51		44
Other noncurrent assets	90		95
Total noncurrent assets	7,022		6,921
Total assets	8,182		8,160
Long-term debt due within one year	85		87
Accounts payable	268		292
Accrued expenses	77		111
Mark-to-market derivative liabilities (current liabilities)	10		24
Other current liabilities	9		22
Other	18		25
Total current liabilities	467		561
Long-term debt	211		212
Asset retirement obligations	1,843		1,763
Pension obligation(a)	9	[2]	9	[2]
Energy Marketing Contract Liabilities, Noncurrent	48		51
Other noncurrent liabilities	124		127
Total deferred credits and other liabilities	2,235		2,162
Total liabilities	2,702		2,723
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	532		780		566	1,258
Restricted cash	179		158
Accounts receivable, net
Customer	2,320		2,295
Other	378		318
Inventory
Materials and supplies	841		847
Other current assets	530		658
Mark-to-market derivative assets (current assets)	1,116		1,276
Total current assets	6,719		7,638
Property, plant and equipment, net	23,414		22,945
Nuclear decommissioning trust funds	10,712		10,537
Goodwill	47		47
Mark-to-market derivative assets	911		771
Other noncurrent assets	776		731
Total assets	45,318	[3]	45,348	[3]
Short-term borrowings	25		36
Long-term debt due within one year	75		58
Accounts payable	1,634		1,759
Accrued expenses	694		886
Mark-to-market derivative liabilities (current liabilities)	97		214
Other current liabilities	172		238
Other	532		605
Total current liabilities	4,275		4,459
Long-term debt	7,477		6,709
Asset retirement obligations	7,296		7,146
Energy Marketing Contract Liabilities, Noncurrent	189		211
Other noncurrent liabilities	764		719
Total deferred credits and other liabilities	19,458		19,186
Total liabilities	32,150	[3]	31,297	[3]
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	334		392
Restricted cash	113		96
Accounts receivable, net
Customer	296		297
Other	33		57
Inventory
Materials and supplies	168		172
Other current assets	34		26
Mark-to-market derivative assets (current assets)	130		171
Total current assets	1,108		1,211
Property, plant and equipment, net	4,720		4,638
Nuclear decommissioning trust funds	2,114		2,097
Goodwill	47		47
Mark-to-market derivative assets	51		44
Other noncurrent assets	78		82
Total noncurrent assets	7,010		6,908
Total assets	8,118		8,119
Long-term debt due within one year	5		5
Accounts payable	268		292
Accrued expenses	71		108
Mark-to-market derivative liabilities (current liabilities)	10		24
Other current liabilities	9		22
Other	18		25
Total current liabilities	381		476
Long-term debt	81		81
Asset retirement obligations	1,843		1,763
Pension obligation(a)	9	[2]	9	[2]
Energy Marketing Contract Liabilities, Noncurrent	48		51
Other noncurrent liabilities	124		127
Total deferred credits and other liabilities	2,105		2,031
Total liabilities	2,486		2,507
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	41		64		23
Restricted cash	48		50
Accounts receivable, net
Customer	489		390
Other	99		82
Inventory
Materials and supplies	33		30
Other current assets	4		5
Total current assets	962		957
Property, plant and equipment, net	6,280		6,204
Other noncurrent assets	28		25
Total assets	8,130		8,078
Short-term borrowings	0		120
Long-term debt due within one year	75		75
Accounts payable	222		215
Accrued expenses	155		131
Other	27		51
Total current liabilities	780		846
Long-term debt	1,867		1,867
Asset retirement obligations	18		17
Other noncurrent liabilities	62		60
Total deferred credits and other liabilities	2,402		2,354
Total liabilities	5,307	[4]	5,325	[4]
Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	0		0
Restricted cash	46		21
Accounts receivable, net
Customer	0		0
Other	0		0
Inventory
Materials and supplies	0		0
Other current assets	0		0
Mark-to-market derivative assets (current assets)	0		0
Total current assets	46		21
Property, plant and equipment, net	0		0
Nuclear decommissioning trust funds	0		0
Goodwill	0		0
Mark-to-market derivative assets	0		0
Other noncurrent assets	3		3
Total noncurrent assets	3		3
Total assets	49		24
Long-term debt due within one year	75		75
Accounts payable	0		0
Accrued expenses	5		2
Mark-to-market derivative liabilities (current liabilities)	0		0
Other current liabilities	0		0
Other	0		0
Total current liabilities	80		77
Long-term debt	120		120
Asset retirement obligations	0		0
Pension obligation(a)	0	[2]	0	[2]
Energy Marketing Contract Liabilities, Noncurrent	0		0
Other noncurrent liabilities	0		0
Total deferred credits and other liabilities	120		120
Total liabilities	$200		$197
[1]	Exelon’s consolidated assets include $8,182 million and $8,160 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,702 million and $2,723 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.
[2]	Includes 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 12 — Retirement Benefits for additional details.
[3]	Generation’s consolidated assets include $8,118 million and $8,119 million at March 31, 2015 and December 31, 2014, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,486 million and $2,507 million at March 31, 2015 and December 31, 2014, 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 $49 million and $24 million at March 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $200 million and $197 million at March 31, 2015 and December 31, 2014, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 — Variable Interest Entities.

Variable_Interest_Entities_Sum

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Variable Interest Entity [Line Items]
Total assets	$344	[1]	$597	[1]
Total liabilities	79	[1]	286	[1]
Exelon's ownership interest in VIE	9	[1]	9	[1]
Other ownership interests in VIE	256	[1]	302	[1]
Assets Held-in-trust, Noncurrent	308		319
Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	259	[1]	506	[1]
Total liabilities	32	[1]	237	[1]
Exelon's ownership interest in VIE	0	[1]	0	[1]
Other ownership interests in VIE	227	[1]	269	[1]
Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	85	[1]	91	[1]
Total liabilities	47	[1]	49	[1]
Exelon's ownership interest in VIE	9	[1]	9	[1]
Other ownership interests in VIE	29	[1]	33	[1]
Investments [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	13
Investments [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss			13
Investments [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	0		0
Investments [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	13		13
Contract Intangible Asset [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	9		9
Contract Intangible Asset [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	9		9
Payment Guarantee [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	3
Payment Guarantee [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss			3
Payment Guarantee [Member] | Maximum [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	3		3
Asset Held In Trust Noncurrent [Member] | Maximum [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	27	[2]	27	[2]
Asset Held In Trust Noncurrent [Member] | Maximum [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Registrants' maximum exposure to loss	27	[2]	27	[2]
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Assets Held-in-trust, Noncurrent	308		319
Payable to Zion Solutions	$281	[3]	$292	[3]
[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 include, gross pledged assets of $308 million and $319 million as of March 31, 2015 and December 31, 2014, respectively; offset by payables to ZionSolutions, LLC of $281 million and $292 million as of March 31, 2015 and December 31, 2014, 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_Dispo1

Mergers, Acquisitions, and Dispositions - Narrative (Details) (USD $)	3 Months Ended			12 Months Ended	0 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014	Jan. 21, 2015	Nov. 14, 2014	Jun. 30, 2014	Jun. 11, 2014	1-May-14	Jul. 18, 2014
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross	$15,000,000		$0
Business Combination, Integration Related Costs	69,000,000
Temporary Equity, Share Subscriptions							57.5	57.5
Line of Credit Facility, Maximum Borrowing Capacity	8,500,000,000	[1]
Bridge Loan	3,200,000,000								7,200,000,000
Other noncurrent assets	1,234,000,000			1,160,000,000
Business Combination, Separately Recognized Transactions, Expenses and Losses Recognized	289,000,000
MARYLAND
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Acquisition, Preacquisition Contingency, Amount of Settlement	94,400,000
Customer Loyalty Program Liability, Noncurrent	4,000,000
BusinessAcquisitionPreacquisitionContingencyCapacityOfSettlementMwH	15
MARYLAND | Stability Fund [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Acquisition, Preacquisition Contingency, Amount of Settlement	19,800,000
Prince George County [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
BusinessAcquisitionPreacquisitionContingencyCapacityOfSettlementMwH	5
Pepco Holdings [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Acquisition, Transaction Costs								220,000,000
Cash Funding From Non Core Asset Sale				1,000,000,000
Expected Debt Issuance				3,500,000,000
Temporary Equity, Share Subscriptions								23
Line of Credit Facility, Maximum Borrowing Capacity								7,200,000,000
Cash offered in exchange for each share of PHI stock				$35						$27.25
Other Long-term Investments										18,000,000
Other noncurrent assets	144,000,000
Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds	7,200,000,000
Business Acquisition, Preacquisition Contingency, Amount of Settlement	300,000,000
Pepco Holdings [Member] | Energy Efficiency Program [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Customer Loyalty Program Liability, Noncurrent	57,600,000
Pepco Holdings [Member] | Rate Bill Credits [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Customer Loyalty Program Liability, Noncurrent	36,800,000
Pepco Holdings [Member] | Minimum [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Exit Costs				259,000,000
Pepco Holdings [Member] | Maximum [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Exit Costs				293,000,000
Other Long-term Investments										180,000,000
Delmarva Power & Light [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Acquisition, Preacquisition Contingency, Amount of Settlement	40,000,000
Delmarva Power & Light [Member] | Workforce Development [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Customer Loyalty Program Liability, Noncurrent	2,000,000
Delmarva Power & Light [Member] | Energy Efficiency Program [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Customer Loyalty Program Liability, Noncurrent	2,000,000
Atlantic City Electric [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Business Acquisition, Preacquisition Contingency, Amount of Settlement	50,000,000
Exelon Generation Co L L C [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross	15,000,000		0
Equity Method Investment, Ownership Percentage			50.01%
Other noncurrent assets	776,000,000			731,000,000
Proceeds from Sale of Productive Assets					1,800,000,000
Exelon Generation Co L L C [Member] | Integrys Energy Services [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Payments to Acquire Businesses, Gross						319,000,000
Business Combination, Consideration Transferred, Liabilities Incurred						13,000,000
Business Combination, Consideration Transferred						332,000,000
Junior Subordinated Debt [Member] | Pepco Holdings [Member]
Payments to Acquire Businesses and Interest in Affiliates [Abstract]
Subordinated Debt, Amount				$1,200,000,000
[1]	Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 16, 2015. These facilities are solely utilized to issue letters of credit. As of March 31, 2015, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $16 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion to support the PHI transaction discussed below.

Mergers_Acquisitions_and_Dispo2

Mergers, Acquisitions, and Dispositions - Assets Disposition Table (Details) (USD $)	0 Months Ended
	Jan. 21, 2015	Mar. 31, 2015	Dec. 31, 2014
Assets Disposition Table [Line Items]
Total assets held for sale		$1,000,000	$147,000,000
Accrued expenses		1,230,000,000	1,539,000,000
Other current liabilities		1,018,000,000	1,123,000,000
Exelon Generation Co L L C [Member]
Assets Disposition Table [Line Items]
Proceeds from Sale of Productive Assets	1,800,000,000
Total assets held for sale		1,000,000	147,000,000
Accrued expenses		694,000,000	886,000,000
Other current liabilities		532,000,000	605,000,000
Proceed from sale of asset net of tax	$1,400,000,000

Regulatory_Matters_Narrative_D

Regulatory Matters - Narrative (Details) (USD $)	3 Months Ended				12 Months Ended	0 Months Ended					1 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014	Dec. 08, 2014	Aug. 21, 2014	Dec. 13, 2013	17-May-13	Feb. 27, 2013	Aug. 31, 2010	Oct. 20, 2015	Apr. 28, 2014	Aug. 23, 2013	Jun. 03, 2014
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	$6,872				$6,923
Rate of Return on Common Equity, Incentive Basis Points	0.50%
Regulatory assets	6,068				6,076
Transmission Rate Formula, First Basis Points Credited	0.50%
Business Combination, Integration Related Costs	69
Regulatory Liabilities	4,987				4,860
Revenues	8,830	[1]	7,237	[1]
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	1,183				1,201
Public Utilities, Requested Rate Increase (Decrease), Amount	50
Expected revenue adjustment for current year	92
Expected revenue adjustment for prior year					142
Requested Debt and Equity Return on Distribution	7.05%
Requested ROE	9.14%				9.09%
Weighted Average Debt And Equity Return Electric Distribution	7.02%
Weighted Average Debt And Equity Return	8.61%				8.62%
Gross transmission revenue requirement	73
Transmission revenue true up	18
Net transmission revenue requirement	91
Regulatory assets	866				852
Rate Of Return On Common Equity	11.50%
Common Equity Component Cap	55.00%
Regulatory Liabilities	3,823				3,780
Revenues	1,185		1,134
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
CostRecoveryForSignificantOneTimeEvents	76				85
UnderOverRecoveredDistributionServiceCosts	240				286
Business Combination, Integration Related Costs	17				19
RegulatoryAssetsDueToDeferredStormCosts	59				66
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	1,584				1,558
Spend on smart grid investments	155
Public Utilities, Requested Rate Increase (Decrease), Amount	190
Requested ROE	10.95%
Public Utilities, Requested Rate Increase (Decrease), Percentage	4.40%
TotalSmartMetersInstalled	1,700,000
SmartMeterFundingSGIG	200
Smart meter spend to date	568
Smart grid infrastructure spend to date	155
Total smart grid and smart meter investment grant amount	591
Regulatory assets	1,543				1,529
Amount of Regulatory Costs Not yet Approved	275
Regulatory Liabilities	781				747
Revenues	985		993
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	678				724
Public Utilities, Requested Rate Increase (Decrease), Amount									24
Weighted Average Debt And Equity Return	8.46%												8.53%
Adjustment to Requested increase in electric revenues														83
Rate of return on common equity electric distribution								9.75%
Rate of return on common equity gas distribution								9.60%
Increase in electric delivery service revenue resulting from rate case settlement or order.								34
Increase in gas delivery service revenue resulting from rate case settlement or order.								12
Gross transmission revenue requirement	13
Transmission revenue true up	3
Net transmission revenue requirement	10
Revenue Reduction							14
Customer Refund Liability, Noncurrent							13
Estimated number of smart meters to be installed											2,000,000
Reimbursements received from the DOE											200
Regulatory assets	491				510
Total Projected smart meter smart grid spend											480
Customer Refund							13
Rate Of Return On Common Equity	11.30%
Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint						8.80%				8.70%
Regulatory Liabilities	311				244
Revenues	1,036		1,054
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
License Costs	40
Other Commitment	3.5
Revenues	5,840		4,390
Exelon Generation Co L L C [Member] | Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Minimum Purchase Obligation															25
Exelon Generation Co L L C [Member] | Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maximum Purchase Obligation															35
Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	316				371
Under Recovered Distribution Service Costs [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	316				371
Under Recovered Distribution Service Costs [Member] | PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	0				0
Under Recovered Distribution Service Costs [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	0				0
AMI Expenses [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	325				296
AMI Expenses [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	106				91
AMI Expenses [Member] | PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	76				77
AMI Expenses [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	143				128
Regulatory assets	143				128
Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	230				248
Energy Efficiency And Demand Response Programs [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	0				0
Energy Efficiency And Demand Response Programs [Member] | PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	0				0
Energy Efficiency And Demand Response Programs [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	230				248
Transmission Rate Formula [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net regulatory asset	25				21
Net Regulatory Asset	25				21
Transmission Rate Formula [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net regulatory asset	2				1
Net Regulatory Asset	2				1
Distribution formula Rate [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net Regulatory Assets	316				371
Stride Program [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets	1
Under-Recovered Electric Supply Costs [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
ElectricTransmissionCostsUnderRecovery	5				4
Business Combination, Integration Related Costs	7				7
Under Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	41				48
Under Recovered Energy And Transmission Costs [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	37				33
ElectricTransmissionCostsUnderRecovery	25				22
Under Recovered Energy And Transmission Costs [Member] | PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	0				0
Under Recovered Energy And Transmission Costs [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Assets	4				15
Renewable Energy Requirement [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenues	18		16
FERC Transmission Complaint [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Approved ROE										10.80%
Scenario, Forecast [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue Reduction												-11
Over Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities	142				84
Over Recovered Energy And Transmission Costs [Member] | Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
ElectricTransmissionCostsUnderRecovery	5				3
Regulatory Liabilities	23				19
Over Recovered Energy And Transmission Costs [Member] | PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities	84				58
Over Recovered Energy And Transmission Costs [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities	$35				$7
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}

