Exelon (EXC) 10-K 13 Feb 15 2014 FY Annual report Financial data

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
	Dec. 31, 2014	Jan. 31, 2015
Entity Registrant Name	EXELON CORP
Entity Central Index Key	1109357
Document Type	10-K
Document Period End Date	31-Dec-14
Amendment Flag	FALSE
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
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		859,833,343
Entity Public Float	$31,319,710,373
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		127,016,950
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 $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating revenues [Abstract]
Revenues	$27,429	[1]	$24,888	[1]	$23,489	[1]
Operating revenues from affiliates	23		70		48
Operating expenses
Purchased power and fuel	12,472		9,468		9,121
Purchased power and fuel from affiliates	531		1,256		1,036
Operating and maintenance	8,568		7,270		7,961
Depreciation and amortization	2,314		2,153		1,881
Taxes other than income	1,154		1,095		1,019
Total operating expenses	25,039		21,242		21,018
Equity in (losses) earnings of unconsolidated affiliates	-20		10		-91
Gain (loss) on sales of assets	437		13		-7
Gain on consolidation and acquisition of businesses	289		0		0
Operating Income (Loss)	3,096		3,669		2,373
Other income and (deductions)
Interest expense, net	-1,024		-1,315		-891
Interest expense to affiliates, net	-41		-41		-37
Other, net	455		460		353
Total other income and (deductions)	-610		-896		-575
Income before income taxes	2,486		2,773		1,798
Income before income taxes	2,486		2,773		1,798
Income taxes	666		1,044		627
Net income	1,820		1,729		1,171
Net income attributable to noncontrolling interest, preferred security dividends and preference stock dividends	-197		-10		-11
Net income attributable to common shareholders	1,623		1,719		1,160
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost, net of tax	-30		0		1
Actuarial loss reclassified to periodic cost, net of tax	147		208		168
Transition obligation reclassified to periodic cost, net of tax	0		0		2
Pension and non-pension postretirement benefit plans valuation adjustment, net of tax	-497		669		-371
Unrealized gain (loss) on cash flow hedges, net of taxes	-148		-248		-120
Unrealized gain (loss) on marketable securities, net of taxes	1		2		2
Unrealized gain (loss) on equity investments, net of taxes	8		106		1
Unrealized gain (loss) on foreign currency translation, net of taxes	-9		-10		0
Reversal of CENG equity method AOCI, net of taxes	-116		0		0
Other comprehensive income (loss)	-644		727	[2]	-317
Comprehensive income	1,176		2,456		854
Average shares of common stock outstanding:
Basic	860		856		816
Diluted	864		860		819
Earnings per average common share:
Basic (in usd per share)	$1.89		$2.01		$1.42
Diluted (in usd per share)	$1.88		$2		$1.42
Dividends per common share (in usd per share)	$1.24		$1.46		$2.10
Exelon Generation Co L L C [Member]
Operating revenues [Abstract]
Revenues	17,393		15,630		14,437
Operating revenues	16,614		14,207		12,735
Operating revenues from affiliates	779		1,423		1,702
Operating expenses
Purchased power and fuel	9,368		6,927		6,017
Purchased power and fuel from affiliates	557		1,270		1,044
Operating and maintenance	4,943		3,960		4,398
Operating and maintenance from affiliates	623		574		630
Depreciation and amortization	967		856		768
Taxes other than income	465		389		369
Total operating expenses	16,923		13,976		13,226
Equity in (losses) earnings of unconsolidated affiliates	-20		10		-91
Gain (loss) on sales of assets	437		13		-7
Gain on consolidation and acquisition of businesses	289		0		0
Operating Income (Loss)	1,176		1,677		1,113
Other income and (deductions)
Interest expense, net	-303		-298		-226
Interest expense to affiliates, net	-53		-59		-75
Other, net	406		355		246
Total other income and (deductions)	50		-2		-55
Income before income taxes	1,226		1,675		1,058
Income taxes	207		615		500
Net income	1,019		1,060		558
Net income (loss) attributable to noncontrolling interests	184		-10		-4
Net income attributable to membership interest	835		1,070		562
Pension and non-pension postretirement benefit plans:
Unrealized gain (loss) on cash flow hedges, net of taxes	-132		-398		-403
Unrealized gain (loss) on marketable securities, net of taxes	-1		2		0
Unrealized gain (loss) on equity investments, net of taxes	8		107		1
Unrealized gain (loss) on foreign currency translation, net of taxes	-9		-10		0
Reversal of CENG equity method AOCI, net of taxes	-116		0		0
Other comprehensive income (loss)	-250		-299	[2]	-402
Comprehensive income	769		761		156
Commonwealth Edison Co [Member]
Operating revenues [Abstract]
Revenues	4,564		4,464		5,443
Operating revenues	4,560		4,461		5,441
Operating revenues from affiliates	4		3		2
Operating expenses
Purchased power and fuel	1,001		662		1,518
Purchased power from affiliate	176		512		789
Operating and maintenance	1,263		1,211		1,182
Operating and maintenance from affiliates	166		157		163
Depreciation and amortization	687		669		610
Taxes other than income	293		299		295
Total operating expenses	3,586		3,510		4,557
Equity in (losses) earnings of unconsolidated affiliates	0		0
Gain (loss) on sales of assets	2		0		0
Operating Income (Loss)	980		954		886
Other income and (deductions)
Interest expense, net	-308		-566		-294
Interest expense to affiliates, net	-13		-13		-13
Other, net	17		26		39
Total other income and (deductions)	-304		-553		-268
Income before income taxes	676		401		618
Income taxes	268		152		239
Net income	408		249		379
Pension and non-pension postretirement benefit plans:
Unrealized gain (loss) on marketable securities, net of taxes	0		0		1
Other comprehensive income (loss)	0		0		1
Comprehensive income	408		249		380
PECO Energy Co [Member]
Operating revenues [Abstract]
Revenues	3,094		3,100		3,186
Operating revenues	3,092		3,099		3,183
Operating revenues from affiliates	2		1		3
Operating expenses
Purchased power and fuel	1,067		908		842
Purchased power from affiliate	194		392		533
Operating and maintenance	767		647		698
Operating and maintenance from affiliates	99		101		111
Depreciation and amortization	236		228		217
Taxes other than income	159		158		162
Total operating expenses	2,522		2,434		2,563
Equity in (losses) earnings of unconsolidated affiliates	0		0		0
Operating Income (Loss)	572		666		623
Other income and (deductions)
Interest expense, net	-101		-103		-111
Interest expense to affiliates, net	-12		-12		-12
Other, net	7		6		8
Total other income and (deductions)	-106		-109		-115
Income before income taxes	466		557		508
Income taxes	114		162		127
Net income	352		395		381
Preferred security dividends and redemption	0		-7		-4
Net income attributable to common shareholders	352		388		377
Pension and non-pension postretirement benefit plans:
Unrealized gain (loss) on marketable securities, net of taxes	0		0		1
Other comprehensive income (loss)	0		0		1
Comprehensive income	352		395		382
Baltimore Gas and Electric Company [Member]
Operating revenues [Abstract]
Revenues	3,165		3,065		2,735
Operating revenues	3,140		3,052		2,725
Operating revenues from affiliates	25		13		10
Operating expenses
Purchased power and fuel	1,035		969		973
Purchased power from affiliate	382		452		396
Operating and maintenance	614		551		622
Operating and maintenance from affiliates	103		83		106
Depreciation and amortization	371		348		298
Taxes other than income	221		213		208
Total operating expenses	2,726		2,616		2,603
Equity in (losses) earnings of unconsolidated affiliates	0		0		0
Operating Income (Loss)	439		449		132
Other income and (deductions)
Interest expense, net	-90		-106		-128
Interest expense to affiliates, net	-16		-16		-16
Other, net	18		17		23
Total other income and (deductions)	-88		-105		-121
Income before income taxes	351		344		11
Income taxes	140		134		7
Net income	211		210		4
Preferred security dividends and redemption	-13		-13		-13
Net income attributable to common shareholders	198		197		-9
Pension and non-pension postretirement benefit plans:
Comprehensive income	$211		$210		$4
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Consolidated_Statements_of_Ope1