Regulatory_Matters_Regulatory_

Regulatory Matters Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Regulatory Assets [Line Items]
Current	$804	$847
Noncurrent	6,068	6,076
Regulatory Assets	6,872	6,923
Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Regulatory Assets	3,248	3,256
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Assets	1,561	1,542
AMI Expenses [Member]
Regulatory Assets [Line Items]
Regulatory Assets	325	296
Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	316	371
Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	54	57
Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	184	190
Employee Severance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	11	12
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	119	116
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	250	257
Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Regulatory Assets	62	67
Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Regulatory Assets	241	207
Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	41	48
Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	3	3
Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets	28	30
Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	136	160
Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	230	248
Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	8	8
ConservativeVoltageReductionProgram [Member]
Regulatory Assets [Line Items]
Regulatory Assets	2	2
Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	53	46
Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Regulatory Assets		7
Commonwealth Edison Co [Member]
Regulatory Assets [Line Items]
Current	317	349
Noncurrent	866	852
Regulatory Assets	1,183	1,201
Commonwealth Edison Co [Member] | Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Assets	65	64
Commonwealth Edison Co [Member] | AMI Expenses [Member]
Regulatory Assets [Line Items]
Regulatory Assets	106	91
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	316	371
Commonwealth Edison Co [Member] | Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	51	53
Commonwealth Edison Co [Member] | Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Employee Severance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	75	74
Commonwealth Edison Co [Member] | Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	213	219
Commonwealth Edison Co [Member] | Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Regulatory Assets	62	67
Commonwealth Edison Co [Member] | Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Regulatory Assets	241	207
Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	37	33
Commonwealth Edison Co [Member] | Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | ConservativeVoltageReductionProgram [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Commonwealth Edison Co [Member] | Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	17	22
Commonwealth Edison Co [Member] | Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Regulatory Assets		0
PECO Energy Co [Member]
Regulatory Assets [Line Items]
Current	41	29
Noncurrent	1,543	1,529
Regulatory Assets	1,584	1,558
PECO Energy Co [Member] | DSP Program [Member]
Regulatory Assets [Line Items]
Regulatory Assets	42	39
PECO Energy Co [Member] | Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Assets	1,419	1,400
PECO Energy Co [Member] | AMI Expenses [Member]
Regulatory Assets [Line Items]
Regulatory Assets	76	77
PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	3	4
PECO Energy Co [Member] | Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Employee Severance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	26	26
PECO Energy Co [Member] | Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	36	37
PECO Energy Co [Member] | Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | ConservativeVoltageReductionProgram [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
PECO Energy Co [Member] | Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	24	14
PECO Energy Co [Member] | Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Regulatory Assets		0
PECO Energy Co [Member] | Over-Recovered Natural Gas Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	34	3
PECO Energy Co [Member] | Over Recovered Electric Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	8	16
Baltimore Gas and Electric Company [Member]
Regulatory Assets [Line Items]
Current	187	214
Noncurrent	491	510
Regulatory Assets	678	724
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Baltimore Gas and Electric Company [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Regulatory Assets	77	78
Baltimore Gas and Electric Company [Member] | AMI Expenses [Member]
Regulatory Assets [Line Items]
Noncurrent	143	128
Regulatory Assets	143	128
Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Baltimore Gas and Electric Company [Member] | Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	8	9
Baltimore Gas and Electric Company [Member] | Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Baltimore Gas and Electric Company [Member] | Employee Severance [Member]
Regulatory Assets [Line Items]
Regulatory Assets	11	12
Baltimore Gas and Electric Company [Member] | Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	18	16
Baltimore Gas and Electric Company [Member] | Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	1	1
Baltimore Gas and Electric Company [Member] | Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Baltimore Gas and Electric Company [Member] | Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	0
Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	4	15
Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	3	3
Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets	28	30
Baltimore Gas and Electric Company [Member] | Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	136	160
Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	230	248
Baltimore Gas and Electric Company [Member] | Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Current	4	4
Regulatory Assets	8	8
Baltimore Gas and Electric Company [Member] | ConservativeVoltageReductionProgram [Member]
Regulatory Assets [Line Items]
Regulatory Assets	2	2
Baltimore Gas and Electric Company [Member] | Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets	9	7
Baltimore Gas and Electric Company [Member] | Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Regulatory Assets		7
Baltimore Gas and Electric Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	1
Baltimore Gas and Electric Company [Member] | Under-Recovered Electric Revenue Decoupling [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$7

Regulatory_Matters_Regulatory_1

Regulatory Matters Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Regulatory Liabilities [Line Items]
Regulatory Assets	$6,872	$6,923
Current	421	310
Noncurrent	4,566	4,550
Regulatory Liabilities	4,987	4,860
Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	72	88
Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	2,920	2,879
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,567	1,566
Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	27	27
Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	10	10
Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	38	32
Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	106	102
Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	34	49
Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	142	84
Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	3	2
Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	3	3
Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	56	12
Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	9	6
Baltimore Gas and Electric Company [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	678	724
Current	124	44
Noncurrent	187	200
Regulatory Liabilities	311	244
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Gas Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	37	12
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Electric Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	19
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	216	223
Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	35	7
Baltimore Gas and Electric Company [Member] | Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	56	12
Baltimore Gas and Electric Company [Member] | Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	4	2
Baltimore Gas and Electric Company [Member] | Over-Recovered Natural Gas Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	31	7
Baltimore Gas and Electric Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	4	10
PECO Energy Co [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	1,584	1,558
Current	119	90
Noncurrent	662	657
Regulatory Liabilities	781	747
PECO Energy Co [Member] | Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
PECO Energy Co [Member] | Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	500	490
PECO Energy Co [Member] | Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	2	2
PECO Energy Co [Member] | Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	10	10
PECO Energy Co [Member] | Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	38	32
PECO Energy Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	106	102
PECO Energy Co [Member] | Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	34	49
PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	84	58
PECO Energy Co [Member] | Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	3	2
PECO Energy Co [Member] | Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
PECO Energy Co [Member] | Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
PECO Energy Co [Member] | Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	4	2
Commonwealth Edison Co [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	1,183	1,201
Current	131	125
Noncurrent	3,692	3,655
Regulatory Liabilities	3,823	3,780
Commonwealth Edison Co [Member] | Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	2,420	2,389
Commonwealth Edison Co [Member] | Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1,351	1,343
Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	25	25
Commonwealth Edison Co [Member] | Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	23	19
Commonwealth Edison Co [Member] | Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	3	3
Commonwealth Edison Co [Member] | Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	0	0
Commonwealth Edison Co [Member] | Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	1	1
Under Recovered Distribution Service Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	316	371
Under Recovered Distribution Service Costs [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	0	0
Under Recovered Distribution Service Costs [Member] | PECO Energy Co [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	0	0
Under Recovered Distribution Service Costs [Member] | Commonwealth Edison Co [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	316	371
Under Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	41	48
Under Recovered Energy And Transmission Costs [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	4	15
Under Recovered Energy And Transmission Costs [Member] | PECO Energy Co [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	0	0
Under Recovered Energy And Transmission Costs [Member] | Commonwealth Edison Co [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets	37	33
Under-Recovered Electric Revenue Decoupling [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Liabilities [Line Items]
Regulatory Assets		$7

Regulatory_Matters_Regulatory_2

Regulatory Matters Regulatory Matters - Purchase of Receivables Programs (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Purchase Of Receivables [Line Items]
Purchased receivables	$336	[1]	$290	[1]
Allowance for uncollectible accounts	-51	[2]	-42	[2]
Purchased receivables, net	285		248
Commonwealth Edison Co [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	150	[1]	139	[1]
Allowance for uncollectible accounts	-25	[2]	-21	[2]
Purchased receivables, net	125		118
PECO Energy Co [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	91	[1]	76	[1]
Allowance for uncollectible accounts	-10	[2]	-8	[2]
Purchased receivables, net	81		68
Discount rate	1.00%
Baltimore Gas and Electric Company [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	95	[1]	75	[1]
Allowance for uncollectible accounts	-16	[2]	-13	[2]
Purchased receivables, net	$79		$62
[1]	ECO’s gas POR program became effective on January 1, 2012 and includes a 1% discount on purchased receivables in order to recover the implementation costs of the program. If the costs are not fully recovered when PECO files its next gas distribution rate case, PECO will propose a mechanism to recover the remaining implementation costs as a distribution charge to low volume transportation customers or apply future discounts on purchased receivables from natural gas suppliers serving those customers.
[2]	or ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

Investment_in_Constellation_En2

Investment in Constellation Energy Nuclear Group LLC - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014		Dec. 31, 2013		Apr. 01, 2014
Schedule of Equity Method Investments [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$10,267,000,000
Revenues	8,830,000,000	[1]	7,237,000,000	[1]
Accumulated other comprehensive loss, net	-2,673,000,000	[2]	-2,036,000,000	[2]	-2,684,000,000	[2]	-2,040,000,000	[2]
Other Comprehensive Income (Loss), Tax	-12,000,000		-6,000,000
Revenue from Related Parties	1,000,000	[3]	1,000,000	[3]
Guarantor Obligations, Current Carrying Value	75,000,000
Business Combination, Integration Related Costs	69,000,000
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage			50.01%
Interest Rate	3.71%
Payments of Distributions to Affiliates	1,356,000,000		30,000,000
Related Party Purchase Of Nuclear Output By Third Party Percentage	49.99%
Payables to affiliates	110,000,000				107,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	7,365,000,000
Total equity investment earnings (losses) - CENG			19,000,000
Revenues	5,840,000,000		4,390,000,000
Accumulated other comprehensive loss, net	-53,000,000	[2]	193,000,000	[2]	-36,000,000	[2]	214,000,000	[2]
Other Comprehensive Income (Loss), Tax	5,000,000		10,000,000
Related Party Transaction Required Purchase Of Power Percentage	85.00%
Revenue from Related Parties	211,000,000		334,000,000
Guarantor Obligations, Current Carrying Value	7,000,000
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Revenues	197,000,000		17,000,000
Investment in CENG			1,900,000,000
Accumulated other comprehensive loss, net			116,000,000
Other Comprehensive Income (Loss), Tax			77,000,000
Electricite De France LLC [Member]
Schedule of Equity Method Investments [Line Items]
Related Party Transaction Required Purchase Of Power Percentage	15.00%
Constellation Energy Nuclear Group [Member] | Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Due from Affiliates	288,000,000								400,000,000
Reduction To Net Income Attributable To Noncontrolling Interest	4,000,000
Net Income (Loss) Attributable to Parent	98,000,000
EDFI [Member] | Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Revenue from Related Parties	182,000,000
Payment Guarantee [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Payables to affiliates									245,000,000
Financial Guarantee [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted									165,000,000
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]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}
[2]	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.
[3]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NzEwQ0VGNzJGQTI1RkM2RDgzOUMwOTNBRjYwNUU2MTQM}

Impairment_of_LongLived_Assets

Impairment of Long-Lived Assets (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Proceeds From Lease Termination	$0	$335
Operating and maintenance	2,081	1,858
Exelon Generation Co L L C [Member]
Capital Leases, Net Investment in Direct Financing Leases [Abstract]
Operating and maintenance	$1,162	$938

Fair_Value_of_Financial_Assets2

Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at the Carrying Amount (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Reported Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	$312	$463
Long-term debt (including amounts due within one year)	21,779	21,164
Long-term debt to financing trusts	648	648
SNF obligation	1,021	1,021
Estimate of Fair Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	312	463
Long-term debt (including amounts due within one year)	23,985	22,936
Long-term debt to financing trusts	672	648
SNF obligation	843	833
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	3	3
Long-term debt (including amounts due within one year)	1,119	1,208
Long-term debt to financing trusts	0	0
SNF obligation	0	0
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	309	448
Long-term debt (including amounts due within one year)	21,486	20,417
Long-term debt to financing trusts	0	0
SNF obligation	843	833
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	12
Long-term debt (including amounts due within one year)	1,380	1,311
Long-term debt to financing trusts	672	648
SNF obligation	0	0
Exelon Generation Co L L C [Member] | Reported Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	25	36
Long-term debt (including amounts due within one year)	8,492	8,266
SNF obligation	1,021	1,021
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	25	36
Long-term debt (including amounts due within one year)	9,265	8,822
SNF obligation	843	833
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
SNF obligation	0	0
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	25	24
Long-term debt (including amounts due within one year)	7,885	7,511
SNF obligation	843	833
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	12
Long-term debt (including amounts due within one year)	1,380	1,311
SNF obligation	0	0
Commonwealth Edison Co [Member] | Reported Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	283	304
Long-term debt (including amounts due within one year)	6,359	5,958
Long-term debt to financing trusts	206	206
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	283	304
Long-term debt (including amounts due within one year)	7,347	6,788
Long-term debt to financing trusts	206	213
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	0	0
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	283	304
Long-term debt (including amounts due within one year)	7,347	6,788
Long-term debt to financing trusts	0	0
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	206	213
PECO Energy Co [Member] | Reported Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	2,246	2,246
Long-term debt to financing trusts	184	184
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	2,602	2,537
Long-term debt to financing trusts	201	199
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	0	0
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	2,602	2,537
Long-term debt to financing trusts	0	0
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	201	199
Baltimore Gas and Electric Company [Member] | Reported Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	3	123
Long-term debt (including amounts due within one year)	1,942	1,942
Long-term debt to financing trusts	258	258
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	3	123
Long-term debt (including amounts due within one year)	2,234	2,178
Long-term debt to financing trusts	265	236
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	3	3
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	0	0
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	120
Long-term debt (including amounts due within one year)	2,234	2,178
Long-term debt to financing trusts	0	0
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	$265	$236

Fair_Value_of_Financial_Assets3

Fair Value of Financial Assets and Liabilities - Fair Value Measurements of Assets and Liabilities, Recurring and Nonrecurring (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	$1,107		$1,119
Fixed income
Other investments	5		5
Total assets	14,236		14,081
Deferred compensation obligation	-103		-107
Total liabilities	-711		-744
Total net assets	13,525		13,337
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-103		-107
Mark-to-market derivative liabilities	491		403
Derivative Liability, Current	117		234
Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	264		245
Equity
Domestic	4,686		4,630
Foreign	639		612
Equity funds subtotal	5,325		5,242
Fixed income
U.S. Treasury and agencies	1,201		996
State and municipal debt	423		438
Financial Instruments, Owned, at Fair Value	488
Other	89		95
Corporate debt securities	2,159		2,262
Commingled funds			511
Fixed income subtotal	4,360		4,302
Middle market lending	363		366
Private Equity	95		83
Other	323		301
Fair Value Assets Measured On Recurring Basis Real Estate	9		3
Nuclear decommissioning trust fund investments subtotal	10,739		10,542
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments	-27		-5
Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	19		15
Equity
Domestic	7		7
Fixed income
U.S. Treasury and agencies	5		8
State and municipal debt	10		10
Financial Instruments, Owned, at Fair Value	4
Corporate debt securities	84		89
Commingled funds			3
Fixed income subtotal	103		110
Middle market lending	178		184
Pledged assets for Zion Station decommissioning subtotal	307		316
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments	1		3
Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			1
Fixed income
Mutual funds			46
Rabbi trust investments in mutual funds(d)(e)	48		47
Deferred compensation obligation	-47		-45
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-47		-45
Supplemental executive retirement plan fair value	1		1
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	36		35
Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	6,981		6,813
Proprietary trading	501		512
Effect of netting and allocation of collateral	5,488		5,296
Commodity derivative assets subtotal	1,994		2,029
Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-6,762		-6,694
Proprietary trading	-514		-532
Effect of netting and allocation of collateral	-6,834		-6,702
Commodity derivative assets subtotal	-442		-524
Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	-44		-48
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-36		-23
Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	-52		-54
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-166		-113
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	1,107		1,119
Fixed income
Other investments	2		2
Total assets	5,485		5,305
Deferred compensation obligation	0		0
Total liabilities	43		-9
Total net assets	5,528		5,296
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Collateral received from counterparties, net of collateral paid to counterparties	425		434
Fair Value, Inputs, Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	224		208
Equity
Domestic	2,459		2,423
Foreign	639		612
Equity funds subtotal	3,098		3,035
Fixed income
U.S. Treasury and agencies	1,201		996
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Other	0		0
Corporate debt securities	0		0
Commingled funds			0
Fixed income subtotal	1,201		996
Middle market lending	0		0
Private Equity	0		0
Other	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	0
Nuclear decommissioning trust fund investments subtotal	4,523		4,239
Fair Value, Inputs, Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Equity
Domestic	6		6
Fixed income
U.S. Treasury and agencies	2		5
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Corporate debt securities	0		0
Commingled funds			0
Fixed income subtotal	2		5
Middle market lending	0		0
Pledged assets for Zion Station decommissioning subtotal	8		11
Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			1
Fixed income
Mutual funds			46
Rabbi trust investments in mutual funds(d)(e)	48		47
Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	1,510		1,667
Proprietary trading	176		201
Effect of netting and allocation of collateral	1,899		1,982
Commodity derivative assets subtotal	-213		-114
Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-2,126		-2,241
Proprietary trading	-169		-195
Effect of netting and allocation of collateral	-2,324		-2,416
Commodity derivative assets subtotal	29		-20
Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	-8		-17
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-10		-1
Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	-15		-25
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	14		11
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Other investments	0		0
Total assets	6,639		6,747
Deferred compensation obligation	-103		-107
Total liabilities	-363		-427
Total net assets	6,276		6,320
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-103		-107
Collateral received from counterparties, net of collateral paid to counterparties	736		800
Fair Value, Inputs, Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	40		37
Equity
Domestic	2,227		2,207
Foreign	0		0
Equity funds subtotal	2,227		2,207
Fixed income
U.S. Treasury and agencies	0		0
State and municipal debt	423		438
Financial Instruments, Owned, at Fair Value	488
Other	89		95
Corporate debt securities	1,911		2,023
Commingled funds			511
Fixed income subtotal	2,911		3,067
Middle market lending	0		0
Private Equity	0		0
Other	323		301
Fair Value Assets Measured On Recurring Basis Real Estate	0
Nuclear decommissioning trust fund investments subtotal	5,501		5,612
Fair Value, Inputs, Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	19		15
Equity
Domestic	1		1
Fixed income
U.S. Treasury and agencies	3		3
State and municipal debt	10		10
Financial Instruments, Owned, at Fair Value	4
Corporate debt securities	84		89
Commingled funds			3
Fixed income subtotal	101		105
Middle market lending	0		0
Pledged assets for Zion Station decommissioning subtotal	121		121
Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			0
Fixed income
Mutual funds			0
Rabbi trust investments in mutual funds(d)(e)	0		0
Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	3,554		3,465
Proprietary trading	286		284
Effect of netting and allocation of collateral	2,849		2,757
Commodity derivative assets subtotal	991		992
Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-3,370		-3,458
Proprietary trading	-295		-295
Effect of netting and allocation of collateral	-3,585		-3,557
Commodity derivative assets subtotal	-80		-196
Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	-36		-31
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-26		-22
Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	-37		-29
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-180		-124
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Other investments	3		3
Total assets	2,112		2,029
Deferred compensation obligation	0		0
Total liabilities	-391		-308
Total net assets	1,721		1,721
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Collateral received from counterparties, net of collateral paid to counterparties	185		172
Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Equity
Domestic	0		0
Foreign	0		0
Equity funds subtotal	0		0
Fixed income
U.S. Treasury and agencies	0		0
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Other	0		0
Corporate debt securities	248		239
Commingled funds			0
Fixed income subtotal	248		239
Middle market lending	363		366
Private Equity	95		83
Other	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	9		3
Nuclear decommissioning trust fund investments subtotal	715		691
Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Equity
Domestic	0		0
Fixed income
U.S. Treasury and agencies	0		0
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Corporate debt securities	0		0
Commingled funds			0
Fixed income subtotal	0		0
Middle market lending	178		184
Pledged assets for Zion Station decommissioning subtotal	178		184
Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			0
Fixed income
Mutual funds			0
Rabbi trust investments in mutual funds(d)(e)	0		0
Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	1,917		1,681
Proprietary trading	39		27
Effect of netting and allocation of collateral	740		557
Commodity derivative assets subtotal	1,216		1,151
Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-1,266		-995
Proprietary trading	-50		-42
Effect of netting and allocation of collateral	-925		-729
Commodity derivative assets subtotal	-391		-308
Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	0		0
Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	0		0
Designated as Hedging Instrument [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	32		31
Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	32		31
Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral			-41
Derivative Liability, Fair Value, Amount Offset Against Collateral	-17
Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-17		-41
Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Derivative [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	29		13
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Mark-to-market derivative liabilities	332		289
Derivative Liability, Current	110		235
Derivative [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Derivative [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	29		13
Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral			-103
Derivative Liability, Fair Value, Amount Offset Against Collateral	-186
Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-186		-103
Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Interest Rate Swap [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	19		27
Interest Rate Swap [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	18		18
Interest Rate Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	1		9
Interest Rate Swap [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral			-23
Derivative Liability, Fair Value, Amount Offset Against Collateral	-15
Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-1		-14
Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-14		-9
Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	220		405
Fixed income
Derivative Liability, Fair Value, Amount Offset Against Collateral	1,138		1,140
Other investments	3		3
Total assets	13,312		13,329
Deferred compensation obligation	-30		-31
Total liabilities	-248		-350
Total net assets	13,064		12,979
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-30		-31
Mark-to-market derivative liabilities	121		105
Derivative Liability, Current	97		214
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	264		245
Equity
Domestic	4,686		4,630
Foreign	639		612
Equity funds subtotal	5,325		5,242
Fixed income
U.S. Treasury and agencies	1,201		996
State and municipal debt	423		438
Financial Instruments, Owned, at Fair Value	488
Other	89		95
Corporate debt securities	2,159		2,262
Commingled funds			511
Fixed income subtotal	4,360		4,302
Middle market lending	363		366
Private Equity	95		83
Other	323		301
Fair Value Assets Measured On Recurring Basis Real Estate	9		3
Nuclear decommissioning trust fund investments subtotal	10,739		10,542
Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	19		15
Equity
Domestic	7		7
Fixed income
U.S. Treasury and agencies	5		8
State and municipal debt	10		10
Financial Instruments, Owned, at Fair Value	4
Corporate debt securities	84		89
Commingled funds			3
Fixed income subtotal	103		110
Middle market lending	178		184
Pledged assets for Zion Station decommissioning subtotal	307		316
Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			0
Fixed income
Mutual funds			16
Rabbi trust investments in mutual funds(d)(e)	16		16
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	12		11
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	6,981		6,813
Proprietary trading	501		512
Effect of netting and allocation of collateral	5,488		5,296
Commodity derivative assets subtotal	1,994		2,029
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-6,521		-6,487
Proprietary trading	-514		-532
Effect of netting and allocation of collateral	-6,834		-6,702
Commodity derivative assets subtotal	-201		-317
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	-13		-29
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-33		-18
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	-21		-35
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-17		-2
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	220		405
Fixed income
Other investments	0		0
Total assets	4,564		4,558
Deferred compensation obligation	0		0
Total liabilities	43		-9
Total net assets	4,607		4,549
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	224		208
Equity
Domestic	2,459		2,423
Foreign	639		612
Equity funds subtotal	3,098		3,035
Fixed income
U.S. Treasury and agencies	1,201		996
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Other	0		0
Corporate debt securities	0		0
Commingled funds			0
Fixed income subtotal	1,201		996
Middle market lending	0		0
Private Equity	0		0
Other	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	0
Nuclear decommissioning trust fund investments subtotal	4,523		4,239
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Equity
Domestic	6		6
Fixed income
U.S. Treasury and agencies	2		5
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Corporate debt securities	0		0
Commingled funds			0
Fixed income subtotal	2		5
Middle market lending	0		0
Pledged assets for Zion Station decommissioning subtotal	8		11
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			0
Fixed income
Mutual funds			16
Rabbi trust investments in mutual funds(d)(e)	16		16
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	1,510		1,667
Proprietary trading	176		201
Effect of netting and allocation of collateral	1,899		1,982
Commodity derivative assets subtotal	-213		-114
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-2,126		-2,241
Proprietary trading	-169		-195
Effect of netting and allocation of collateral	-2,324		-2,416
Commodity derivative assets subtotal	29		-20
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	-8		-17
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-10		-1
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	-15		-25
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	14		11
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Other investments	0		0
Total assets	6,636		6,742
Deferred compensation obligation	-30		-31
Total liabilities	-141		-240
Total net assets	6,495		6,502
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-30		-31
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	40		37
Equity
Domestic	2,227		2,207
Foreign	0		0
Equity funds subtotal	2,227		2,207
Fixed income
U.S. Treasury and agencies	0		0
State and municipal debt	423		438
Financial Instruments, Owned, at Fair Value	488
Other	89		95
Corporate debt securities	1,911		2,023
Commingled funds			511
Fixed income subtotal	2,911		3,067
Middle market lending	0		0
Private Equity	0		0
Other	323		301
Fair Value Assets Measured On Recurring Basis Real Estate	0		0
Nuclear decommissioning trust fund investments subtotal	5,501		5,612
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	19		15
Equity
Domestic	1		1
Fixed income
U.S. Treasury and agencies	3		3
State and municipal debt	10		10
Financial Instruments, Owned, at Fair Value	4
Corporate debt securities	84		89
Commingled funds			3
Fixed income subtotal	101		105
Middle market lending	0		0
Pledged assets for Zion Station decommissioning subtotal	121		121
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			0
Fixed income
Mutual funds			0
Rabbi trust investments in mutual funds(d)(e)	0		0
Commodity derivative assets subtotal			992
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	3,554		3,465
Proprietary trading	286		284
Effect of netting and allocation of collateral	2,849		2,757
Commodity derivative assets subtotal	991
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-3,370		-3,458
Proprietary trading	-295		-295
Effect of netting and allocation of collateral	-3,585		-3,557
Commodity derivative assets subtotal	-80		-196
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	-5		-12
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-23		-17
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	-6		-10
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	-31		-13
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Other investments	3		3
Total assets	2,112		2,029
Deferred compensation obligation	0		0
Total liabilities	-150		-101
Total net assets	1,962		1,928
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Equity
Domestic	0		0
Foreign	0		0
Equity funds subtotal	0		0
Fixed income
U.S. Treasury and agencies	0		0
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Other	0		0
Corporate debt securities	248		239
Commingled funds			0
Fixed income subtotal	248		239
Middle market lending	363		366
Private Equity	95		83
Other	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	9		3
Nuclear decommissioning trust fund investments subtotal	715		691
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Equity
Domestic	0		0
Fixed income
U.S. Treasury and agencies	0		0
State and municipal debt	0		0
Financial Instruments, Owned, at Fair Value	0
Corporate debt securities	0		0
Commingled funds			0
Fixed income subtotal	0		0
Middle market lending	178		184
Pledged assets for Zion Station decommissioning subtotal	178		184
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents			0
Fixed income
Mutual funds			0
Rabbi trust investments in mutual funds(d)(e)	0		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fixed income
Economic hedges	1,917		1,681
Proprietary trading	39		27
Effect of netting and allocation of collateral	740		557
Commodity derivative assets subtotal	1,216		1,151
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fixed income
Economic hedges	-1,025		-788
Proprietary trading	-50		-42
Effect of netting and allocation of collateral	-925		-729
Commodity derivative assets subtotal	-150		-101
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fixed income
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	0		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fixed income
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets
Interest rate and foreign currency derivative assets subtotal	0		0
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		8
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		8
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	17		-12
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-17		-12
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Derivative [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	27		12
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Mark-to-market derivative liabilities	111	[1]	102	[2]
Derivative Liability, Current	90	[1]	215	[2]
Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	27		12
Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral			-2
Derivative Liability, Fair Value, Amount Offset Against Collateral	-6
Exelon Generation Co L L C [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-6		-2
Exelon Generation Co L L C [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	19		27
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Derivative Liability, Current	3
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	18		18
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	1		9
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		0
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral			-23
Derivative Liability, Fair Value, Amount Offset Against Collateral	-15
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 1 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-1		-14
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 2 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-14		-9
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member] | Fair Value, Inputs, Level 3 [Member]
Fixed income
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		0
PECO Energy Co [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	5		12
Fixed income
Mutual funds			9
Commodity derivative assets subtotal	0		0
Total assets	14		21
Deferred compensation obligation	-14		-15
Total liabilities	-14		-15
Total net assets	0		6
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-14		-15
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	14		14
PECO Energy Co [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	5		12
Fixed income
Mutual funds			9
Commodity derivative assets subtotal	0		0
Total assets	14		21
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	14		21
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
PECO Energy Co [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	-14		-15
Total liabilities	-14		-15
Total net assets	-14		-15
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-14		-15
PECO Energy Co [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
PECO Energy Co [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		0
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
PECO Energy Co [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
Commonwealth Edison Co [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	67		25
Fixed income
Commodity derivative assets subtotal	241		207
Total assets	67		25
Deferred compensation obligation	-8		-8
Total liabilities	-249		-215
Total net assets	-182		-190
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-8		-8
Mark-to-market derivative liabilities	221		187
Derivative Liability, Current	20		20
Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	67		25
Fixed income
Commodity derivative assets subtotal	0		0
Total assets	67		25
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	67		25
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	-8		-8
Total liabilities	-8		-8
Total net assets	-8		-8
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-8		-8
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Commodity derivative assets subtotal	241		207
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	-241		-207
Total net assets	-241		-207
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
Baltimore Gas and Electric Company [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	75		103
Fixed income
Mutual funds			5
Commodity derivative assets subtotal	0		0
Total assets	80		108
Deferred compensation obligation	-4		-5
Total liabilities	-4		-5
Total net assets	76		103
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-4		-5
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	75		103
Fixed income
Mutual funds	5		5
Commodity derivative assets subtotal	0		0
Total assets	80		108
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	80		108
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	-4		-5
Total liabilities	-4		-5
Total net assets	-4		-5
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	-4		-5
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	0		0
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]
Cash equivalents	0		0
Fixed income
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		0
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]
Deferred compensation	0		0
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fixed income
Mutual funds	$0		$0
[1]	Current and noncurrent assets are shown net of collateral of $387 million and $192 million, respectively, and current and noncurrent liabilities are shown net of collateral of $519 million and $248 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,346 million at March 31, 2015.
[2]	Current and noncurrent assets are shown net of collateral of $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.

Fair_Value_of_Financial_Assets4

Fair Value of Financial Assets and Liabilities - Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2014
Derivative [Member] | Consolidation, Eliminations [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	$0
Total realized / unrealized gains (losses)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	-8
Included in payable for Zion Station decommissioning	0
Included in noncurrent payables to affiliates	8
Change in collateral	0
Purchases, sales, issuances and settlements
Purchases	0
Sales	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0
Transfers into Level 3	0
Transfers out of Level 3	0
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	0
Exelon Generation Co L L C [Member]
Purchases, sales, issuances and settlements
Settlements	2		5
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts	-134	212
Decrease in Fair Value Adjustment	36
Increase In Fair Value Adjustment			30
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning balance	1,721		749
Total realized / unrealized gains (losses)
Included in net income	-30		-311
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0		0
Included in payable for Zion Station decommissioning	-3		1
Included in noncurrent payables to affiliates	-26		28
Change in collateral	-12		-144
Purchases, sales, issuances and settlements
Purchases	93		181
Sales	-22		-7
Settlements	-29		-6
Transfers into Level 3	-4		26
Transfers out of Level 3	-5		1
Ending balance	1,721		752
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	181		-446
Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Consolidation, Eliminations [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	0		0	0
Total realized / unrealized gains (losses)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates			-3
Included in payable for Zion Station decommissioning			0
Included in noncurrent payables to affiliates			3
Change in collateral			0
Purchases, sales, issuances and settlements
Purchases			0
Sales			0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements			0
Transfers into Level 3			0
Transfers out of Level 3			0
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held			0
Fair Value, Inputs, Level 3 [Member] | Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning balance	1,928		942
Total realized / unrealized gains (losses)
Included in net income	-30		-311
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	8		3
Included in payable for Zion Station decommissioning	-3		1
Included in noncurrent payables to affiliates	0		0
Change in collateral	-12		-144
Purchases, sales, issuances and settlements
Purchases	93		181
Sales	-22		-7
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	-29
Settlements			-6
Transfers into Level 3	-4		26
Transfers out of Level 3	-5		1
Ending balance	1,962		920
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	181		-446
Fair Value, Inputs, Level 3 [Member] | Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	2		1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	715		486	350	691
Total realized / unrealized gains (losses)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	8		3
Included in payable for Zion Station decommissioning	0		0
Included in noncurrent payables to affiliates	0		0
Change in collateral	0		0
Purchases, sales, issuances and settlements
Purchases	47		139
Sales	-8		-1
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	-29		-6
Transfers into Level 3	-4		0
Transfers out of Level 3	0		0
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	1		0
Fair Value, Inputs, Level 3 [Member] | Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	178		137	112	184
Total realized / unrealized gains (losses)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0		0
Included in payable for Zion Station decommissioning	-3		1
Included in noncurrent payables to affiliates	0		0
Change in collateral	0		0
Purchases, sales, issuances and settlements
Purchases	5		30
Sales	-14		-4
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0		0
Transfers into Level 3			0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0
Transfers out of Level 3	0		0
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	0		0
Fair Value, Inputs, Level 3 [Member] | Exelon Generation Co L L C [Member] | Derivative [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	1,066		287	465	1,050
Total realized / unrealized gains (losses)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings, Description	-32		-312
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0		0
Included in payable for Zion Station decommissioning	0		0
Included in noncurrent payables to affiliates	0
Change in collateral	-12		-144
Purchases, sales, issuances and settlements
Purchases	41		10
Sales	0		-2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0		0
Transfers into Level 3			26
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	0
Transfers out of Level 3	-5		8
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	180		-446
Fair Value, Inputs, Level 3 [Member] | Exelon Generation Co L L C [Member] | Other Investments [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Value	3		10	15	3
Total realized / unrealized gains (losses)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Liability, Gain (Loss) Included in Earnings, Description	0		0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0		0
Included in payable for Zion Station decommissioning	0		0
Included in noncurrent payables to affiliates	0		0
Change in collateral	0		0
Purchases, sales, issuances and settlements
Purchases	0		2
Sales	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0		0
Transfers into Level 3	0		0
Transfers out of Level 3	0		-7
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held			0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Asset Liability Gain Loss Included In Earnings Attributed To Changes In Unrealized Gains Losses	0
Fair Value, Inputs, Level 3 [Member] | Commonwealth Edison Co [Member] | Derivative [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliations, Recurring Basis, Liability Value	-241		-168	-193	-207
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Earnings	0		0
Total realized / unrealized gains (losses)
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0		0
Included in payable for Zion Station decommissioning	0		0
Included in noncurrent payables to affiliates	-34		25
Change in collateral	0		0
Purchases, sales, issuances and settlements
Purchases	0		0
Sales	0		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Settlements	0		0
Transfers into Level 3	0		0
Transfers out of Level 3	0		0
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	$0		$0