Consolidated Statements of Operations and Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax			$1
Commonwealth Edison Co [Member]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	0	0	0
PECO Energy Co [Member]
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax	$0	$0	$0

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (Unaudited) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Cash flows from operating activities
Net income	$1,820	$1,729	$1,171
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	3,868	3,779	4,079
Impairment of long-lived assets	687	171	284
Gain on consolidation and acquisition of businesses	-296	0	0
(Gain) loss on sales of assets	-437	-13	7
(Gain) loss on sales of assets	-437	-13	7
Deferred income taxes and amortization of investment tax credits	502	119	615
Net fair value changes related to derivatives	716	-445	-604
Net realized and unrealized gains on nuclear decommissioning trust fund investments	-210	-170	-157
Other non-cash operating activities	1,054	718	1,364
Changes in assets and liabilities:
Accounts receivable	-318	-97	243
Inventories	-380	-100	26
Accounts payable, accrued expenses and other current liabilities	209	-90	-632
Option premiums received (paid), net	38	-36	-114
Counterparty collateral (posted) received, net	-1,478	215	135
Income taxes	-143	883	544
Pension and non-pension postretirement benefit contributions	-617	-422	-462
Other assets and liabilities	-558	102	-368
Net cash flows provided by operating activities	4,457	6,343	6,131
Cash flows from investing activities
Capital expenditures	-6,077	-5,395	-5,789
Proceeds from termination of direct financing lease investment	335	0	0
Proceeds from nuclear decommissioning trust fund sales	7,396	4,217	7,265
Investment in nuclear decommissioning trust funds	-7,551	-4,450	-7,483
Acquisitions of businesses	-386	0	-21
Proceeds from sales of long-lived assets	1,719	32	371
Proceeds from sales of investments	7	22	28
Cash and restricted cash acquired from consolidations and acquisitions	140	0	964
Purchases of investments	-3	-4	-13
Change in restricted cash	-104	-43	-34
Distribution from CENG	13	115	0
Other investing activities	-88	112	136
Net cash flows used in investing activities	-4,599	-5,394	-4,576
Cash flows from financing activities
Payment of accounts receivable agreement	0	-210	-15
Changes in short-term borrowings	122	332	-197
Issuance of long-term debt	3,463	2,055	2,027
Retirement of long-term debt	-1,545	-1,589	-1,145
Redemption of preferred securities	0	-93	0
Distribution to noncontrolling interest of consolidated VIE	-421	0	0
Dividends paid on common stock	-1,065	-1,249	-1,716
Proceeds from employee stock plans	35	47	72
Other financing activities	-178	-119	-111
Net cash flows provided by (used in) financing activities	411	-826	-1,085
Increase in cash and cash equivalents	269	123	470
Cash and cash equivalents at beginning of period	1,609	1,486	1,016
Cash and cash equivalents at end of period	1,878	1,609	1,486
Exelon Generation Co L L C [Member]
Cash flows from operating activities
Net income	1,019	1,060	558
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, depletion and accretion, including nuclear fuel and energy contract amortization	2,519	2,559	2,966
Impairment of long-lived assets	663	157	284
Gain on consolidation and acquisition of businesses	-296	0	0
(Gain) loss on sales of assets	-437	-13	7
Deferred income taxes and amortization of investment tax credits	-198	315	408
Net fair value changes related to derivatives	635	-448	-611
Net realized and unrealized gains on nuclear decommissioning trust fund investments	-210	-170	-157
Other non-cash operating activities	346	270	518
Changes in assets and liabilities:
Accounts receivable	-215	109	248
Receivables from and payables to affiliates, net	15	2	39
Inventories	-359	-88	31
Accounts payable, accrued expenses and other current liabilities	94	-109	-499
Option premiums received (paid), net	38	-36	-114
Counterparty collateral (posted) received, net	-1,507	162	95
Income taxes	265	402	114
Pension and non-pension postretirement benefit contributions	-297	-149	-178
Other assets and liabilities	-249	-136	-128
Net cash flows provided by operating activities	1,826	3,887	3,581
Cash flows from investing activities
Capital expenditures	-3,012	-2,752	-3,554
Proceeds from nuclear decommissioning trust fund sales	7,396	4,217	7,265
Investment in nuclear decommissioning trust funds	-7,551	-4,450	-7,483
Acquisitions of businesses	-386	0	-21
Proceeds from sales of long-lived assets	1,719	32	371
Cash and restricted cash acquired from consolidations and acquisitions	140	0	708
Change in restricted cash	-87	-64	4
Distribution from CENG	13	115	0
Other investing activities	-43	30	81
Changes in Exelon intercompany money pool	44	-44	0
Net cash flows used in investing activities	-1,767	-2,916	-2,629
Cash flows from financing activities
Changes in short-term borrowings	17	13	-52
Issuance of long-term debt	1,112	854	1,076
Retirement of long-term debt	-586	-570	-145
Distribution to noncontrolling interest of consolidated VIE	-421	0	0
Other financing activities	-67	-82	-78
Distribution to member	-645	-625	-1,626
Contribution from member	53	26	48
Net cash flows provided by (used in) financing activities	-537	-384	-777
Increase in cash and cash equivalents	-478	587	175
Cash and cash equivalents at beginning of period	1,258	671	496
Cash and cash equivalents at end of period	780	1,258	671
Commonwealth Edison Co [Member]
Cash flows from operating activities
Net income	408	249	379
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	687	669	610
(Gain) loss on sales of assets	-2	0	0
Deferred income taxes and amortization of investment tax credits	433	-57	270
Other non-cash operating activities	255	28	252
Changes in assets and liabilities:
Accounts receivable	-121	-12	24
Receivables from and payables to affiliates, net	-11	-12	-18
Inventories	-16	-18	-11
Accounts payable, accrued expenses and other current liabilities	53	74	59
Income taxes	-159	178	9
Pension and non-pension postretirement benefit contributions	-248	-122	-138
Other assets and liabilities	45	241	-102
Net cash flows provided by operating activities	1,326	1,218	1,334
Cash flows from investing activities
Capital expenditures	-1,689	-1,433	-1,246
Proceeds from sales of investments	7	7	28
Purchases of investments	-3	-4	-13
Change in restricted cash	-2	-2	0
Other investing activities	32	45	19
Net cash flows used in investing activities	-1,655	-1,387	-1,212
Cash flows from financing activities
Changes in short-term borrowings	120	184	0
Issuance of long-term debt	900	350	350
Retirement of long-term debt	-617	-252	-450
Dividends paid on common stock	-307	-220	-105
Other financing activities	-10	-1	-7
Contributions from parent	273	0	0
Net cash flows provided by (used in) financing activities	359	61	-212
Increase in cash and cash equivalents	30	-108	-90
Cash and cash equivalents at beginning of period	36	144	234
Cash and cash equivalents at end of period	66	36	144
PECO Energy Co [Member]
Cash flows from operating activities
Net income	352	395	381
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	236	228	217
Deferred income taxes and amortization of investment tax credits	88	20	37
Other non-cash operating activities	92	108	125
Changes in assets and liabilities:
Accounts receivable	-16	-79	-14
Receivables from and payables to affiliates, net	-6	-18	13
Inventories	2	2	21
Accounts payable, accrued expenses and other current liabilities	54	41	-47
Income taxes	-57	87	174
Pension and non-pension postretirement benefit contributions	-16	-31	-45
Other assets and liabilities	-17	-6	16
Net cash flows provided by operating activities	712	747	878
Cash flows from investing activities
Capital expenditures	-661	-537	-422
Change in restricted cash	0	-2	2
Other investing activities	12	8	10
Changes in Exelon intercompany money pool	0	0	82
Net cash flows used in investing activities	-649	-531	-328
Cash flows from financing activities
Changes in short-term borrowings	0	-210	-15
Issuance of long-term debt	300	550	350
Retirement of long-term debt	-250	-300	-375
Redemption of preferred securities	0	-93	0
Dividends paid on common stock	-320	-332	-343
Other financing activities	-4	-2	-4
Contributions from parent	24	27	9
Dividends paid on preferred securities	0	-1	-4
Net cash flows provided by (used in) financing activities	-250	-361	-382
Increase in cash and cash equivalents	-187	-145	168
Cash and cash equivalents at beginning of period	217	362	194
Cash and cash equivalents at end of period	30	217	362
Baltimore Gas and Electric Company [Member]
Cash flows from operating activities
Net income	211	210	4
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	371	348	298
Deferred income taxes and amortization of investment tax credits	116	125	104
Other non-cash operating activities	180	153	193
Changes in assets and liabilities:
Accounts receivable	46	-127	-45
Receivables from and payables to affiliates, net	-1	-14	26
Inventories	-6	1	25
Accounts payable, accrued expenses and other current liabilities	-70	-14	-33
Counterparty collateral (posted) received, net	27	0	0
Income taxes	45	-33	14
Pension and non-pension postretirement benefit contributions	-16	-24	-16
Other assets and liabilities	-163	-64	-85
Net cash flows provided by operating activities	740	561	485
Cash flows from investing activities
Capital expenditures	-620	-587	-582
Change in restricted cash	-22	2	0
Other investing activities	20	14	9
Net cash flows used in investing activities	-622	-571	-573
Cash flows from financing activities
Changes in short-term borrowings	-15	135	0
Issuance of long-term debt	0	300	250
Retirement of long-term debt	-70	-467	-173
Other financing activities	13	-3	-2
Contributions from parent	0	0	66
Dividends paid on preferred securities	-13	-13	-13
Net cash flows provided by (used in) financing activities	-85	-48	128
Increase in cash and cash equivalents	33	-58	40
Cash and cash equivalents at beginning of period	31	89	49
Cash and cash equivalents at end of period	$64	$31	$89

Consolidated_Balance_Sheets_Un

Consolidated Balance Sheets (Unaudited) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Current assets
Cash and cash equivalents	$1,878		$1,609
Cash and cash equivalents	1,878		1,609
Restricted cash and cash equivalents	271		167
Accounts receivable, net
Customer	3,482		2,981
Other	1,227		1,175
Mark-to-market derivative assets	1,279		727
Unamortized energy contract assets	254		374
Inventories, net
Fossil fuel	579		276
Materials and supplies	1,024		829
Deferred income taxes	244		573
Regulatory assets	847		760
Assets held for sale	147		14
Other	865		652
Total current assets	12,097		10,137
Property, plant and equipment, net	52,087		47,330
Deferred debits and other assets
Regulatory assets	6,076		5,910
Nuclear decommissioning trust funds	10,537		8,071
Investments	544		1,187
Investment in CENG	0		1,925
Goodwill	2,672		2,625
Mark-to-market derivative assets	773		607
Unamortized energy contract assets	549		710
Pledged assets for Zion Station decommissioning	319		458
Other	1,160		964
Total deferred debits and other assets	22,630		22,457
Total assets	86,814	[1]	79,924	[1]
Current liabilities
Short-term borrowings	460		341
Long-term debt due within one year	1,802		1,509
Accounts payable	3,048		2,484
Accrued expenses	1,539		1,633
Payables to affiliates	8		116
Mark-to-market derivative liabilities	234		159
Unamortized energy contract liabilities	238		261
Deferred income taxes	0		40
Regulatory liabilities	310		327
Other	1,123		858
Total current liabilities	8,762		7,728
Long-term debt	19,362		17,623
Long-term debt to financing trusts	648		648
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	13,019		12,905
Asset retirement obligations	7,295		5,194
Pension obligations	3,366		1,876
Non-pension postretirement benefit obligations	1,742		2,190
Spent nuclear fuel obligation	1,021		1,021
Regulatory liabilities	4,550		4,388
Mark-to-market derivative liabilities	403		300
Unamortized energy contract liabilities	211		266
Payable for Zion Station decommissioning	155		305
Other	2,147		2,540
Total deferred credits and other liabilities	33,909		30,985
Total liabilities	62,681	[1]	56,984	[1]
Shareholders’ equity
Common stock	16,709		16,741
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013)	-2,327		-2,327
Retained earnings	10,910		10,358
Accumulated other comprehensive loss, net	-2,684		-2,040	[2]
Total shareholders’ equity	22,608		22,732
BGE preference stock not subject to mandatory redemption	193		193
Noncontrolling interest	1,332		15
Total equity	24,133		22,940
Total liabilities and shareholders’ equity	86,814		79,924
Member’s equity
Accumulated other comprehensive loss, net	-2,684		-2,040	[2]
Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]
Deferred debits and other assets
Total assets	8,160		1,755
Deferred credits and other liabilities
Total liabilities	2,723		658
Exelon Generation Co L L C [Member]
Current assets
Cash and cash equivalents	780		1,258
Cash and cash equivalents	780		1,258
Restricted cash and cash equivalents	158		71
Accounts receivable, net
Customer	2,295		1,689
Other	318		353
Mark-to-market derivative assets	1,276		727
Receivables from affiliates	113		108
Unamortized energy contract assets	254		374
Inventories, net
Fossil fuel	465		164
Materials and supplies	847		671
Deferred income taxes	327		475
Receivable from Exelon intercompany money pool	0		44
Regulatory assets	147		14
Other	658		491
Total current assets	7,638		6,439
Property, plant and equipment, net	22,945		20,111
Deferred debits and other assets
Nuclear decommissioning trust funds	10,537		8,071
Investments	104		400
Investment in CENG	0		1,925
Goodwill	47		0
Mark-to-market derivative assets	771		600
Prepaid pension asset	1,704		1,873
Unamortized energy contract assets	549		710
Deferred income taxes	3
Pledged assets for Zion Station decommissioning	319		458
Other	731		645
Total deferred debits and other assets	14,765		14,682
Total assets	45,348	[3]	41,232	[3]
Current liabilities
Short-term borrowings	36		22
Long-term debt due within one year	58		561
Long-term debt to affiliates due within one year	556		0
Accounts payable	1,759		1,322
Accrued expenses	886		976
Payables to affiliates	107		181
Mark-to-market derivative liabilities	214		142
Unamortized energy contract liabilities	238		249
Deferred income taxes	0		25
Other	605		389
Total current liabilities	4,459		3,867
Long-term debt	6,709		5,645
Long-term debt to financing trusts	943		1,523
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	6,034		6,295
Asset retirement obligations	7,146		5,047
Non-pension postretirement benefit obligations	915		850
Spent nuclear fuel obligation	1,021		1,021
Payables to affiliates	2,880		2,740
Mark-to-market derivative liabilities	105		120
Unamortized energy contract liabilities	211		266
Payable for Zion Station decommissioning	155		305
Other	719		811
Total deferred credits and other liabilities	19,186		17,455
Total liabilities	31,297	[3]	28,490	[3]
Shareholders’ equity
Accumulated other comprehensive loss, net	-36		214	[2]
Noncontrolling interest	1,333		17
Member’s equity
Membership interest	8,951		8,898
Undistributed earnings	3,803		3,613
Accumulated other comprehensive loss, net	-36		214	[2]
Total member’s equity	12,718		12,725
Total equity	14,051		12,742
Total liabilities and equity	45,348		41,232
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]
Deferred debits and other assets
Total assets	8,119		1,695
Deferred credits and other liabilities
Total liabilities	2,507		362