Fair_Value_of_Financial_Assets5

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities - Narrative (Details) (USD $)	Mar. 31, 2015
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward Power Basis	$3.15
Forward Gas Basis	0.31
Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$265,000,000

Fair_Value_of_Financial_Assets6

Fair Value of Financial Assets and Liabilities - Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Operating Revenue [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	($10)	($268)
Change in the unrealized gains (losses) relating to assets and liabilities held	169	-425
Purchased Fuel and Electric [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	-22	-44
Change in the unrealized gains (losses) relating to assets and liabilities held	11	-21
Other, net [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	2	1
Change in the unrealized gains (losses) relating to assets and liabilities held	1	0
Exelon Generation Co L L C [Member] | Operating Revenue [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	-10	-268
Change in the unrealized gains (losses) relating to assets and liabilities held	169	-425
Exelon Generation Co L L C [Member] | Purchased Fuel and Electric [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	-22	-44
Change in the unrealized gains (losses) relating to assets and liabilities held	11	-21
Exelon Generation Co L L C [Member] | Other, net [Member]
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]
Total gains (losses) included in income	2	1
Change in the unrealized gains (losses) relating to assets and liabilities held	$1	$0

Fair_Value_of_Financial_Assets7

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Derivatives Fair Value Footnotes [Abstract]
Cash collateral excluded	185,000,000
Fair Value, Inputs, Level 3 [Member]
Derivatives Fair Value Footnotes [Abstract]
Cash collateral excluded		172,000,000
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	892,000,000	893,000,000
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	17	15
Forward gas price assets	1.68	1.52
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	121	120
Forward gas price assets	13.69	14.02
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	8.00%	8.00%
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Option Model Valuation Technique [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Volatility percentage	172.00%	257.00%
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	11,000,000	15,000,000
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	17	15
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	95	117
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	241,000,000	207,000,000
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Minimum [Member]
Fair Value Inputs [Abstract]
Marketability Reserve	3.50%	3.50%
Forward heat rate	-8.00%	-8.00%
Renewable factor	86.00%	86.00%
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Marketability Reserve	8.00%	8.00%
Forward heat rate	-9.00%	-9.00%
Renewable factor	126.00%	126.00%
All Regions excluding New England [Member] | Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	107	97
Forward gas price assets	8.19	8.14
All Regions excluding New England [Member] | Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Proprietary Trading [Member] | Discounted Cash Flow [Member] | Maximum [Member]
Fair Value Inputs [Abstract]
Forward power price assets	55	76

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	$1,117		$1,279
Mark-to-market derivative assets	913		773
Derivative Liability, Current	-117		-234
Derivative Liability, Noncurrent	-491		-403
InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	15		15
Mark-to-market derivative assets	21		8
Derivative Liability, Current	-7		1
Derivative Liability, Noncurrent	-159		-114
Total mark-to-market derivative net assets (liabilities)	-130	[1]	-90	[1]
Total mark-to-market derivative assets	36	[1]	23	[1]
Derivative Liability	-166	[1]	-113	[1]
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,116		1,276
Mark-to-market derivative assets	911		771
Derivative Liability, Current	-97		-214
Derivative Liability, Noncurrent	-121		-105
Exelon Generation Co L L C [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	14		12
Mark-to-market derivative assets	19		6
Derivative Liability, Current	-7		1
Derivative Liability, Noncurrent	-10		-3
Total mark-to-market derivative net assets (liabilities)	16	[1]	16	[1]
Total mark-to-market derivative assets	33	[1]	18	[1]
Derivative Liability	-17	[1]	-2	[1]
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative Liability, Current	-3
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0		7
Mark-to-market derivative assets	0		1
Derivative Liability, Current	-8		-8
Derivative Liability, Noncurrent	-9		-4
Total mark-to-market derivative net assets (liabilities)	-17		-4
Total mark-to-market derivative assets	0		8
Derivative Liability	-17		-12
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	11		20
Mark-to-market derivative assets	8		7
Derivative Liability, Current	-8		-14
Derivative Liability, Noncurrent	-7		-9
Total mark-to-market derivative net assets (liabilities)	4		4
Total mark-to-market derivative assets	19	[2]	27	[2]
Derivative Liability	-15	[2]	-23	[2]
Exelon Generation Co L L C [Member] | Collateral And Netting [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	-10		-22
Mark-to-market derivative assets	-3		-7
Derivative Liability, Current	15		25
Derivative Liability, Noncurrent	6		10
Total mark-to-market derivative net assets (liabilities)	8	[1]	6	[1]
Total mark-to-market derivative assets	-13	[1]	-29	[1]
Derivative Liability	21	[1]	35	[1]
Exelon Generation Co L L C [Member] | Economic Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	13		7
Mark-to-market derivative assets	14		5
Derivative Liability, Current	-6		-2
Derivative Liability, Noncurrent	0		0
Total mark-to-market derivative net assets (liabilities)	21		10
Total mark-to-market derivative assets	27		12
Derivative Liability	-6		-2
Corporate, Non-Segment [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1		3
Mark-to-market derivative assets	2		2
Derivative Liability, Current	0		0
Derivative Liability, Noncurrent	-149		-111
Total mark-to-market derivative net assets (liabilities)	-146	[1]	-106	[1]
Total mark-to-market derivative assets	3	[1]	5	[1]
Derivative Liability	-149	[1]	-111	[1]
Corporate, Non-Segment [Member] | Designated as Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1		3
Mark-to-market derivative assets	31		20
Derivative Liability, Current	0		0
Derivative Liability, Noncurrent	0		-29
Total mark-to-market derivative net assets (liabilities)	32		-6
Total mark-to-market derivative assets	32		23
Derivative Liability	0		-29
Corporate, Non-Segment [Member] | Collateral And Netting [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets	-31		-19
Derivative Liability, Current	0		0
Derivative Liability, Noncurrent	31		19
Total mark-to-market derivative net assets (liabilities)	0	[1]	0	[1]
Total mark-to-market derivative assets	-31	[1]	-19	[1]
Derivative Liability	31	[1]	19	[1]
Corporate, Non-Segment [Member] | Economic Hedging Instrument [Member] | InterestRateAndForeignExchangeContract [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets	2		1
Derivative Liability, Current	0		0
Derivative Liability, Noncurrent	-180		-101
Total mark-to-market derivative net assets (liabilities)	-178		-100
Total mark-to-market derivative assets	2		1
Derivative Liability	($180)		($101)
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MzFGMzlBOEZENkM2MzU4RDBBNzEwOTNBRjYwNTQzOEQM}
[2]	Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts within the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) (Interest Expense [Member], Fair Value Hedging [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$9	[1]	$2	[1]
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	-1	[1]	-5	[1]
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Gain (Loss) on Fair Value Hedges Recognized in Earnings	1		-4
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	11	[1]	4	[1]
Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$0	[1]	($1)	[1]
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MkU0QjI1QzVBMjc1OUZCMzhBRjkwOTNBRjYwNTgzNTEM}

Derivative_Financial_Instrumen4

Derivative Financial Instruments Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	$1,117		$1,279
Mark-to-market derivative assets (noncurrent assets)	913		773
Mark-to-market derivative liabilities (current liabilities)	-117		-234
Mark-to-market derivative liabilities (noncurrent liabilities)	-491		-403
Derivative [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,102		1,264
Mark-to-market derivative assets (noncurrent assets)	892		765
Total mark-to-market derivative assets	1,994		2,029
Mark-to-market derivative liabilities (current liabilities)	-110		-235
Mark-to-market derivative liabilities (noncurrent liabilities)	-332		-289
Total mark-to-market derivative liabilities	-442		-524
Total mark-to-market derivative net assets (liabilities)	1,552		1,505
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,116		1,276
Mark-to-market derivative assets (noncurrent assets)	911		771
Mark-to-market derivative liabilities (current liabilities)	-97		-214
Mark-to-market derivative liabilities (noncurrent liabilities)	-121		-105
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	4,618		4,992
Mark-to-market derivative assets (noncurrent assets)	2,363		1,821
Total mark-to-market derivative assets	6,981		6,813
Mark-to-market derivative liabilities (current liabilities)	-4,505		-4,947
Mark-to-market derivative liabilities (noncurrent liabilities)	-2,016		-1,540
Total mark-to-market derivative liabilities	-6,521		-6,487
Total mark-to-market derivative net assets (liabilities)	460		326
Current assets collateral offset	387		416
Noncurrent assets collateral offset	192		171
Current liabilities collateral offset	519		599
Noncurrent liabilities collateral offset	248		220
Total cash collateral received net of cash collateral posted	1,346		-1,406
Exelon Generation Co L L C [Member] | Derivative [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,102	[1]	1,264	[2]
Mark-to-market derivative assets (noncurrent assets)	892	[1]	765	[2]
Total mark-to-market derivative assets	1,994	[1]	2,029	[2]
Mark-to-market derivative liabilities (current liabilities)	-90	[1]	-215	[2]
Mark-to-market derivative liabilities (noncurrent liabilities)	-111	[1]	-102	[2]
Total mark-to-market derivative liabilities	-201	[1]	-317	[2]
Total mark-to-market derivative net assets (liabilities)	1,793	[1]	1,712	[2]
Exelon Generation Co L L C [Member] | Proprietary Trading [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	431		456
Mark-to-market derivative assets (noncurrent assets)	70		56
Total mark-to-market derivative assets	501		512
Mark-to-market derivative liabilities (current liabilities)	-437		-468
Mark-to-market derivative liabilities (noncurrent liabilities)	-77		-64
Total mark-to-market derivative liabilities	-514		-532
Total mark-to-market derivative net assets (liabilities)	-13		-20
Exelon Generation Co L L C [Member] | Collateral And Netting [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	-3,947		-4,184
Mark-to-market derivative assets (noncurrent assets)	-1,541		-1,112
Total mark-to-market derivative assets	-5,488	[3]	-5,296	[3]
Mark-to-market derivative liabilities (current liabilities)	4,852		5,200
Mark-to-market derivative liabilities (noncurrent liabilities)	1,982		1,502
Total mark-to-market derivative liabilities	6,834	[3]	6,702	[3]
Total mark-to-market derivative net assets (liabilities)	1,346	[3]	1,406	[3]
Commonwealth Edison Co [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities (current liabilities)	-20		-20
Mark-to-market derivative liabilities (noncurrent liabilities)	-221		-187
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets (noncurrent assets)	0		0
Total mark-to-market derivative assets	0	[4]	0	[4]
Mark-to-market derivative liabilities (current liabilities)	-20		-20
Mark-to-market derivative liabilities (noncurrent liabilities)	-221		-187
Total mark-to-market derivative liabilities	-241	[4]	-207	[4]
Total mark-to-market derivative net assets (liabilities)	($241)	[4]	($207)	[4]
[1]	Current and noncurrent assets are shown net of collateral of $387 million and $192 million, respectively, and current and noncurrent liabilities are shown net of collateral of $519 million and $248 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,346 million at March 31, 2015.
[2]	Current and noncurrent assets are shown net of collateral of $416 million and $171 million, respectively, and current and noncurrent liabilities are shown net of collateral of $599 million and $220 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $1,406 million at December 31, 2014.
[3]	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
[4]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative_Financial_Instrumen5

Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) (USD $)	3 Months Ended				12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014	Dec. 31, 2013
Derivative [Line Items]
Income taxes	($363)		$54
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Income taxes	-226		199
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Derivative [Line Items]
Income taxes	10	[1]	-15	[1]
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]
Derivative [Line Items]
Income taxes	0	[1]	-15	[1]
Energy Related Hedges [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	-6		-4
Energy Related Hedges [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)	-23		88		-18	116
Energy Related 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] | Operating Revenue One [Member]
Derivative [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	-2		-24
Energy Related 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] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	3
Energy Related 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] | Other, net [Member]
Derivative [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	0
Cash Flow Hedging [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	-11		-1
Cash Flow Hedging [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)	-22		95		-28	120
Cash Flow Hedging [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Operating Revenue One [Member]
Derivative [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	-2		-24
Cash Flow Hedging [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	3
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]
Derivative [Line Items]
Derivative Instruments, Gain Reclassified from Accumulated OCI into Income, Effective Portion	$16
[1]	All amounts are net of tax. Amounts in parentheses represent a decrease in net income.

Derivative_Financial_Instrumen6

Derivative Financial Instruments - Summary of Economic Hedges (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$84		($731)
Gain (Loss) on Sale of Derivatives	-23	[1]
Unrealized Gain (Loss) on Derivatives	91		-730
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	162		-731
Gain (Loss) on Sale of Derivatives	3	[1]
Unrealized Gain (Loss) on Derivatives	165		-737
Unrealized Gain (Loss) on Commodity Contracts	154		-760
Purchased Power And Fuel [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	8		30
Interest Expense [Member] | Corporate, Non-Segment [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-78		0
Interest Expense [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0		-1
Operating Revenue [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	154		-760
Not Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-67		-2
Not Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	11		-2
Not Designated as Hedging Instrument [Member] | Purchased Power And Fuel [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0		0
Not Designated as Hedging Instrument [Member] | Interest Expense [Member] | Corporate, Non-Segment [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-78		0
Not Designated as Hedging Instrument [Member] | Interest Expense [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0		-1
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	151		-729
Gain (Loss) on Sale of Derivatives	66		-48
Unrealized Gain (Loss) on Commodity Contracts	85		-681
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	151		-729
Gain (Loss) on Sale of Derivatives	66		-48
Unrealized Gain (Loss) on Commodity Contracts	85		-681
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Purchased Power And Fuel [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	8		30
Gain (Loss) on Sale of Derivatives	87		-141
Unrealized Gain (Loss) on Commodity Contracts	-79		171
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0		0
Gain (Loss) on Sale of Derivatives	0		0
Unrealized Gain (Loss) on Commodity Contracts	0		0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Interest Expense [Member] | Corporate, Non-Segment [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0		0
Gain (Loss) on Sale of Derivatives	0		0
Unrealized Gain (Loss) on Commodity Contracts	0		0
Not Designated as Hedging Instrument [Member] | Commodity Contract [Member] | Operating Revenue [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	143		-759
Gain (Loss) on Sale of Derivatives	-21		93
Unrealized Gain (Loss) on Commodity Contracts	164		-852
Not Designated as Hedging Instrument [Member] | InterestRateandForeignExchange [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	-2		0
Unrealized Gain (Loss) on Derivatives	-65		-2
Not Designated as Hedging Instrument [Member] | InterestRateandForeignExchange [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	-2		0
Unrealized Gain (Loss) on Derivatives	13		-2
Not Designated as Hedging Instrument [Member] | InterestRateandForeignExchange [Member] | Purchased Power And Fuel [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	0		0
Unrealized Gain (Loss) on Derivatives	0		0
Not Designated as Hedging Instrument [Member] | InterestRateandForeignExchange [Member] | Interest Expense [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	0		0
Unrealized Gain (Loss) on Derivatives	0		-1
Not Designated as Hedging Instrument [Member] | InterestRateandForeignExchange [Member] | Interest Expense [Member] | Corporate, Non-Segment [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	0		0
Unrealized Gain (Loss) on Derivatives	-78		0
Not Designated as Hedging Instrument [Member] | InterestRateandForeignExchange [Member] | Operating Revenue [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	11		-1
Gain (Loss) on Sale of Derivatives	-2		0
Unrealized Gain (Loss) on Derivatives	$13		($1)
[1]	In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.

Derivative_Financial_Instrumen7

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	($23)	[1]
Unrealized Gain (Loss) on Derivatives	91		-730
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	84		-731
Operating Revenue [Member] | Principal or Proprietary Transactions [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3		-2
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	3	[1]
Unrealized Gain (Loss) on Derivatives	165		-737
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	162		-731
Unrealized Gain (Loss) on Commodity Contracts	154		-760
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	8		30
Exelon Generation Co L L C [Member] | Operating Revenue [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	154		-760
Exelon Generation Co L L C [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	0		-1
Corporate, Non-Segment [Member] | Interest Expense [Member]
Derivative [Line Items]
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	-78		0
Commodity Contract [Member] | Operating Revenue [Member] | Principal or Proprietary Transactions [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	2		1
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	3		-2
Unrealized Gain (Loss) on Commodity Contracts	1		-3
InterestRateAndForeignExchangeContract [Member] | Operating Revenue [Member] | Principal or Proprietary Transactions [Member]
Derivative [Line Items]
Gain (Loss) on Sale of Derivatives	-4		0
Unrealized Gain (Loss) on Derivatives	4		0
Derivative Instruments Not Designated as Hedging Instruments, Gain (Loss), Net	$0		$0
[1]	In January 2015, in connection with Generation's $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.