Commonwealth Edison Co [Member]
Current assets
Cash and cash equivalents	66		36
Restricted cash and cash equivalents	4		2
Accounts receivable, net
Customer	477		451
Other	648		581
Receivables from affiliates	14		3
Inventories, net
Inventories, net	125		109
Regulatory assets	349		329
Other	40		29
Total current assets	1,723		1,540
Property, plant and equipment, net	15,793		14,666
Deferred debits and other assets
Regulatory assets	852		933
Investments	6		11
Goodwill	2,625		2,625
Receivable from affiliates	2,571		2,469
Prepaid pension asset	1,551		1,583
Other	271		291
Total deferred debits and other assets	7,876		7,912
Total assets	25,392		24,118
Current liabilities
Short-term borrowings	304		184
Long-term debt due within one year	260		617
Accounts payable	598		449
Accrued expenses	331		307
Payables to affiliates	84		83
Mark-to-market derivative liabilities	20		17
Deferred income taxes	63		16
Customer deposits	128		133
Regulatory liabilities	125		170
Other	73		72
Total current liabilities	1,986		2,048
Long-term debt	5,698		5,058
Long-term debt to financing trusts	206		206
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	4,498		4,116
Asset retirement obligations	103		99
Non-pension postretirement benefit obligations	263		381
Regulatory liabilities	3,655		3,512
Mark-to-market derivative liabilities	187		176
Other	889		994
Total deferred credits and other liabilities	9,595		9,278
Total liabilities	17,485		16,590
Shareholders’ equity
Common stock	1,588		1,588
Other paid-in capital	5,468		5,190
Retained earnings	851		750
Total shareholders’ equity	7,907		7,528
Total liabilities and shareholders’ equity	25,392		24,118
PECO Energy Co [Member]
Current assets
Cash and cash equivalents	30		217
Restricted cash and cash equivalents	2		2
Accounts receivable, net
Customer	320		360
Other	141		104
Receivables from affiliates	3		3
Inventories, net
Fossil fuel	57		60
Materials and supplies	22		21
Deferred income taxes	69		83
Prepaid utility taxes	10		3
Regulatory assets	29		17
Other	31		36
Total current assets	714		906
Property, plant and equipment, net	6,801		6,384
Deferred debits and other assets
Regulatory assets	1,529		1,448
Investments	31		31
Receivable from affiliates	490		447
Prepaid pension asset	344		363
Other	34		38
Total deferred debits and other assets	2,428		2,327
Total assets	9,943		9,617
Current liabilities
Long-term debt due within one year	0		250
Accounts payable	337		285
Accrued expenses	91		106
Payables to affiliates	52		58
Customer deposits	52		49
Regulatory liabilities	90		106
Other	31		37
Total current liabilities	653		891
Long-term debt	2,246		1,947
Long-term debt to financing trusts	184	[4]	184	[4]
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	2,671		2,487
Asset retirement obligations	29		29
Non-pension postretirement benefit obligations	287		286
Regulatory liabilities	657		629
Mark-to-market derivative liabilities	14
Other	95		99
Total deferred credits and other liabilities	3,739		3,530
Total liabilities	6,822		6,552
Shareholders’ equity
Common stock	2,439		2,415
Retained earnings	681		649
Accumulated other comprehensive loss, net	1		1	[2]
Total shareholders’ equity	3,121		3,065
Total liabilities and shareholders’ equity	9,943		9,617
Member’s equity
Accumulated other comprehensive loss, net	1		1	[2]
Baltimore Gas and Electric Company [Member]
Current assets
Cash and cash equivalents	64		31
Restricted cash and cash equivalents	50		28
Accounts receivable, net
Customer	390		480
Other	82		114
Income taxes receivable	0		30
Inventories, net
Fossil fuel	57		53
Materials and supplies	30		28
Deferred income taxes	6		2
Prepaid utility taxes	59		57
Regulatory assets	214		181
Other	5		7
Total current assets	957		1,011
Property, plant and equipment, net	6,204		5,864
Deferred debits and other assets
Regulatory assets	510		524
Investments	12		13
Prepaid pension asset	370		423
Other	25		26
Total deferred debits and other assets	917		986
Total assets	8,078	[5]	7,861	[5]
Current liabilities
Short-term borrowings	120		135
Long-term debt to affiliates due within one year	75		70
Accounts payable	215		270
Accrued expenses	131		111
Payables to affiliates	66		55
Deferred income taxes	52		27
Customer deposits	92		76
Regulatory liabilities	44		48
Other	51		35
Total current liabilities	846		827
Long-term debt	1,867		1,941
Long-term debt to financing trusts	258		258
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits	1,865		1,773
Asset retirement obligations	17		19
Non-pension postretirement benefit obligations	212		217
Regulatory liabilities	200		204
Other	60		67
Total deferred credits and other liabilities	2,354		2,280
Total liabilities	5,325	[5]	5,306	[5]
Shareholders’ equity
Common stock	1,360		1,360
Retained earnings	1,203		1,005
Total shareholders’ equity	2,563		2,365
BGE preference stock not subject to mandatory redemption	190		190
Total equity	2,753		2,555
Total liabilities and shareholders’ equity	8,078		7,861
Baltimore Gas and Electric Company [Member] | Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]
Deferred debits and other assets
Total assets	24		31
Deferred credits and other liabilities
Total liabilities	197		269
Constellation Energy Group LLC [Member]
Deferred debits and other assets
Total assets	$189
[1]	Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[3]	Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[4]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[5]	BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