Derivative_Financial_Instrumen8

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) (Exelon Generation Co L L C [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Derivative [Line Items]
Credit Derivative, Maximum Exposure, Undiscounted	$2,196
Credit derivative net exposure	2,121
Credit Derivative, Collateral Held Directly or by Third Parties	75
Number of Credit Risk Derivatives Held	1
Derivative Credit Risk Valuation Adjustment, Derivative Assets	442
Financial institution [Member]
Derivative [Line Items]
Credit derivative net exposure	324
Energy Cooperatives And Municipalities [Member]
Derivative [Line Items]
Credit derivative net exposure	869
Investor Owned Utilities Marketers And Power Producers Credit Risk Exposure [Member]
Derivative [Line Items]
Credit derivative net exposure	897
Other Credit Risk Exposure [Member]
Derivative [Line Items]
Credit derivative net exposure	31
External Credit Rating, Investment Grade [Member]
Derivative [Line Items]
Credit Derivative, Maximum Exposure, Undiscounted	1,570
Credit derivative net exposure	1,514
Credit Derivative, Collateral Held Directly or by Third Parties	56
Number of Credit Risk Derivatives Held	1
Derivative Credit Risk Valuation Adjustment, Derivative Assets	442
External Credit Rating, Non Investment Grade [Member]
Derivative [Line Items]
Credit Derivative, Maximum Exposure, Undiscounted	63
Credit derivative net exposure	47
Credit Derivative, Collateral Held Directly or by Third Parties	16
Number of Credit Risk Derivatives Held	0
Derivative Credit Risk Valuation Adjustment, Derivative Assets	0
Risk Level, High [Member]
Derivative [Line Items]
Credit Derivative, Maximum Exposure, Undiscounted	68
Credit derivative net exposure	65
Credit Derivative, Collateral Held Directly or by Third Parties	3
Number of Credit Risk Derivatives Held	0
Derivative Credit Risk Valuation Adjustment, Derivative Assets	0
Risk Level, Low [Member]
Derivative [Line Items]
Credit Derivative, Maximum Exposure, Undiscounted	495
Credit derivative net exposure	495
Credit Derivative, Collateral Held Directly or by Third Parties	0
Number of Credit Risk Derivatives Held	0
Derivative Credit Risk Valuation Adjustment, Derivative Assets	$0

Derivative_Financial_Instrumen9

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Derivative [Line Items]
Derivative, Collateral, Obligation to Return Cash	$62
Derivative, Collateral, Obligation to Return Securities	14
Energy Supply Procurement [Member]
Derivative [Line Items]
Derivative Asset, Fair Value of Collateral	2
ReNewAble Energy Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value of Collateral	19
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Aggregate fair value of derivatives with credit-risk-related contingent features	-1,420		-1,433
Contractual right of offset related to derivative assets	1,138		1,140
Net liability position after contractual right of offset	-282	[1]	-293	[1]
Derivative, Collateral, Right to Reclaim Cash	1,428		1,497
Derivative, Collateral, Right to Reclaim Securities	626		672
Derivative, Collateral, Obligation to Return Cash	69		77
Derivative, Collateral, Obligation to Return Securities	$22		$24
[1]	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.

Recovered_Sheet1

Derivative Financial Instruments - Narrative (Details) (USD $)	3 Months Ended				12 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Derivative [Line Items]
Income taxes	$363		($54)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	2		39
Hypothetical Increase In Interest Rates	0.50%
Hypothetical increase in interest rates associated with variable-rate debt	1
Ineffective portion recognized in income	4	[1]	5
Mark-to-market derivative liabilities (noncurrent liabilities)	491				403
Derivative Liability, Current	117				234
Cash collateral held	62
Letters of credit collateral posted	14
Interest Rate Fair Value Hedge Asset at Fair Value	-130
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives	3,068
Energy Supply Procurement [Member]
Derivative [Line Items]
Derivative Asset, Fair Value of Collateral	2
ReNewAble Energy Contract [Member]
Derivative [Line Items]
Derivative Asset, Fair Value of Collateral	19
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Income taxes	226		-199
Proprietary trading activities volume	3,006,000		8,129,000
Mark-to-market derivative liabilities (noncurrent liabilities)	121				105
Derivative Liability, Current	97				214
Cash collateral received not offset against net derivative positions	5				8
Credit exposure under natural gas supply and management agreements	2,196
Cash collateral posted	1,428				1,497
Letters of credit collateral posted	626				672
Cash collateral held	69				77
Letters of credit collateral posted	22				24
Incremental collateral for loss of investment grade credit rating	2,300				2,400
Interest Rate Fair Value Hedge Asset at Fair Value	16
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives	768
Commonwealth Edison Co [Member]
Derivative [Line Items]
Income taxes	59		65
Mark-to-market derivative liabilities (noncurrent liabilities)	221				187
Derivative Liability, Current	20				20
PECO Energy Co [Member]
Derivative [Line Items]
Income taxes	58		34
Estimated percentage of natural gas purchases hedged	30.00%
Incremental collateral for loss of investment grade credit rating	36
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Income taxes	74		58
Incremental collateral for loss of investment grade credit rating	111
Minimum [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months	94.00%
Expected Generation Hedged In Year Two	67.00%
Expected generation hedged in year three	37.00%
Minimum [Member] | Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged	10.00%
Maximum [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Expected Generation Hedged In Next Twelve Months	97.00%
Expected Generation Hedged In Year Two	70.00%
Expected generation hedged in year three	40.00%
Maximum [Member] | Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged	20.00%
Interest Rate Swap [Member] | Derivative [Member]
Derivative [Line Items]
Derivative, Notional Amount	900
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Liability, Current	3
Interest Rate Contract [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	271
Foreign Exchange Contract [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	338
Fair Value Hedging [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	900				1,450
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments	32				29
Fair Value Hedging [Member] | Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Interest rate swaps previously held by acquiree					550
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments					7
Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional Amount of Pre-issuance Interest Rate Cash Flow Hedge Derivatives	400
Other Solar Projects [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional amounts on forward starting interest rate swaps	26
Mark-to-market derivative liabilities (noncurrent liabilities)	3
Other Solar Projects [Member] | Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	26
PHI Merger [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities (noncurrent liabilities)	-178
PHI Merger [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	2,300
ExGen Texas Power [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative, Notional Amount	504
ExGen Texas Power [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities (noncurrent liabilities)	13
ExGen Texas Power [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Increase In Notional Amount Of Derivative Instruments	212
Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	26
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Derivative [Line Items]
Income taxes	-10	[2]	15	[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]
Derivative [Line Items]
Income taxes	0	[2]	15	[2]
Commonwealth Edison Co Affiliate [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Net receivable from electric utility	52
PECO Energy Co Affiliate [Member] | PECO Energy Co [Member]
Derivative [Line Items]
Net receivable from affiliated electric and gas utility	36
Baltimore Gas And Electric Company Affiliate [Member] | Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Net receivable from affiliated electric and gas utility	$26
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MkU0QjI1QzVBMjc1OUZCMzhBRjkwOTNBRjYwNTgzNTEM}
[2]	All amounts are net of tax. Amounts in parentheses represent a decrease in net income.

Debt_and_Credit_Agreements_Com

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) (Commercial Paper [Member], USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	$0	$0
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	283	304
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Commercial paper borrowings	$0	$120

Debt_and_Credit_Agreements_Lin

Debt and Credit Agreements - Lines of Credit under Committed Credit Facilities (Details) (USD $)	Mar. 31, 2015		1-May-14	Jun. 11, 2014
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$8,500,000,000	[1]
Bridge Loan	3,200,000,000		7,200,000,000
Line of Credit Facility, Current Borrowing Capacity	22,000,000
Parent [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	500,000,000	[1],[2]
Exelon Generation Co L L C [Member] | Community and Minority Banks [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	50,000,000
Outstanding letters of credit	7,000,000
Exelon Generation Co L L C [Member] | CitiBank [Member]
Debt Instrument [Line Items]
Outstanding letters of credit	300,000,000	[1],[2]
Exelon Generation Co L L C [Member] | CIBC [Member]
Debt Instrument [Line Items]
Outstanding letters of credit				100,000,000	[1],[2]
Exelon Generation Co L L C [Member] | SUMITOMO [Member]
Debt Instrument [Line Items]
Outstanding letters of credit	100,000,000	[1],[2]
Commonwealth Edison Co [Member] | Community and Minority Banks [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	34,000,000
Outstanding letters of credit	16,000,000
Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	1,000,000,000	[1],[2]
PECO Energy Co [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	27,000,000
PECO Energy Co [Member] | Community and Minority Banks [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	34,000,000
Outstanding letters of credit	21,000,000
PECO Energy Co [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	600,000,000	[1],[2]
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity	27,000,000
Baltimore Gas and Electric Company [Member] | Community and Minority Banks [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	5,000,000
Outstanding letters of credit	1,000,000
Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	600,000,000	[1],[2]
Syndicated Revolver 1 [Member] | Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	5,100,000,000	[1],[2]
Syndicated Revolver 2 [Member] | Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$200,000,000	[1],[2]
[1]	Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 16, 2015. These facilities are solely utilized to issue letters of credit. As of March 31, 2015, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $16 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion to support the PHI transaction discussed below.
[2]	edit facility commitments of $22 million, $27 million and $27 million for Exelon Corporate, PECO and BGE, respectively, which expire in August 2018.

Debt_and_Credit_Agreements_Nar

Debt and Credit Agreements - Narrative (Details) (USD $)	0 Months Ended	3 Months Ended				0 Months Ended
	Jun. 01, 2014	Mar. 31, 2015		Sep. 30, 2014	Mar. 31, 2014	Jun. 11, 2014	1-May-14
Debt Instrument [Line Items]
Repayments of Long-term Debt		$580,000,000			$1,150,000,000
Line of Credit Facility, Maximum Borrowing Capacity		8,500,000,000	[1]
Bridge Loan		3,200,000,000					7,200,000,000
Interest Expense, Commercial Paper		11,000,000
equity units issued	23,000,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions				35,000,000
Subordinated Borrowing, Interest Rate				2.50%
Long-term Debt		131,000,000
Parent Company [Member]
Debt Instrument [Line Items]
Basis points adders for prime-based borrowings		0.28%
Basis Points For Libor Based Borrowings		0.01275
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		0			617,000,000
Basis points adders for prime-based borrowings		0.08%
Basis Points For Libor Based Borrowings		0.01075
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt		18,000,000			532,000,000
Basis points adders for prime-based borrowings		0.28%
Basis Points For Libor Based Borrowings		0.01275
Interest Rate		3.71%
PECO Energy Co [Member]
Debt Instrument [Line Items]
Basis points adders for prime-based borrowings		0.00%
Basis Points For Libor Based Borrowings		0.009
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Basis points adders for prime-based borrowings		0.00%
Basis Points For Libor Based Borrowings		0.01
Revolving Credit Facility [Member] | Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		1,000,000,000	[1],[2]
Revolving Credit Facility [Member] | PECO Energy Co [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		600,000,000	[1],[2]
Revolving Credit Facility [Member] | Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		600,000,000	[1],[2]
Parent [Member] | Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		500,000,000	[1],[2]
Convertible Debt Securities [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Subordinated Long-term Debt				1,110,000,000
Maximum [Member]
Debt Instrument [Line Items]
Basis points adders for prime-based borrowings		0.07%
Basis Points For Libor Based Borrowings		0.00165
SeniorSecuredNotes525January152014Member [Member] | Senior Notes [Member] | Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt					500,000,000
Interest Rate					5.35%
SeniorSecuredNotes525January152014Member [Member] | Junior Subordinated Debt [Member] | Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt						1,150,000,000
SeniorNotesJan152020 [Member] | Senior Notes [Member] | Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum		2.29%
Interest Rate		2.95%
Debt Instrument, Face Amount		750,000,000
ExgenRenewablesI425June62021[Member] | Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount					$300,000,000
[1]	Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities expire on October 16, 2015. These facilities are solely utilized to issue letters of credit. As of March 31, 2015, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $7 million, $16 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion to support the PHI transaction discussed below.
[2]	edit facility commitments of $22 million, $27 million and $27 million for Exelon Corporate, PECO and BGE, respectively, which expire in August 2018.

Debt_and_Credit_Agreements_Sch

Debt and Credit Agreements - Schedule of Issuance of Long-Term Debt (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Apr. 29, 2015	Apr. 01, 2015
Debt Instrument [Line Items]
Long-term Debt	$131
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Interest Rate	3.71%
Exelon Generation Co L L C [Member] | ExgenRenewablesI425June62021[Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		300
Exelon Generation Co L L C [Member] | Energy Efficiency Project Financing [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	42
Exelon Generation Co L L C [Member] | AVSR [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	14		18	7
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] | Senior Notes [Member] | SeniorNotesJan152020 [Member]
Debt Instrument [Line Items]
Interest Rate	2.95%
Debt Instrument, Face Amount	750
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Minimum	2.29%
Debt Instrument, Interest Rate, Stated Percentage Rate Range, Maximum	2.56%
Commonwealth Edison Co [Member] | FirstMortgageBondSeries118March12045 [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	400
Commonwealth Edison Co [Member] | First Mortgage Bonds [Member] | FirstMortgageBondSeries115January152019 [Member]
Debt Instrument [Line Items]
Interest Rate		2.15%
Debt Instrument, Face Amount		300
Commonwealth Edison Co [Member] | First Mortgage Bonds [Member] | FirstMortgageBondSeries116January152044 [Member]
Debt Instrument [Line Items]
Interest Rate		4.70%
Debt Instrument, Face Amount		$350

Debt_and_Credit_Agreements_Ret

Debt and Credit Agreements - Retirement and Redemptions of Current and Long-Term Debt (Details) (USD $)	3 Months Ended		0 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Apr. 06, 2015	Apr. 15, 2015
Debt Instrument [Line Items]
Repayments of Long-term Debt	$580	$1,150
Senior Notes [Member] | SeniorSecuredNotes455Jun152015 [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	550
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Interest Rate	3.71%
Repayments of Long-term Debt	18	532
Exelon Generation Co L L C [Member] | AVSR [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	4
Exelon Generation Co L L C [Member] | Clear Horizon solar [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	2
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	10	11
Exelon Generation Co L L C [Member] | ExGen Texas Power [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	2
Exelon Generation Co L L C [Member] | Senior Notes [Member] | SeniorSecuredNotes525January152014Member [Member]
Debt Instrument [Line Items]
Interest Rate		5.35%
Repayments of Long-term Debt		500
Exelon Generation Co L L C [Member] | Senior Notes [Member] | AVSR [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			2
Exelon Generation Co L L C [Member] | Senior Notes [Member] | SeniorSecuredNotes455Jun152015 [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	550
Exelon Generation Co L L C [Member] | Pollution Control Notes [Member]
Debt Instrument [Line Items]
Interest Rate		4.10%
Repayments of Long-term Debt		20
Exelon Generation Co L L C [Member] | Capital Lease Obligations [Member] | Continental Wind 6000 February 28, 2033 [Member]
Debt Instrument [Line Items]
Interest Rate		7.83%
Repayments of Long-term Debt	1	1
Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Rate Stabilization Bonds, April 1, 2017 [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt			37
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt	0	617
Commonwealth Edison Co [Member] | Pollution Control Notes [Member]
Debt Instrument [Line Items]
Interest Rate		5.85%
Repayments of Long-term Debt		17
Commonwealth Edison Co [Member] | First Mortgage Bonds [Member] | Subsequent Event [Member]
Debt Instrument [Line Items]
Repayments of Long-term Debt				260
Commonwealth Edison Co [Member] | First Mortgage Bonds [Member] | FirstMortgageBond163January12014 [Member]
Debt Instrument [Line Items]
Interest Rate		1.63%
Repayments of Long-term Debt		$600

Income_Taxes_Reconciliation_to

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
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	2.60%	-57.60%
Qualified nuclear decommissioning trust fund income	1.90%	44.20%
Domestic production activities deduction	-2.20%	-27.80%
Health care reform legislation	0.00%	1.30%
Amortization of investment tax credit, net deferred taxes	-0.90%	-18.00%
Plant basis differences	-1.30%	-31.40%
Production tax credits and other credits	1.80%	36.50%
Noncontrolling interest	-0.70%
Other	0.40%	-47.70%
Effective income tax rate	33.00%	-138.50%
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	2.70%	9.70%
Qualified nuclear decommissioning trust fund income	3.00%	-4.60%
Domestic production activities deduction	-3.40%	2.90%
Health care reform legislation	0.00%	0.00%
Amortization of investment tax credit, net deferred taxes	-1.40%	1.70%
Plant basis differences	0.00%	0.00%
Production tax credits and other credits	2.80%	-3.80%
Noncontrolling interest	-1.10%
Other	-0.20%	3.30%
Effective income tax rate	31.80%	51.80%
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	5.00%	5.50%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Domestic production activities deduction	0.00%
Health care reform legislation	0.00%	0.10%
Amortization of investment tax credit, net deferred taxes	-0.30%	-0.30%
Plant basis differences	-0.30%	-0.60%
Production tax credits and other credits	0.00%	0.00%
Noncontrolling interest	0.00%
Other	0.20%	0.20%
Effective income tax rate	39.60%	39.90%
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	1.20%	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, net deferred taxes	-0.10%	-0.10%
Plant basis differences	-6.70%	-8.70%
Production tax credits and other credits	0.00%	0.00%
Noncontrolling interest	0.00%
Other	0.00%	0.20%
Effective income tax rate	29.40%	27.60%
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	5.30%	5.20%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%
Domestic production activities deduction	0.00%
Health care reform legislation	0.20%	0.20%
Amortization of investment tax credit, net deferred taxes	0.00%	-0.20%
Plant basis differences	-0.30%	-0.60%
Production tax credits and other credits	0.00%	0.00%
Noncontrolling interest	0.00%
Other	0.20%	0.10%
Effective income tax rate	40.40%	39.70%