Consolidated_Balance_Sheets_Un1

Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Common stock, par value	$0	$0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	859,833,343	857,290,484
Treasury Stock, Shares held	35,000,000	35,000,000
Commonwealth Edison Co [Member]
Common stock, shares authorized	250,000,000
Common stock, shares outstanding	127,016,947	127,016,896
PECO Energy Co [Member]
Common stock, shares authorized	500,000,000
Common stock, shares outstanding	170,478,507	170,478,507
Baltimore Gas and Electric Company [Member]
Common stock, shares authorized	175,000,000
Common stock, shares outstanding	1,000	1,000

Consolidated_Statement_of_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]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]	PECO Energy 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]	Baltimore Gas and Electric Company [Member]
In Millions, except Share data in Thousands, unless otherwise specified											Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interest [Member]	Membership Interest [Member]	Undistributed Earnings [Member]		Common Stock [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Other Paid-In Capital [Member]	Retained Deficit Unappropriated [Member]	Retained Earnings Appropriated [Member]		Common Stock [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income (Loss) [Member]		Common Stock [Member]	Retained Earnings [Member]	Membership Interest [Member]	Preference Stock Not Subject To Mandatory Redemption [Member]
Beginning Balance at Dec. 31, 2011	$14,388		$9,107	($2,327)	$10,055	($2,450)	$3																		$2,301	$1,294	$817	$2,111	$190
Beginning Balance (in shares) at Dec. 31, 2011	698,112
Beginning Balance at Dec. 31, 2011									8,708		915	5	3,556	4,232
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,171				1,160		-3	14	558			-4		562	379				379		381		381		4		4	4
Long-term incentive plan activity, shares	2,432
Long-term incentive plan activity	126		126
Employee stock purchase plan issuances	26		26
Employee stock purchase plan issuances, shares	857
Common stock dividends	-1,322				-1,322										-105					-105	-343		-343
Common stock issuance Constellation merger, shares	188,124
Common stock issuance Constellation merger	7,365		7,365						5,264				5,264
Noncontrolling interest acquired	114		8				106
BGE preference stock acquired	193							193
Preferred and preference stock dividends	-14							-14													-4		-4		-13		-13	-13
Other comprehensive loss, net of income taxes	-317								-402		-402				1		1				1			1
Allocation of tax benefit from parent									48												9
Other comprehensive loss, net of income taxes	-317					-317
Distribution to member									-1,626					-1,626
Allocation of tax benefit from member									48				48
Noncontrolling interest acquired									115			107	8
Allocation of tax benefit from parent															11			11			9	9
Appropriation of retained earnings for future dividends																			-379	379
Contribution from parent																									66	66		66
Ending Balance at Dec. 31, 2012															7,323	1,588		5,014	-1,639	2,360	2,982	2,388	593	1
Ending Balance at Dec. 31, 2012	21,730		16,632	-2,327	9,893	-2,767	106	193																	2,358	1,360	808	2,168	190
Ending Balance (in shares) at Dec. 31, 2012	889,525
Ending Balance at Dec. 31, 2012									12,665		513	108	8,876	3,168
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	-4	[1]							-18						-81						121				77
Ending Balance at Mar. 31, 2013
Beginning Balance at Dec. 31, 2012	21,730		16,632	-2,327	9,893	-2,767	106	193																	2,358		808	2,168	190
Beginning Balance (in shares) at Dec. 31, 2012	889,525
Beginning Balance at Dec. 31, 2012									12,665		513	108	8,876	3,168
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,729				1,719		-10	20	1,060			-10		1,070	249				249		395		395		210		210	210
Long-term incentive plan activity, shares	1,445
Long-term incentive plan activity	81		81
Employee stock purchase plan issuances	28		28
Employee stock purchase plan issuances, shares	1,064
Common stock dividends	-1,254				-1,254										-220					-220	-332		-332
Common stock issuance Constellation merger									-19			-18	-1
Preferred and preference stock dividends	-14							-14													-1		-1		-13		-13	-13
Other comprehensive loss, net of income taxes	727	[2]							-299	[2]	-299				0						0
Consolidated VIE dividend to noncontrolling interest	-63						-63		-63			-63
Deconsolidation of VIE	-18						-18
Redemption of preferred securities	-6							-6
Acquisition of noncontrolling interest									-3				-3
Allocation of tax benefit from parent																					27	27
Other comprehensive loss, net of income taxes	727					727
Distribution to member									-625					-625
Allocation of tax benefit from member									26				26
Allocation of tax benefit from parent															176			176			-6		-6
Appropriation of retained earnings for future dividends																			-249	249
Ending Balance at Dec. 31, 2013	22,732														7,528	1,588	0	5,190	-1,639	2,389	3,065	2,415	649	1	2,365
Ending Balance at Dec. 31, 2013	22,940		16,741	-2,327	10,358	-2,040	15	193																	2,555	1,360	1,005	2,365	190
Ending Balance (in shares) at Dec. 31, 2013	892,034
Ending Balance at Dec. 31, 2013									12,742		214	17	8,898	3,613
Beginning Balance at Sep. 30, 2013
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	495								269						109						102				47
Ending Balance at Dec. 31, 2013	22,732														7,528	1,588	0				3,065			1	2,365
Ending Balance at Dec. 31, 2013	22,940			-2,327																					2,555	1,360			190
Ending Balance (in shares) at Dec. 31, 2013	892,034
Ending Balance at Dec. 31, 2013									12,742
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	90								-185						98						89				85
Ending Balance at Mar. 31, 2014
Beginning Balance at Dec. 31, 2013			16,741	-2,327																						1,360			190
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Tax benefit on stock compensation			-8
Ending Balance at Sep. 30, 2014
Beginning Balance at Dec. 31, 2013	22,940		16,741	-2,327	10,358	-2,040	15	193																	2,555	1,360	1,005	2,365	190
Beginning Balance (in shares) at Dec. 31, 2013	892,034
Beginning Balance at Dec. 31, 2013									12,742		214	17	8,898	3,613
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	1,820				1,623		184	13	1,019			184		835	408				408		352		352		211		211	211
Long-term incentive plan activity, shares	1,574
Long-term incentive plan activity	72		72
Employee stock purchase plan issuances	35		35
Employee stock purchase plan issuances, shares	960
Common stock dividends	-1,071				-1,071										-307					-307	-320		-320
Noncontrolling interest acquired	1,548						1,548
Preferred and preference stock dividends	-13							-13																	-13		-13	-13
Other comprehensive loss, net of income taxes	-644								-250						0						0
Consolidated VIE dividend to noncontrolling interest	-421						-421		1,548			1,548
Deconsolidation of VIE									-421			-421
Tax benefit on stock compensation	-8
Acquisition of noncontrolling interest	4		-2				6		5			5
Fair value of financing contract payments	-131		-131
Transfer of CENG pension and non-pension postretirement benefit obligations	2		2
Reversal of CENG equity method AOCI, net of income taxes	-116					-116
Other comprehensive loss, net of income taxes	-528					-528			-134		-134
Distribution to member									53				53
Allocation of tax benefit from member									-645					-645
Noncontrolling interest acquired									-116		-116
Allocation of tax benefit from parent															5			5			24	24
Appropriation of retained earnings for future dividends																			-408	408
Contribution from parent	273																	273
Ending Balance at Dec. 31, 2014	22,608														7,907	1,588	0	5,468	-1,639	2,490	3,121	2,439	681	1	2,563
Ending Balance at Dec. 31, 2014	24,133		16,709	-2,327	10,910	-2,684	1,332	193																	2,753	1,360	1,203	2,563	190
Ending Balance (in shares) at Dec. 31, 2014	894,568
Ending Balance at Dec. 31, 2014									14,051		-36	1,333	8,951	3,803
Beginning Balance at Sep. 30, 2014
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	18	[3]							-91						73						98				52
Ending Balance at Dec. 31, 2014	22,608														7,907	1,588	0				3,121			1	2,563
Ending Balance at Dec. 31, 2014	24,133			-2,327																					2,753	1,360			190
Ending Balance (in shares) at Dec. 31, 2014	894,568
Ending Balance at Dec. 31, 2014									$14,051
[1]	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
[2]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[3]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.

Consolidated_Statement_of_Chan1

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012
Other comprehensive income, income taxes	$192
Exelon Generation Co L L C [Member]
Other comprehensive income, income taxes	263
PECO Energy Co [Member]
Other comprehensive income, income taxes	0
Commonwealth Edison Co [Member]
Other comprehensive income, income taxes	$0

Significant_Accounting_Policie

Significant Accounting Policies

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

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

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

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

Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon’s principal subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (“Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation’s regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4 — Mergers, Acquisitions, and Dispositions for further information regarding the merger transaction.

On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation consolidated CENG’s financial position and results of operations into their businesses. Prior to April 1, 2014, Exelon and Generation accounted for CENG as an equity method investment. Refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC for further information regarding the integration transaction.

The energy generation business includes:

•

Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions.

The energy delivery businesses include:

•

ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.

•

PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.

•

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

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

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

Exelon did not apply push-down accounting to BGE and BGE continued to be subject to reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2014, 2013 and 2012 and the financial position as of December 31, 2014 and December 31, 2013. However, for Exelon’s consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2014.

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

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

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

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

ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of which ComEd owns 75% and an additional12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2014 and December 31, 2013, as equity.

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

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

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

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

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

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

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

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

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

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

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

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

Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As of the Constellation merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. As ComEd receives full cost recovery for energy procurement and related costs from retail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 3 — Regulatory Matters and Note 12 — Derivative Financial Instruments for further information.

Proprietary Trading Activities. Exelon and Generation account for Generation’s trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 12 — Derivative Financial Instruments for further information.

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

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

Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14 — Income Taxes for further information.

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

Exelon, Generation, ComEd, PECO and BGE collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s and BGE’s utility taxes that are presented on a gross basis.

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

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

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

Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2014 and 2013, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, as of December 31, 2014 and 2013, Generation’s restricted cash and cash equivalents primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which is required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2014 and 2013, ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2014 and 2013, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds and cash collateral held from suppliers.

Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2014 and 2013, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2014, Exelon, Generation, ComEd, PECO and BGE had investments in Rabbi trusts classified as noncurrent assets.

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

The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable aging, historical experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accounts on customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance for uncollectible accounts, which was consistent with ComEd and PECO, as described above. For additional information regarding the change in estimate, refer to Note 6 — Accounts Receivable.

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

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

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

•

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

•

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

•

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

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

•

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

•

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

See Note 2 — Variable Interest Entities for additional information.

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

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

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

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

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

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

All marketable securities are reported at fair value. Marketable securities held in the NDT funds, certain Generation Rabbi trust investments and BGE’s Rabbi trust investments are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on certain Generation Rabbi trust investments and BGE’s Rabbi trust investments are included in earnings at Exelon, Generation and BGE. Unrealized gains and losses, net of tax, for Generation’s, ComEd’s and PECO’s available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd’s and PECO’s available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 15 — Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 23 — Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities.

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

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

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

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

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

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

See Note 7 — Property, Plant and Equipment, Note 9 — Jointly Owned Electric and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment.

Nuclear Fuel (Exelon and Generation)

The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. On-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22 — Commitments and Contingencies for additional information regarding the SNF disposal fee.

Nuclear Outage Costs (Exelon and Generation)

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

New Site Development Costs (Exelon and Generation)

New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management’s determination that the project is economically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. At December 31, 2014 and 2013, there were not material capitalized development costs for projects not yet under construction included in Property, plant and equipment, net on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $13 million, $10 million and $4 million of costs were expensed by Exelon and Generation for the years ended December 31, 2014, 2013, and 2012, respectively. These costs primarily related to the possible development of new renewable energy projects.

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

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

Net unamortized software costs

Exelon (a)

Generation (a)

ComEd

PECO

BGE

December 31, 2014

$

596

$

193

$

133

$

84

$

163

December 31, 2013

479

129

101

71

155

Amortization of capitalized software costs

Exelon (a) (b)

Generation (a) (b)

ComEd

PECO

BGE (b)

2014

$

186

$

59

$

45

$

28

$

43

2013

198

67

52

33

36

2012

208

81

56

30

32

_______________________

(a)

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

(b)

Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.

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

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

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

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

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

See Note 3 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of ComEd’s, PECO’s and BGE’s regulatory assets.

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

The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income or, in the case of the majority of ComEd’s, PECO’s, and BGE’s accretion, through an increase to regulatory assets. See Note 15 — Asset Retirement Obligations for additional information.

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

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

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

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

Exelon(a)(b)

Generation(a)(b)

ComEd

PECO

BGE (b)

2014

Total incurred interest (c)

$

1,144

$

419

$

323

$

115

$

118

Capitalized interest

63

63

—

—

—

Credits to AFUDC debt and equity

37

—

5

8

24

2013

Total incurred interest (c)

$

1,423

$

411

$

584

$

117

$

129

Capitalized interest

54

54

—

—

—

Credits to AFUDC debt and equity

35

—

16

6

13

2012

Total incurred interest (c)

$

1,003

$

368

$

310

$

125

$

149

Capitalized interest

67

67

—

—

—

Credits to AFUDC debt and equity

25

—

9

6

15

_______________________

(a)

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

(b)

Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.

(c)

Includes interest expense to affiliates.

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

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

The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 22 — Commitments and Contingencies for additional information.

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

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

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

Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10 — Intangible Assets for additional information regarding Exelon’s, Generation's and ComEd’s goodwill.