Income_Taxes_Narrative_Details

Income Taxes - Narrative (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2009	Dec. 31, 2014
Income Tax Additional Narrative Information [Line Items]
Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities	$345,000,000
Deferred tax gain under involuntary conversion provisions of the IRC				1,200,000,000
IRS asserted penalties for understatement of tax	90,000,000
Expected non-cash charge to earnings			265,000,000
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position	810,000,000
Early termination amount		335,000,000
Taxes Payable, Current		285,000,000
Parent Company [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate	1,282,000,000				1,829,000,000
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	733,000,000				1,357,000,000
Commonwealth Edison Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate	147,000,000				149,000,000
Expected non-cash charge to earnings			170,000,000
Non-cash equity contributions			172,000,000
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position	310,000,000
Taxes Payable, Current		155,000,000
PECO Energy Co [Member]
Income Tax Additional Narrative Information [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate	0				44,000,000
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	$120,000,000				$0

Nuclear_Decommissioning_Rollfo

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) (Nuclear Decommissioning Asset Retirement Obligation [Member], Exelon Generation Co L L C [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Dec. 31, 2014
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Nuclear Decommissioning ARO, Beginning Balance	$6,961	[1]
Accretion expense	94
Nuclear Decommissioning ARO, Ending Balance	7,110	[1]
Current portion of ARO	8		9
Nuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Nuclear Decommissioning ARO, Ending Balance	$55	[2]
[1]	Includes $8 million as the current portion of the ARO at March 31, 2015 and December 31, 2014, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
[2]	the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

Nuclear_Decommissioning_Detail

Nuclear Decommissioning (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Nuclear Decommissioning Additional Narrative Information [Line Items]
Nuclear Decommissioning Annual Recovery Current	$24
Half Of Non Decommissioning Withdraw	50.00%
Decommissioning Fund Investments	10,712	10,537
Decommissioning Liability, Noncurrent	136	155
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Shortfall	50
Decommissioning Shortfall Percentage	5.00%
Decommissioning Fund Investments	10,712	10,537
Decommissioning Liability, Noncurrent	136	155
Nuclear Plant [Member] | Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Decommissioning Liability, Noncurrent	$87

Nuclear_Decommissioning_Unreal

Nuclear Decommissioning - Unrealized Gains on NDT Funds (Details) (Exelon Generation Co L L C [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Exelon Generation Co L L C [Member]
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]
Net unrealized gains (losses) on decommissioning trust funds - regulatory agreement units	$48	[1]	$61	[1]
Net unrealized gains (losses) on decommissioning trust funds - non-regulatory agreement units	40	[2],[3]	13	[2],[3]
Unrealized Gain Loss Investment Income Pledged Assets	$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 $10 million of net unrealized gains related to the Zion Station pledged assets for the three months ended March 31, 2015 and 2014. 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

Nuclear Decommissioning - Assets, Payables and Withdrawals by ZionSolutions (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014	Dec. 31, 2014
Nuclear Decommissioning Additional Narrative Information [Line Items]
Pledged assets for Zion Station decommissioning	$308			$319
Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]
Pledged assets for Zion Station decommissioning	308			319
Payable to Zion Solutions	281	[1]		292	[1]
Current portion of payable to Zion Solutions	145	[2]		137	[2]
Withdrawals by Zion Solutions to pay decommissioning costs	$687		$666
[1]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[2]	Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.

Retirement_Benefits_Narrative_

Retirement Benefits - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Changes in plan assets and benefit obligations recognized in OCI	$27
Increase in regulatory assets due valuation received by Exelon for its legacy pension and other postretirement benefit obligations.	48
Increase in regulatory liabilities due to updated valuation of Exelon's legacy pension and postretirement benefit obligations	11
Business Services Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	14	[1]	14	[1]
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	67	[2]	75	[2]
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	52		56
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	10		12
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	17		16
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation increase (decrease) reflecting actual census data	45
Expected return on assets	7.00%
Pension Plan, Defined Benefit [Member] | CENG [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	3
Pension Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.94%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefit obligation increase (decrease) reflecting actual census data	57
Expected return on assets	6.46%
Discount rate	3.92%
Other Postretirement Benefit Plan, Defined Benefit [Member] | CENG [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	$3
[1]	(b)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.
[2]	(a)For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.

Retirement_Benefits_Calculatio

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Sep. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$22	[1]	$29	[1]
Amortization of:
Pension and Other Postretirement Benefit Expense	159		173
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	82	[2]	69	[2]
Interest cost	178	[2]	183	[2]
Expected return on assets	-257	[2]	-241	[2]
Amortization of:
Prior service cost (benefit)	3	[2]	3	[2]
Actuarial loss	143	[2]	105	[2]
Net periodic benefit cost	149	[2]	119	[2]
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	30	[2]	33	[2]
Interest cost	42	[2]	55	[2]
Expected return on assets	-38	[2]	-38	[2]
Amortization of:
Prior service cost (benefit)	-43	[2]	-4	[2]
Actuarial loss	20	[2]	8	[2]
Net periodic benefit cost	11	[2]	54	[2]
CENG [Member] | Pension Plan, Defined Benefit [Member]
Amortization of:
Pension and Other Postretirement Benefit Costs	3
CENG [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Amortization of:
Pension and Other Postretirement Benefit Costs	3
CENG [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$2	[1]			$1
[1]	(a)Includes $2 million related to CENG for the three months ended March 31, 2015. CENG is not included in the 2014 amounts.
[2]	(a)For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.

Retirement_Benefits_Allocated_

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	$67	[1]	$75	[1]
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	52		56
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	10		12
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	17		16
Business Services Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	14	[2]	14	[2]
CENG [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense	$3
[1]	(a)For the three months ended March 31, 2015, the cost for pension benefits and other postretirement benefits related to CENG were $3 million and $3 million, respectively. CENG is not included in the 2014 amounts.
[2]	(b)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.

Retirement_Benefits_Defined_Co

Retirement Benefits - Defined Contribution Savings Plans (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Sep. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$22	[1]	$29	[1]
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	13	[1]	14	[1]
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	5		7
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	1		2
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	2		3
Business Services Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	1	[2]	3	[2]
CENG [Member]
Defined Benefit Plan Disclosure [Line Items]
Savings Plan Matching Contributions	$2	[1]			$1
[1]	(a)Includes $2 million related to CENG for the three months ended March 31, 2015. CENG is not included in the 2014 amounts.
[2]	(b)These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Severance_Ongoing_Severance_Pl

Severance - Ongoing Severance Plans (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	$20	$4
Exelon Generation Co L L C [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	20	4
Commonwealth Edison Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	0	0
PECO Energy Co [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	0	0
Baltimore Gas and Electric Company [Member]
Corporate Restructuring Severance Benefit Obligation [Line Items]
Severance charges recorded	$0	$0

Changes_in_Accumulated_Other_C2

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2013		Dec. 31, 2014
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	($2,684)	[1]	($2,040)	[1]
OCI before reclassifications	-49	[1]	-8	[1]
Amounts reclassified from AOCI	60	[1],[2]	12	[1],[2]
Net current-period OCI	11	[1]	4	[1]
Ending balance	-2,673	[1]	-2,036	[1]
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-28	[1]	120	[1]
OCI before reclassifications	-11	[1]	-1	[1]
Amounts reclassified from AOCI	17	[1],[2]	-24	[1],[2]
Net current-period OCI	6	[1]	-25	[1]
Ending balance	-22	[1]	95	[1]
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	3	[1]	2
OCI before reclassifications	0	[1]	0	[1]
Net current-period OCI	0	[1]	0	[1]
Ending balance	3	[1]	2	[1]
Accumulated Defined Benefit Plans Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-2,640	[1]	-2,260	[1]
OCI before reclassifications	-26	[1]	-13	[1]
Amounts reclassified from AOCI	43	[1],[2]	35	[1],[2]
Net current-period OCI	17	[1]	22	[1]
Ending balance	-2,623	[1]	-2,238	[1]
Accumulated Translation Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-19	[1]	-10
OCI before reclassifications	-12	[1]	-5	[1]
Net current-period OCI	-12	[1]	-5	[1]
Ending balance	-31	[1]	-15	[1]
Accumulated Equity Investment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	0	[1]	108	[1]
OCI before reclassifications	0	[1]	11	[1]
Amounts reclassified from AOCI	0	[1],[2]	1	[1],[2]
Net current-period OCI	0	[1]	12	[1]
Ending balance	0	[1]	120	[1]
Exelon Generation Co L L C [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-36	[1]	214	[1]
OCI before reclassifications	-18	[1]	2	[1]
Amounts reclassified from AOCI	1	[1],[2]	-23	[1],[2]
Net current-period OCI	-17	[1]	-21	[1]
Ending balance	-53	[1]	193	[1]
Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-18	[1]	114	[1]
OCI before reclassifications	-6	[1]	-1	[1]
Amounts reclassified from AOCI	1	[1],[2]	-24	[1],[2]
Net current-period OCI	-5	[1]	-25	[1]
Ending balance	-23	[1]	89	[1]
Exelon Generation Co L L C [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	1	[1]	2	[1]
OCI before reclassifications	0	[1]	-3	[1]
Net current-period OCI	0	[1]	-3	[1]
Ending balance	1	[1]	-1	[1]
Exelon Generation Co L L C [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance					0	[1]
Ending balance			0	[1]	0	[1]
Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-19	[1]	-10
OCI before reclassifications	-12	[1]	-5	[1]
Net current-period OCI	-12	[1]	-5	[1]
Ending balance	-31	[1]	-15	[1]
Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	0	[1]	108	[1]
OCI before reclassifications	0	[1]	11	[1]
Amounts reclassified from AOCI	0	[1],[2]	1	[1],[2]
Net current-period OCI	0	[1]	12	[1]
Ending balance	0	[1]	120	[1]
PECO Energy Co [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance					1	[1]	1	[1]
Ending balance	1	[1]	1	[1]	1	[1]	1	[1]
PECO Energy Co [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance					0	[1]	0	[1]
Ending balance	0	[1]	0	[1]	0	[1]	0	[1]
PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance					1	[1]	1	[1]
Ending balance	$1	[1]	$1	[1]	$1	[1]	$1	[1]
[1]	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.
[2]	See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.

Changes_in_Accumulated_Other_C3

Changes in Accumulated Other Comprehensive Income - Reclassification out of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Sep. 30, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	$8,830	[1]	$7,237	[1]
Income before income taxes	1,101		39
Income taxes	-363		54
Net income	738		93
Prior service benefit reclassified to periodic benefit cost	8				-1
Other Nonoperating Income (Expense)	80		98
Equity in losses of unconsolidated affiliates			-19
Interest Expense	335		217
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Net income	-60	[2]	-12	[2]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	2
Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	-26
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes	-27	[2]	39	[2]
Income taxes	10	[2]	-15	[2]
Net income	-17	[2]	24	[2]
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense			39
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	-3
Accumulated Defined Benefit Plans Adjustment [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes	-71	[2]	-58	[2]
Income taxes	28	[2]	23
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	-43	[2]
Net income			-35	[2]
Prior service benefit reclassified to periodic benefit cost	19	[2],[3]	-2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	-90	[2],[3]	-56
Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes			-1	[2]
Income taxes			0	[2]
Net income			-1	[2]
Other Nonoperating Income (Expense)			-1
Exelon Generation Co L L C [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	5,840		4,390
Income before income taxes	711		-384
Income taxes	-226		199
Net income	485		-185
Other Nonoperating Income (Expense)	94		85
Equity in losses of unconsolidated affiliates			-19
Interest Expense	90		73
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]
Net income	-1	[2]	23	[2]
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	2
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Interest Rate Swap [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	0
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]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes	-1	[2]	39	[2]
Income taxes	0	[2]	-15	[2]
Net income	-1	[2]	24	[2]
Exelon Generation Co L L C [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense			39
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]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Interest expense	-3
Exelon Generation Co L L C [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]
Income before income taxes	0	[2]	0
Income taxes	0	[2]	0
Net Income (Loss), Including Portion Attributable to Nonredeemable Noncontrolling Interest	0	[2]
Net income			0
Prior service benefit reclassified to periodic benefit cost	0	[2],[3]	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	0	[2],[3]	0
Exelon Generation Co L L C [Member] | Equity Method Investments | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]
Income before income taxes			-1	[2]
Income taxes			0	[2]
Net income			-1	[2]
Other Nonoperating Income (Expense)			($1)
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}
[2]	All amounts are net of tax. Amounts in parentheses represent a decrease in net income.
[3]	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 12— Retirement Benefits for additional details).

Changes_in_Accumulated_Other_C4

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Sep. 30, 2013	Dec. 31, 2014		Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss, net	($2,673)	[1]	($2,036)	[1]		($2,684)	[1]	($2,040)	[1]
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	8				-1
Actuarial gain (loss) reclassified to periodic cost	-35				-23
Pension and non-pension postretirement benefit plans valuation adjustment	17				7
Change in unrealized gain (loss) on cash flow hedges	-2				18
Change in unrealized income on equity investments	0				-7
Total	-12		-6
Exelon Generation Co L L C [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Accumulated other comprehensive loss, net	-53	[1]	193	[1]		-36	[1]	214	[1]
Pension and non-pension postretirement benefit plans:
Change in unrealized gain (loss) on cash flow hedges	5				19
Change in unrealized income on equity investments	0				-7
Change in marketable securities	0				-2
Total	$5		$10
[1]	All amounts are net of tax. Amounts in parentheses represent a decrease in accumulated other comprehensive income.

Common_Stock_Narrative_Details

Common Stock - Narrative (Details) (USD $)	1 Months Ended	3 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Sep. 30, 2014	Mar. 31, 2015	Jun. 11, 2014	Jun. 05, 2013
Common Stock [Abstract]
Temporary Equity, Share Subscriptions	57.5			57.5
Shares Issued, Price Per Share			$2,500,000		$35
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions		$35,000,000
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share	$33.21
Junior Subordinated Notes, Noncurrent					$1,150,000,000
Forward Contract Indexed to Issuer's Equity, Indexed Shares					23

Earnings_Per_Share_and_Equity_2

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Net income attributable to common shareholders	$693	$90
Average common shares outstanding — basic	862	858
Potentially dilutive effect of stock options, performance share awards and restricted stock	5	3
Average common shares outstanding — diluted	867	861

Earnings_Per_Share_and_Equity_3

Earnings Per Share and Equity - Narrative (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Dec. 31, 2014
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Treasury Stock, Shares held	35,000,000				35,000,000
Treasury Stock, Value	2,327				$2,327
Employee Stock Option [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding	15,000,000	16,000,000	18,000,000	20,000,000

Commitments_and_Contingencies_2

Commitments and Contingencies - Energy Commitments (Details) (USD $)	Apr. 01, 2015		Mar. 31, 2015
In Millions, unless otherwise specified
Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			$840
2014			258
2015			279
2016			152
2017			38
2018			30
Thereafter			83
Energy Supply Procurement [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2014	179	[1]
2015	112	[1]
CapacityOffsets [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
2014			107
2015			133
2016	23		136
2017	21		137
2018			138
Operating Leases, Future Minimum Payments Receivable [Abstract]
Thereafter			591
Exelon Generation Co L L C [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			2,028
2014			454
2015			560
2016			387
2017			177
2018			138
Thereafter			312
Exelon Generation Co L L C [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			364	[2],[3]
2014			123	[2],[3]
2015			81	[2],[3]
2016			43	[2],[3]
2017			31	[2],[3]
2018			23	[2],[3]
Thereafter			63	[2],[3]
Exelon Generation Co L L C [Member] | Net Capacity Purchases [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			1,321	[4]
2014			317	[4]
2015			287	[4]
2016			219	[4]
2017			109	[4]
2018			113	[4]
Thereafter			276	[4]
Exelon Generation Co L L C [Member] | Power Purchases [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			597	[5]
2014			124	[5]
2015			258	[5]
2016			153	[5]
2017			52	[5]
2018			9	[5]
Thereafter			1	[5]
Exelon Generation Co L L C [Member] | Transmission Rights Purchases [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			110	[6]
2014			13	[6]
2015			15	[6]
2016			15	[6]
2017			16	[6]
2018			16	[6]
Thereafter			35	[6]
Commonwealth Edison Co [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			152	[7]
2014			53	[7]
2015			82	[7]
2016			2	[7]
2017			2	[7]
2018			2	[7]
Thereafter			11	[7]
Commonwealth Edison Co [Member] | Energy Supply Procurement [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			473	[1]
2014			182	[1]
2015			151	[1]
2016			140	[1]
2017			0	[1]
2018			0	[1]
Thereafter			0	[1]
Commonwealth Edison Co [Member] | Renewable Energy Including Renewable Energy Credits [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			1,498	[8]
2014			56	[8]
2015			76	[8]
2016			77	[8]
2017			78	[8]
2018			84	[8]
Thereafter			1,127	[8]
PECO Energy Co [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			11	[7]
2014			5	[7]
2015			6	[7]
2016			0	[7]
2017			0	[7]
2018			0	[7]
Thereafter			0	[7]
PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			832	[9]
2014			532	[9]
2015			268	[9]
2016			32	[9]
2017			0	[9]
2018			0	[9]
Thereafter			0	[9]
PECO Energy Co [Member] | Alternative Energy Credits [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			13	[10]
2014			2	[10]
2015			2	[10]
2016			2	[10]
2017			2	[10]
2018			2	[10]
Thereafter			3	[10]
Baltimore Gas and Electric Company [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			313	[7]
2014			77	[7]
2015			110	[7]
2016			107	[7]
2017			5	[7]
2018			5	[7]
Thereafter			9	[7]
Baltimore Gas and Electric Company [Member] | Energy Supply Procurement [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			1,074	[11]
2014			538	[11]
2015			448	[11]
2016			88	[11]
2017			0	[11]
2018			0	[11]
Thereafter			0	[11]
Baltimore Gas and Electric Company [Member] | Curtailment Services [Member]
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]
Total			105	[12]
2014			30	[12]
2015			34	[12]
2016			29	[12]
2017			12	[12]
2018			$0	[12]
[1]	ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2018. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of March 31, 2015, ComEd has completed the ICC-approved procurement process for a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017.
[2]	Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information.
[3]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MUZCNTc2MzY0RjBDMkQwMTJFNTEwOTNBRjYwNTQ5M0IM}
[4]	Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generation’s expected payments under these arrangements at March 31, 2015, net of fixed capacity payments expected to be received ("capacity offsets") by Generation under contracts to resell such acquired capacity to third parties under long-term capacity sale contracts. As of March 31, 2015, capacity offsets were $107 million, $133 million, $136 million, $137, million, $138 million, and $591 million for years 2015, 2016, 2017, 2018, 2019, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.
[5]	The table excludes renewable energy purchases that are contingent in nature.
[6]	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
[7]	Purchase obligations include commitments related to smart meter installation. See Note 5 — Regulatory Matters for additional information.
[8]	Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms.
[9]	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2017. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 — Regulatory Matters for additional information.
[10]	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information.
[11]	BGE entered into various contracts for the procurement of electricity that expire between 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters of the Exelon 2014 10-K for additional information.
[12]	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. See Note 3 —Regulatory Matters of the Exelon 2014 Form 10-K for additional information.

Commitments_and_Contingencies_3

Commitments and Contingencies - Fuel Purchase Obligations (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Exelon Generation Co L L C [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	$2,028
2014	454
2015	560
2016	387
2017	177
2018	138
Thereafter	312
Exelon Generation Co L L C [Member] | Public Utilities, Inventory, Fuel [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	8,479
2014	1,015
2015	1,145
2016	1,151
2017	987
2018	869
Thereafter	3,312
PECO Energy Co [Member] | Public Utilities, Inventory, Fuel [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	392
2014	109
2015	104
2016	61
2017	34
2018	13
Thereafter	71
Baltimore Gas and Electric Company [Member] | Public Utilities, Inventory, Fuel [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	614
2014	82
2015	87
2016	74
2017	64
2018	61
Thereafter	$246

Commitments_and_Contingencies_4

Commitments and Contingencies - Other Purchase Obligations (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	$840
2014	258
2015	279
2016	152
2017	38
2018	30
Thereafter	83
Exelon Generation Co L L C [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	2,028
2014	454
2015	560
2016	387
2017	177
2018	138
Thereafter	312
Exelon Generation Co L L C [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	364	[1],[2]
2014	123	[1],[2]
2015	81	[1],[2]
2016	43	[1],[2]
2017	31	[1],[2]
2018	23	[1],[2]
Thereafter	63	[1],[2]
Commonwealth Edison Co [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	152	[3]
2014	53	[3]
2015	82	[3]
2016	2	[3]
2017	2	[3]
2018	2	[3]
Thereafter	11	[3]
PECO Energy Co [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	11	[3]
2014	5	[3]
2015	6	[3]
2016	0	[3]
2017	0	[3]
2018	0	[3]
Thereafter	0	[3]
Baltimore Gas and Electric Company [Member] | Other Purchase Obligations [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	313	[3]
2014	77	[3]
2015	110	[3]
2016	107	[3]
2017	5	[3]
2018	5	[3]
Thereafter	$9	[3]
[1]	Purchase obligations do not include commitments related to construction contracts. See Construction Commitments section below for additional information.
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MUZCNTc2MzY0RjBDMkQwMTJFNTEwOTNBRjYwNTQ5M0IM}
[3]	Purchase obligations include commitments related to smart meter installation. See Note 5 — Regulatory Matters for additional information.

Commitments_and_Contingencies_5

Commitments and Contingencies - Commitments Narrative (Details) (USD $)	3 Months Ended
	Sep. 30, 2014	Mar. 31, 2015	Dec. 31, 2014	Jun. 30, 2012	Mar. 31, 2014
Guarantor Obligations [Line Items]
Accrued environmental liabilities		$340,000,000	$347,000,000
Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
Accrued environmental liabilities		62,000,000	63,000,000
2015		560,000,000
2014		454,000,000
2017		177,000,000
Minimum future operating lease payments due in one year		0
Minimum future operating lease payments due in three years		12,000,000
Minimum future operating lease payments due in four years		13,000,000
Minimum future operating lease payments due in five years		13,000,000
Minimum future operating lease payments due beyond five years		285,000,000
Other Commitment		3,500,000
Loss Contingency, Loss in Period	44,000,000
Loss Contingency, Estimate of Possible Loss	105,000,000
Operating Leases, Future Minimum Payments, Due in Two Years		5,000,000
Exelon Generation Co L L C [Member] | Perryman Construction [Member]
Guarantor Obligations [Line Items]
Other Commitment		17,000,000
Exelon Generation Co L L C [Member] | Combine-cycle Turbine Units [Member]
Guarantor Obligations [Line Items]
Other Commitment		816,000,000
Exelon Generation Co L L C [Member] | Fair Wind Project [Member]
Guarantor Obligations [Line Items]
Other Commitment		26,000,000
Exelon Generation Co L L C [Member] | Sendero Wind Project [Member]
Guarantor Obligations [Line Items]
Other Commitment		34,000,000
Baltimore Gas and Electric Company [Member]
Guarantor Obligations [Line Items]
Accrued environmental liabilities		3,000,000	1,000,000
Business Acquisition, Direct Investment With State And Local Governments Due To Settlement				1,000,000,000
Minimum [Member] | Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
Business Acquisition, Construction Cost					95,000,000
Business Acquisition, Development Of New Generation Cost		600,000,000
Maximum [Member] | Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
Business Acquisition, Construction Cost					120,000,000
Business Acquisition, Development Of New Generation Cost		650,000,000
Equity Method Investments [Member] | Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
2015		77,000,000
2017		$19,000,000

Commitments_and_Contingencies_6

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) (Exelon Generation Co L L C [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015
Guarantor Obligations [Line Items]
2014	$454
2015	560
2016	387
2017	177
2018	138
Total	2,028
Equity Method Investments [Member]
Guarantor Obligations [Line Items]
2015	77
2016	37
2017	19
2018	14
Total	147
Long-term Purchase Commitment, Amount	$20

Commitments_and_Contingencies_7

Commitments and Contingencies - Schedule of Commercial Commitments (Details) (USD $)	Mar. 31, 2015
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$10,267,000,000
Underwriting Discount	60,000,000	[1]
Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1,740,000,000	[2]
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	5,453,000,000	[3]
Estimated net exposure for commercial transaction obligations	642,000,000
Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	3,014,000,000	[4]
Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	7,365,000,000
Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1,673,000,000	[2]
Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	2,678,000,000	[5]
Estimated net exposure for commercial transaction obligations	429,000,000
Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	3,014,000,000	[4]
Commonwealth Edison Co [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	220,000,000
Commonwealth Edison Co [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	18,000,000	[2]
Commonwealth Edison Co [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	202,000,000	[6]
Commonwealth Edison Co [Member] | Trust Preferred Securities [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	200,000,000
PECO Energy Co [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	218,000,000
PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	22,000,000	[2]
PECO Energy Co [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	196,000,000	[7]
PECO Energy Co [Member] | Trust Preferred Securities [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	178,000,000
Baltimore Gas and Electric Company [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	264,000,000
Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	1,000,000	[2]
Baltimore Gas and Electric Company [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	263,000,000	[8]
Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted	$250,000,000
Commonwealth Edison III [Member] | Commonwealth Edison Co [Member]
Guarantor Obligations [Line Items]
Percentage owned finance subsidiary	100.00%
PECO Trust III and IV [Member] | PECO Energy Co [Member]
Guarantor Obligations [Line Items]
Percentage owned finance subsidiary	100.00%
Baltimore Gas and Electric Capital Trust II [Member] | Baltimore Gas and Electric Company [Member]
Guarantor Obligations [Line Items]
Percentage owned finance subsidiary	100.00%
[1]	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 15 — Common Stock for further details of the equity securities offering.
[2]	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
[3]	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $642 million at March 31, 2015, which represents the total amount Exelon could be required to fund based on March 31, 2015 market prices.
[4]	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.
[5]	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $429 million at March 31, 2015, which represents the total amount Generation could be required to fund based on March 31, 2015 market prices.
[6]	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.
[7]	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
[8]	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

Commitments_and_Contingencies_8

Commitments and Contingencies - Contingencies Narrative (Details) (USD $)	3 Months Ended
	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	$10,267,000,000
Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Total of U.S. licensed nuclear reactors	104
Nuclear financial protection pool value	375,000,000
Maximum liability per nuclear incident	13,600,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	7,365,000,000
Funds available for claim	13,200,000,000
Recovery of Direct Costs	3,200,000,000
Nuclear Insurance Premiums [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	2,700,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	3,014,000,000	[1]
Nuclear Insurance Premiums [Member] | Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]
Nuclear Insurance Financial Protection Pool Surcharge On Nuclear Incident Assessment	5.00%
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	19,000,000
Guarantor Obligations, Maximum Exposure, Undiscounted	$3,014,000,000	[1]
[1]	Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

Commitments_and_Contingencies_9

Commitments and Contingencies - Environmental Issues Narrative (Details) (USD $)	3 Months Ended	1 Months Ended	0 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Oct. 31, 2007	Apr. 12, 2012	Feb. 28, 2012	Sep. 30, 2014
			Defendant	Defendant
Accrual For Environmental Loss Contingencies [Line Items]
Litigation Settlement, Amount	$14
Commonwealth Edison Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites	42
Approved clean-up	17
Sites under study/remediation	25
PECO Energy Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites	26
Approved clean-up	16
Sites under study/remediation	10
Baltimore Gas and Electric Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total number of MGP sites	13
Sites under study/remediation	2
Maximum estimated clean-up costs for all potentially responsible parties	1.7
Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Consent decree penalty		1
Environmental loss contingencies	13
Loss Contingency, Estimate of Possible Loss					105
Cotter Corporation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Number of Defendants			14	15
Cotter Corporation [Member] | Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Total cost of remediation to be shared by PRPs	50
DOJ potential settlement	90
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	19
Minimum estimated clean-up costs for all potentially responsible parties	50
Maximum estimated clean-up costs for all potentially responsible parties	64
Rossville ash site [Member] | Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Loss Contingency, Estimate of Possible Loss	$10

Recovered_Sheet2

Commitments and Contingencies - Litigation and Regulatory Matters (Details) (USD $)	0 Months Ended	3 Months Ended
	Jul. 11, 2011	Mar. 31, 2015	Dec. 31, 2014	Jun. 05, 2013
	Customer	claimant		Customer
		Customer
Exelon Generation Co L L C [Member]
Asbestos Loss Contingency [Abstract]
Asbestos liability reserve		97,000,000	$100,000,000
Asbestos liability reserve related to open claims		20,000,000
Open asbestos liability claims		224
Asbestos liability reserve related to anticipated claims		77,000,000
Commonwealth Edison Co [Member]
Continuous Power Interruption [Abstract]
Minimum number of customers ComEd can be held liable to for power interruption		30,000
Number of customers affected by a major storm	900,000
Number of customers proposed by the ICC that ComEd should not be granted a waiver under Continuous Power Interruption				34,559
Telephone Consumer Protection Act Lawsuit [Abstract]
Possible Defendants Number		1,200,000
Commonwealth Edison Co [Member] | Legal Reserve [Member]
Telephone Consumer Protection Act Lawsuit [Abstract]
Accrued Liabilities		5,000,000
Commonwealth Edison Co [Member] | Maximum [Member]
Telephone Consumer Protection Act Lawsuit [Abstract]
Loss Contingency, Damages Sought, Value		1,500
Commonwealth Edison Co [Member] | Minimum [Member]
Telephone Consumer Protection Act Lawsuit [Abstract]
Loss Contingency, Damages Sought, Value		500
Baltimore Gas and Electric Company [Member]
Asbestos Loss Contingency [Abstract]
Number of claimants		467

Recovered_Sheet3

Commitments and Contingencies - Schedule of Accruals for Environmental Matters (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	$340	$347
Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	62	63
Commonwealth Edison Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	231	238
PECO Energy Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	44	45
Baltimore Gas and Electric Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	3	1
Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	272	277
Accrual For MGP Investigation And Remediation [Member] | Exelon Generation Co L L C [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	0	0
Accrual For MGP Investigation And Remediation [Member] | Commonwealth Edison Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	228	235
Accrual For MGP Investigation And Remediation [Member] | PECO Energy Co [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	42	42
Accrual For MGP Investigation And Remediation [Member] | Baltimore Gas and Electric Company [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	$2	$0

Supplemental_Financial_Informa2

Supplemental Financial Information - Narrative (Details) (PECO Energy Co [Member], USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2015
Supplemental Financial Information Tables [Line Items]
Smart Grid Grant Project Capital Expenditures	$2
Smart Grid Grant Reimbursements	2
Financing Receivable, Net		14
Financing Receivable, Allowance for Credit Losses	15	14
Low To Medium Risk [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	1	1
Risk Level, Medium [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	3	4
Risk Level, High [Member]
Supplemental Financial Information Tables [Line Items]
Financing Receivable, Net	$11	$9

Supplemental_Financial_Informa3

Supplemental Financial Information - Operations (Detail) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Decommissioning-Related Activities [Abstract]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	$71		$43	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	29		25	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	48		61
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	40		13
Net unrealized income (losses) on pledged assets	10		10
Regulatory offset to decommissioning trust fund-related activities	-106	[2]	-94	[2]
Total decommissioning-related activities	92		58
Investment income	1		1
Long-term lease income	4		6
Interest income related to uncertain income tax positions	0		10
AFUDC - equity	5		6
Gain (Loss) on Sale of Derivatives	-23	[3]
Other Income	1		17
Other, net	80		98
Exelon Generation Co L L C [Member]
Decommissioning-Related Activities [Abstract]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	71		43	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	29		25	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	48		61
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	40		13
Net unrealized income (losses) on pledged assets	10		10
Regulatory offset to decommissioning trust fund-related activities	-106	[2]	-94	[2]
Total decommissioning-related activities	92		58
Investment income	1		1
Long-term lease income	0		0
Interest income related to uncertain income tax positions	1		14
AFUDC - equity	0		0
Gain (Loss) on Sale of Derivatives	3	[3]
Other Income	-3		12
Other, net	94		85
Commonwealth Edison Co [Member]
Decommissioning-Related Activities [Abstract]
Investment income	0
Interest income related to uncertain income tax positions	0		0
AFUDC - equity	0		3
Other Income	3		2
Other, net	3		5
PECO Energy Co [Member]
Decommissioning-Related Activities [Abstract]
Investment income	0		0
Interest income related to uncertain income tax positions	0		0
AFUDC - equity	2		1
Other Income	0		1
Other, net	2		2
Baltimore Gas and Electric Company [Member]
Decommissioning-Related Activities [Abstract]
Investment income	1	[4]
Interest income related to uncertain income tax positions	0
AFUDC - equity	3
Other Income	0
Other, net	$4		$4
[1]	Includes investment income and realized gains and losses on sales of investments of the trust funds.
[2]	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2014 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 are probable not to occur. As a result, $26 million of anticipated payments were reclassified from Accumulated OCI to Other, net in Exelon's Consolidated Statement of Operations and Comprehensive Income.
[4]	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters of the Exelon 2014 Form 10-K for additional information regarding the rate stabilization deferral.