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

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

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

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

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

As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12 — Derivative Financial Instruments for additional information.

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

Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. Effective July 14, 2014, Exelon became the sponsor of all of CENG's pension and other postretirement benefit plans.

The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 16 — Retirement Benefits for additional discussion of Exelon’s accounting for retirement benefits.

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

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

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

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

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

Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist

In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants’ results of operations or cash flows.

Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force)

In November 2014, the FASB issued authoritative guidance that allows acquired entities to apply pushdown accounting (i.e., reflecting the acquirer’s basis of accounting for the acquired entity’s assets and liabilities) when an acquirer obtains control of them. At the same time, the SEC rescinded its guidance on pushdown accounting. The SEC’s guidance had required pushdown accounting in certain circumstances, made it optional in others and prevented it in still other circumstances. The new guidance is effective immediately for any future transaction or to the most recent event in which an acquirer obtains or obtained control of the acquired entity. The adoption of the guidance had no impact to the financial statements of the Registrants; however, the Registrants will assess the potential impact of the guidance on future acquisitions.

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

Revenue from Contracts with Customers

In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new 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 is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016. Early adoption is not 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 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.

Variable_Interest_Entities_Exe

Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
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 December 31, 2014 and 2013, Exelon, Generation, and BGE collectively consolidated six and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary. As of December 31, 2014 and 2013, the Registrants had significant interests in six and eight 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
	The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial statements at December 31, 2014 and 2013 are as follows:
		31-Dec-14												31-Dec-13
		Exelon (a) (b)				Generation (b)				BGE				Exelon (a)				Generation				BGE
	Current assets	$	1,271			$	1,242			$	21			$	484			$	446			$	28
	Noncurrent assets	7,580				7,566				3				1,905				1,884				3
	Total assets	$	8,851			$	8,808			$	24			$	2,389			$	2,330			$	31
	Current liabilities	$	611			$	526			$	77			$	566			$	481			$	74
	Noncurrent liabilities	2,730				2,600				120				774				562				195
	Total liabilities	$	3,341			$	3,126			$	197			$	1,340			$	1,043			$	269
	_______________________
	(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
	(b)	Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information.
	Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the table can only be settled using VIE resources.
	Exelon, Generation and BGE's consolidated VIEs consist of:
	RSB BondCo LLC. In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that BGE deferred pursuant to Senate Bill 1. BGE has determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE consolidates BondCo.
	BondCo’s assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it receives from customers for rate stabilization charges to BondCo. During 2014, 2013, and 2012, BGE remitted $85 million, $83 million, and $85 million, respectively, to BondCo.
	BGE did not provide any additional financial support to BondCo during 2014. Further, BGE does not have any contractual commitments or obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest payments of BondCo.
	Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with its existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third-party gas supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is not sufficient equity to fund the group’s activities without the additional credit support that is provided in the form of a parental guarantee. Generation is the primary beneficiary of the retail gas entity group; accordingly, Generation consolidates the retail gas entity group as a VIE.
	The third-party gas supply arrangement is collateralized as follows:
	•	The assets of the retail gas entity group must be used to settle obligations under the third-party gas supply agreement before it can make any distributions to Generation,
	•	The third-party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and
	•	Generation provides a $75 million parental guarantee to the third-party gas supplier in support of the retail gas entity group.
	Other than credit support provided by the parental guarantee, Exelon or Generation do not have any contractual or other obligations to provide additional financial support under the collateralized third-party gas supply agreement. The third-party gas supply creditors do not have any recourse to Exelon’s or Generation’s general credit other than the parental guarantee.
	Solar Project Entity Group. In 2011, Constellation formed a group of solar project limited liability companies to build, own, and operate solar power facilities, which are now part of Generation. Additionally, on September 30, 2011, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley) from First Solar, Inc., a 242-MW solar PV project under construction in northern Los Angeles County, California. While Generation owns 100% of these entities, it has been determined that certain of the individual solar project entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the solar project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar power facilities. Generation provides operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to the Antelope Valley project. In addition, these solar VIE entities have an aggregate amount of outstanding debt with third parties of $642 million, as of December 31, 2014, for which the creditors have no recourse to Generation, however there is limited recourse to Generation with respect to remaining equity contributions necessary to complete the Antelope Valley project. For additional information on these project-specific financing arrangements refer to Note 13 — Debt and Credit Agreements.
	Retail Power Companies. In March 2014, Generation began consolidating retail power VIEs for which Generation is the primary beneficiary as a result of energy supply contracts that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity ownership interest in these entities, but provides approximately $5 million in credit support for the retail power companies. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs does not have a material impact on Generation’s financial results or financial condition.
	Wind Project Entity Group. Generation owns and operates a number of wind project limited liability entities, the majority of which were acquired on December 9, 2010 with the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has evaluated the significant agreements and ownership structures and the risks of each of its wind projects and underlying entities, and determined that certain of the entities are VIEs because either the projects have noncontrolling equity interest holders that absorb variability from the wind projects, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of the wind project entities that qualify as VIEs because Generation controls the design, construction, and operation of the wind generation facilities. While Generation owns 100% of the majority of the wind project entities, nine of the projects have noncontrolling equity interests of 1% held by third parties. Generation’s current economic interests in eight of these projects is significantly greater than its stated contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation is to provide financial support to the projects in proportion to its current 99% economic interests in the projects. However, no additional support to these projects beyond what was contractually required has been provided during 2014. As of December 31, 2014, the carrying amount of the assets and liabilities that are consolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relates to the wind generating assets, PPA intangible assets and working capital amounts.
	CENG. Through March 31, 2014, CENG was operated as a joint venture with EDF Inc. (EDFI) (a subsidiary of EDF) and was governed by a board of ten directors, five of which were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control of Generation and EDFI through the Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain special matters; therefore, CENG was not subject to VIE guidance. Accordingly, Generation’s 50.01% interest in CENG was accounted for as an equity method investment. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating Services Agreement (NOSA) pursuant to which Generation now conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI. As a result of executing the NOSA, CENG now qualifies as a VIE due to the disproportionate relationship between Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA. Further, since Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and, therefore, is required to consolidate the financial position and results of operations of CENG. On April 1, 2014, Exelon and Generation derecognized Generation’s equity method investment in CENG and reflected all assets, liabilities, and the EDFI noncontrolling interest in CENG at fair value on the consolidated balance sheets of Exelon and Generation, resulting in the recognition of a $261 million gain in their respective Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. For additional information on this transaction refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC.