Supplemental_Financial_Informa4

Supplemental Financial Information - Cash Flow (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	$540		$481
Regulatory assets	58		72
Amortization of intangible assets, net	12		11
Amortization of energy contract assets and liabilities	-31	[1]	42	[1]
Nuclear fuel	272	[2]	234	[2]
Asset retirement obligation accretion	97	[3]	68	[3]
Total depreciation, amortization and accretion	948		908
Other Non-Cash Operating Activities [Abstract]
Pension and Other Postretirement Benefit Expense	159		173
Gain (loss) on equity method investments			19
Provision for uncollectible accounts	84		35
Stock-based compensation costs	39		46
Other Decommissioning Related Activity	-44	[4]	-35	[4]
Energy-related options	9	[5]	31	[5]
Amortization of regulatory asset related to debt costs			3
Amortization of rate stabilization deferral			20
Amortization of debt fair value adjustment	-9		-12
Discrete impacts from EIMA			-4	[6]
Amortization of debt costs	18		5
Inventory Write-down	10		2
Other	4		-7
Total other noncash operating activities	344		276
Changes In Other Assets and Liabilities [Abstract]
Under/over-recovered energy and transmission costs			-15
Other regulatory assets and liabilities	92		-4
Increase (Decrease) in Deposits	226	[7]
Increase (Decrease) in Other Current Liabilities	-155
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	113
Other current assets and liabilities			-209
Other noncurrent assets and liabilities			-50
Total changes in other assets and liabilities	115		-278
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Total noncash investing and financing activities	0		0
Exelon Generation Co L L C [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	242		200
Regulatory assets	0		0
Amortization of intangible assets, net	12		11
Amortization of energy contract assets and liabilities	-32	[1]	44	[1]
Nuclear fuel	272	[2]	234	[2]
Asset retirement obligation accretion	97	[3]	68	[3]
Total depreciation, amortization and accretion	591		557
Other Non-Cash Operating Activities [Abstract]
Pension and Other Postretirement Benefit Expense	67		75
Gain (loss) on equity method investments			19
Provision for uncollectible accounts	4		1
Stock-based compensation costs	0		0
Other Decommissioning Related Activity	-44	[4]	-35	[4]
Energy-related options	9	[5]	31	[5]
Amortization of regulatory asset related to debt costs	0		0
Amortization of rate stabilization deferral	0		0
Amortization of debt fair value adjustment	-4		-5
Discrete impacts from EIMA	0	[6]	0	[6]
Amortization of debt costs	4		3
Inventory Write-down	10		2
Other	-1		-2
Total other noncash operating activities	45		89
Changes In Other Assets and Liabilities [Abstract]
Under/over-recovered energy and transmission costs	0
Other regulatory assets and liabilities	0
Increase (Decrease) in Deposits	226	[7]
Increase (Decrease) in Other Current Liabilities	-100
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	41
Other current assets and liabilities			-80
Other noncurrent assets and liabilities			-23
Total changes in other assets and liabilities	85		-103
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Total noncash investing and financing activities	0		0
Commonwealth Edison Co [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	154		143
Regulatory assets	21		30
Total depreciation, amortization and accretion	175		173
Other Non-Cash Operating Activities [Abstract]
Pension and Other Postretirement Benefit Expense	52		56
Provision for uncollectible accounts	22		-11
Stock-based compensation costs	0
Energy-related options			0	[5]
Amortization of regulatory asset related to debt costs	2		2
Discrete impacts from EIMA	46	[6]	-4	[6]
Amortization of debt costs	1		-5
Inventory Write-down	0
Other	3		-2
Total other noncash operating activities	126		36
Changes In Other Assets and Liabilities [Abstract]
Under/over-recovered energy and transmission costs	0		4
Other regulatory assets and liabilities	2		-10
Increase (Decrease) in Deposits	0
Increase (Decrease) in Other Current Liabilities	-1
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	10
Other current assets and liabilities			-29
Other noncurrent assets and liabilities			11
Total changes in other assets and liabilities	-9		-24
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Indemnification of like-kind exchange position	14		38
Total noncash investing and financing activities	2		2
Commonwealth Edison Co [Member] | Indemnification Agreement [Member]
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Indemnification of like-kind exchange position	2	[8]	2	[8]
PECO Energy Co [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	58		56
Regulatory assets	4		2
Total depreciation, amortization and accretion	62		58
Other Non-Cash Operating Activities [Abstract]
Pension and Other Postretirement Benefit Expense	10		12
Gain (loss) on equity method investments			0
Provision for uncollectible accounts	33		35
Stock-based compensation costs	0		0
Other Decommissioning Related Activity			0	[4]
Energy-related options			0	[5]
Amortization of regulatory asset related to debt costs	1		1
Amortization of rate stabilization deferral			0
Amortization of debt fair value adjustment			0
Discrete impacts from EIMA			0	[6]
Amortization of debt costs	1		1
Inventory Write-down	0
Other	-1		0
Total other noncash operating activities	44		49
Changes In Other Assets and Liabilities [Abstract]
Under/over-recovered energy and transmission costs	26		-17
Other regulatory assets and liabilities	-5		-3
Increase (Decrease) in Deposits	0
Increase (Decrease) in Other Current Liabilities	-95	[9]
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	-2
Other current assets and liabilities			-105	[9]
Other noncurrent assets and liabilities			-2
Total changes in other assets and liabilities	-72		-127
Baltimore Gas and Electric Company [Member]
Depreciation, Amortization and Accretion [Abstract]
Property, plant and equipment	71		70
Regulatory assets	35		38
Total depreciation, amortization and accretion	106		108
Other Non-Cash Operating Activities [Abstract]
Pension and Other Postretirement Benefit Expense	16		16
Gain (loss) on equity method investments			0
Provision for uncollectible accounts	25		11
Stock-based compensation costs	0		0
Other Decommissioning Related Activity			0	[4]
Energy-related options			0	[5]
Amortization of regulatory asset related to debt costs	0		0
Amortization of rate stabilization deferral	25		20
Amortization of debt fair value adjustment			0
Discrete impacts from EIMA			0	[6]
Amortization of debt costs	1		0
Inventory Write-down	0
Other	-3		-4
Total other noncash operating activities	64		43
Changes In Other Assets and Liabilities [Abstract]
Under/over-recovered energy and transmission costs	39		23
Other regulatory assets and liabilities	25		6
Increase (Decrease) in Deposits	0
Increase (Decrease) in Other Current Liabilities	30
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	1
Other current assets and liabilities			18
Other noncurrent assets and liabilities			-3
Total changes in other assets and liabilities	93		44
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]
Indemnification of like-kind exchange position	$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 15 — Asset Retirement Obligations of the Exelon 2014 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]	Relates primarily to cash deposits recalled from ISOs/RTOs and replaced with letters of credit.
[8]	See Note 10 — Income Taxes for discussion of the like-kind exchange tax position
[9]	Relates primarily to prepaid utility taxes.

Supplemental_Financial_Informa5

Supplemental Financial Information - Balance Sheet (Details) (USD $)	Mar. 31, 2015		Dec. 31, 2014
In Millions, unless otherwise specified
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation	$15,207	[1]	$14,742	[2]
Accounts receivable, net
Allowance for uncollectible accounts	365		311
Exelon Generation Co L L C [Member]
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation	7,905	[1]	7,612	[2]
Accounts receivable, net
Allowance for uncollectible accounts	61		60
Accumulated amortization of nuclear fuel	2,772		2,673
Commonwealth Edison Co [Member]
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation	3,247		3,432
Accounts receivable, net
Allowance for uncollectible accounts	100		84
PECO Energy Co [Member]
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation	2,989		2,917
Accounts receivable, net
Allowance for uncollectible accounts	127		100
Baltimore Gas and Electric Company [Member]
Property, Plant and Equipment, Net [Abstract]
Accumulated depreciation	2,905		2,868
Accounts receivable, net
Allowance for uncollectible accounts	$84		$67
[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,772 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million.

Segment_Information_Narrative_

Segment Information - Narrative (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Segment Reporting Information [Line Items]
Number of reportable segments	9
Other Segments [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	$1,929	$1,554
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	6
Operating Segments [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Utility Taxes	27	24
Operating Segments [Member] | Commonwealth Edison Co [Member]
Segment Reporting Information [Line Items]
Utility Taxes	$62	$63

Segment_Information_Reconcilia

Segment Information - Reconciliation to Consolidated Financial Statements (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014		Dec. 31, 2014
Segment Reporting Information [Line Items]
Revenues	$8,830	[1]	$7,237	[1]
Operating revenues from affiliates	1	[2]	1	[2]
Net income (loss)	738		93
Assets	87,391		86,814		86,814
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	5,840	[3]	4,390	[3]
Operating Segments [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Revenues	5,840	[1],[4]	4,390	[1],[4]
Operating revenues from affiliates	210	[2],[4]	316	[2],[4]
Net income (loss)	485	[4]	-185	[4]
Assets	45,318	[4]	45,348	[4]
Utility Taxes	27		24
Operating Segments [Member] | Commonwealth Edison Co [Member]
Segment Reporting Information [Line Items]
Revenues	1,185	[1]	1,134	[1]
Operating revenues from affiliates	1	[2]	1	[2]
Net income (loss)	90		98
Assets	25,731		25,392
Utility Taxes	62		63
Operating Segments [Member] | PECO Energy Co [Member]
Segment Reporting Information [Line Items]
Revenues	985	[1]	993	[1]
Operating revenues from affiliates	0	[2]	1	[2]
Net income (loss)	139		89
Assets	10,169		9,943
Utility Taxes	35		35
Operating Segments [Member] | Baltimore Gas and Electric Company [Member]
Segment Reporting Information [Line Items]
Revenues	1,036	[1]	1,054	[1]
Operating revenues from affiliates	7	[2]	16	[2]
Net income (loss)	109		88
Assets	8,130		8,078
Utility Taxes	52		20
Operating Segments [Member] | PECO Energy Co Affiliate [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates	63		88
Operating Segments [Member] | Baltimore Gas And Electric Company Affiliate [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates	138		120
Operating Segments [Member] | Commonwealth Edison Co Affiliate [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates	9		108
Other Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues	318	[1],[5]	290	[1],[5]
Operating revenues from affiliates	316	[2],[5]	290	[2],[5]
Net income (loss)	-84	[5]	4	[5]
Assets	10,457	[5]	9,794	[5]
Intersegment Eliminations [Member] | Segment Elimination [Member]
Segment Reporting Information [Line Items]
Revenues	-534	[1]	-624	[1]
Operating revenues from affiliates	-533	[2]	-623	[2]
Net income (loss)	-1		-1
Assets	-12,414		-11,741
Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	$0		$0
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NzEwQ0VGNzJGQTI1RkM2RDgzOUMwOTNBRjYwNUU2MTQM}
[3]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MzJCOTc5NTI3RTkyMDA2QTkzQzgwOTNBRjYwNURBRkYM}
[4]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NTk4QTIxQTlGRTU5OTQxMkFDM0QwOTNBRjYwNTMyMDIM}
[5]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246QzVGNDk1MTM4RDRDN0NDQjA5MkUwOTNBRjYwNUZCMzMM}

Segment_Information_Generation

Segment Information - Generation Total Revenues (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Segment Reporting Information [Line Items]
Revenues	$8,830	[1]	$7,237	[1]
Revenue from Related Parties	1	[2]	1	[2]
Net income (loss)	738		93
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	154		-760
Revenues	5,840		4,390
Revenue from Related Parties	211		334
Net income (loss)	485		-185
Amortization of Intangible Assets	-40		93
Exelon Generation Co L L C [Member] | Sales Revenue, Goods, Net [Member]
Segment Reporting Information [Line Items]
Unrealized Gain (Loss) on Commodity Contracts	162		-730
Amortization of Intangible Assets	-38		42
Corporate and Other [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	318	[1],[3]	290	[1],[3]
Revenue from Related Parties	316	[2],[3]	290	[2],[3]
Net income (loss)	-84	[3]	4	[3]
Segment Elimination [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-534	[1]	-624	[1]
Revenue from Related Parties	-533	[2]	-623	[2]
Net income (loss)	-1		-1
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	1,513		1,418
Generation Mid Atlantic [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	1,517		1,441
Generation Mid Atlantic [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-4		-23
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	1,276		1,270
Generation Midwest [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	1,275		1,258
Generation Midwest [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	1		12
Generation New England [Member]
Segment Reporting Information [Line Items]
Revenues	859		549
Generation New England [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	858		545
Generation New England [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	1		4
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	310		187
Generation New York [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	310		190
Generation New York [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0		-3
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	180		243
Generation ERCOT [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	182		243
Generation ERCOT [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-2		0
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	214		341
Generation Other Regions [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	212		334
Generation Other Regions [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	2		7
Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenues	4,352		4,008
Generation Reportable Segments Total [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	4,354	[4]	4,011	[4]
Generation Reportable Segments Total [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-2		-3
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	1,488		382
Generation All Other Segments [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	2		3	[5]
Generation All Other Segments [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Revenues	1,486		379	[4],[5]
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenues	5,840	[4]	4,390	[4]
Generation Total Consolidated Group [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0		0
Exelon Generation Co L L C [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	5,840	[1],[6]	4,390	[1],[6]
Revenue from Related Parties	210	[2],[6]	316	[2],[6]
Net income (loss)	485	[6]	-185	[6]
Commonwealth Edison Co Affiliate [Member] | Exelon Generation Co L L C [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenue from Related Parties	$9		$108
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NzEwQ0VGNzJGQTI1RkM2RDgzOUMwOTNBRjYwNUU2MTQM}
[3]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246QzVGNDk1MTM4RDRDN0NDQjA5MkUwOTNBRjYwNUZCMzMM}
[4]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246MzJCOTc5NTI3RTkyMDA2QTkzQzgwOTNBRjYwNURBRkYM}
[5]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246OTk0RkYxNzA5QzkxOUUyRDM3MDcwOTNBRjYwNTNEMDUM}
[6]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NTk4QTIxQTlGRTU5OTQxMkFDM0QwOTNBRjYwNTMyMDIM}

Segment_Information_Generation1

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015		Mar. 31, 2014
Segment Reporting Information [Line Items]
Revenues	$8,830	[1]	$7,237	[1]
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Revenues	5,840		4,390
Amortization of Intangible Assets	-40		93
Unrealized Gain (Loss) on Commodity Contracts	154		-760
Sales Revenue, Goods, Net [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Amortization of Intangible Assets	-38		42
Unrealized Gain (Loss) on Commodity Contracts	162		-730
Exelon Generation Co L L C [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
Revenues	5,840	[1],[2]	4,390	[1],[2]
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenues	1,513		1,418
Generation Mid Atlantic [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	784	[3]	784	[3]
Intersegment RNF	-2		-89
Revenues	1,517		1,441
Generation Mid Atlantic [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-4		-23
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues	1,276		1,270
Generation Midwest [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	701	[3]	530	[3]
Intersegment RNF	-1		26
Revenues	1,275		1,258
Generation Midwest [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	1		12
Generation New England [Member]
Segment Reporting Information [Line Items]
Revenues	859		549
Generation New England [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	177	[3]	154	[3]
Intersegment RNF	-19		-18
Revenues	858		545
Generation New England [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	1		4
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenues	310		187
Generation New York [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	174	[3]	-29	[3]
Intersegment RNF	14		8
Revenues	310		190
Generation New York [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	0		-3
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenues	180		243
Generation ERCOT [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	88	[3]	155	[3]
Intersegment RNF	-33		-72
Revenues	182		243
Generation ERCOT [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	-2		0
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenues	214		341
Generation Other Regions [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	99	[3]	150	[3]
Intersegment RNF	-53		-45
Revenues	212		334
Generation Other Regions [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	2		7
Other Segments [Member]
Segment Reporting Information [Line Items]
Intersegment RNF	-94		-190
Segment Reporting Information Revenue Net of Purchase Power And Fuel	1,929		1,554
Other Segments [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	2,023	[3]	1,744	[3]
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Intersegment RNF	0		0
Segment Reporting Information Revenue Net of Purchase Power And Fuel	2,407		1,033
Revenues	1,488		382
Generation All Other Segments [Member] | Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	384	[3],[4]	-711	[3],[4]
Generation All Other Segments [Member] | Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues	2		3	[5]
Operating Segments [Member]
Segment Reporting Information [Line Items]
RNF from external customers	2,407	[3]	1,033	[3]
Operating Segments [Member] | Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	782		695
Operating Segments [Member] | Generation Midwest [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	700		556
Operating Segments [Member] | Generation New England [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	158		136
Operating Segments [Member] | Generation New York [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	188		-21
Operating Segments [Member] | Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	55		83
Operating Segments [Member] | Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	46		105
Operating Segments [Member] | Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Intersegment RNF	94	[4]	190	[4]
Segment Reporting Information Revenue Net of Purchase Power And Fuel	$478	[4]	($521)	[4]
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246M0JGQzRCODYwOEI3OTJGM0VFMzEwOTNBRjYwNTk1MjUM}
[2]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246NTk4QTIxQTlGRTU5OTQxMkFDM0QwOTNBRjYwNTMyMDIM}
[3]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246Q0RERTFCQ0ZEQ0Q4RDUzODhGMzgwOTNBRjYwNTUwNjUM}
[4]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246RjVDRTNBRkM4RTlCRjRDQzYwOEUwOTNBRjYwNTg5MUYM}
[5]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmVmN2Y3ZjVlMDU4YzQwMGVhOTA4ZWJkNWMzOGFmYjNhfFRleHRTZWxlY3Rpb246OTk0RkYxNzA5QzkxOUUyRDM3MDcwOTNBRjYwNTNEMDUM}