	Generation and Exelon, where indicated, provide the following support to CENG (See Note 25 — Related Party Transactions and Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information regarding Generation and Exelon’s transactions with CENG):
	•	under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDFI,
	•	under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the CENG fleet for the remaining operating life of the CENG nuclear plants,
	•	under power purchase agreements with CENG, Generation purchased 85% of the available output generated by the CENG nuclear plants through the end of 2014 and will purchase 50.01% from 2015 through the end of the operating life of each respective plant,
	•	Generation provided a $400 million loan to CENG (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC for more details),
	•	Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF 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 22 — 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 from 2013 through 2016. As of December 31, 2014, the remaining obligation is approximately $3 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 22 — 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 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 22 — Commitments and Contingencies for more details), and
	•	Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
	For each of the consolidated VIEs, except as otherwise noted:
	•	The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
	•	Exelon, Generation and BGE did not provide any additional material financial support to the VIEs;
	•	Exelon, Generation and BGE did not have any material contractual commitments or obligations to provide financial support to the VIEs; and
	•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s or BGE’s general credit.
	As of December 31, 2014 and 2013, ComEd and PECO did not have any material consolidated VIEs.
	Assets and Liabilities of Consolidated VIEs
	Included within the consolidated VIE table above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of December 31, 2014 and 2013, these assets and liabilities primarily consisted of the following:
			December 31, 2014												December 31, 2013
			Exelon				Generation				BGE					Exelon				Generation				BGE
	Cash and cash equivalents			$	392			$	392			$	—			$	62			$	62			$	—
	Restricted cash			117				96				21				80				52				28
	Accounts receivable, net
		Customer		297				297				—				260				260				—
		Other		57				57				—				—				—				—
	Mark-to-market derivatives assets			171				171				—				21				21				—
	Inventory
		Materials and supplies		172				172				—				—				—				—
	Other current assets			33				26				—				34				23				—
		Total current assets		1,239				1,211				21				457				418				28
	Property, plant and equipment, net			4,638				4,638				—				1,171				1,171				—
	Nuclear decommissioning trust funds			2,097				2,097				—				—				—				—
Goodwill			47				47				—				—				—				—
Mark-to-market derivatives assets			44				44				—				—				—				—
Other noncurrent assets			95				82				3				127				106				3
	Total noncurrent assets		6,921				6,908				3				1,298				1,277				3
	Total assets		$	8,160			$	8,119			$	24			$	1,755			$	1,695			$	31
Long-term debt due within one year			$	87			$	5			$	75			$	85			$	5			$	70
Accounts payable			292				292				—				170				170				—
Accrued expenses			111				108				2				26				22				4
Mark-to-market derivative liabilities			24				24				—				29				29				—
Unamortized energy contract liabilities			22				22				—				5				5				—
Other current liabilities			25				25				—				5				5				—
	Total current liabilities		561				476				77				320				236				74
	Long-term debt		212				81				120				298				86				195
	Asset retirement obligations		1,763				1,763				—				—				—				—
	Pension obligation(a)		9				9				—				—				—				—
	Unamortized energy contract liabilities		51				51				—				28				28				—
	Other noncurrent liabilities		127				127				—				12				12				—
	Noncurrent liabilities		2,162				2,031				120				338				126				195
	Total liabilities		$	2,723			$	2,507			$	197			$	658			$	362			$	269
___________
(a)	Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—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 and Other assets. 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.
As of December 31, 2014 and 2013, Exelon and Generation had significant unconsolidated variable interests in six and eight VIEs, respectively, for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The decrease in the number of unconsolidated VIEs is due to the sale of Generation's ownership interest in four unconsolidated VIEs in 2014, offset by the execution of an energy purchase and sale agreement with an unconsolidated VIE and an equity investment in another unconsolidated VIE. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
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
31-Dec-13	Commercial				Equity				Total
	Agreement				Investment
	VIEs				VIEs
Total assets(a)	$	128			$	332			$	460
Total liabilities(a)	17				123				140
Exelon's ownership interest in VIE(a)	—				86				86
Other ownership interests in VIE(a)	111				123				234
Registrants’ maximum exposure to loss:
Carrying amount of equity method investments	7				67				74
Contract intangible asset	9				—				9
Debt and payment guarantees	—				5				5
Net assets pledged for Zion Station decommissioning(b)	44				—				44
___________________
(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
(b)	These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.
For each unconsolidated VIE, Exelon and Generation assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable interest entities.
Energy Purchase and Sale Agreements.  Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.
In March 2005, Constellation, to which Generation is now a successor, closed a transaction in which Generation assumed from a counterparty two power sales contracts with previously existing VIEs. The VIEs previously were created by the counterparty to issue debt in order to monetize the value of the original contracts to purchase and sell power. Under the power sales contracts, Generation sold power to the VIEs which, in turn, sold that power to an electric distribution utility through 2013. In connection with this transaction, a third-party acquired the equity of the VIEs and Generation loaned that party a portion of the purchase price. If the electric distribution utility were to default under its obligation to buy power from the VIEs, the equity holder could transfer its equity interests to Generation in lieu of repaying the loan. In this event, Generation would have the right to seek recovery of its losses from the electric distribution utility. As a result, Generation has concluded that consolidation was not required. During 2013, the third-party repaid their obligations of the loan with Generation which caused the entities to no longer be unconsolidated VIEs.
ZionSolutions. Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further discussed in Note 15 — Asset Retirement Obligations. Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when decommissioning is complete. Generation has evaluated this agreement and determined that, through the put option, it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions’ creditors do not have any recourse to Exelon’s or Generation’s general credit.
Fuel Purchase Commitments. Generation’s customer supply operations include the physical delivery and marketing of power obtained through its generating capacity, and long-, intermediate- and short-term contracts. Generation also has contracts to purchase fuel supplies for nuclear and fossil generation. These contracts and Generation’s membership in NEIL are discussed in further detail in Note 22 — Commitments and Contingencies. Generation has evaluated these contracts and its membership with NEIL and determined that it either has no variable interest in an entity or, where Generation does have a variable interest in an entity, the variable interest is not significant and it is not the primary beneficiary; therefore, consolidation is not required.
For contracts where Generation has a variable interest, the level of variability being absorbed through the contracts is not considered significant because of the small proportion of the entities’ activities encompassed by the contracts with Generation. Further, Generation has considered which interest holder has the power to direct the activities that most significantly affect the economic performance of the VIE and thus is considered the primary beneficiary and is required to consolidate the entity. The primary beneficiary must also have exposure to significant losses or the right to receive significant benefits from the VIE. In general, the most significant activity of the VIEs is the operation and maintenance of the facilities. Facilities represent power plants, sources of uranium and fossil fuels, or plants used in the uranium conversion, enrichment and fabrication process. Generation does not have control over the operation and maintenance of the facilities considered VIEs, and it does not bear operational risk of the facilities. Furthermore, Generation has no debt or equity investments in the entities and Generation does not provide any other financial support through liquidity arrangements, guarantees or other commitments other than purchase commitments described in Note 22 — Commitments and Contingencies. Upon consideration of these factors, Generation does not consider itself to have significant variable interests in these entities or be the primary beneficiary of these VIEs and, accordingly, has determined that consolidation is not required.
Investment in Energy Development Projects and Energy Generating Facilities. Generation has several equity investments in energy development projects and energy generating facilities. Generation has evaluated the significant agreements, ownership structures and risks of each of its equity investments, and determined that certain of the entities are VIEs because the entity has an insufficient amount of equity at risk to finance its activities, Generation guarantees the debt of the entity, provides equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.
ComEd, PECO and BGE
The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of BGE, BGE Capital Trust II are not consolidated in Exelon’s, ComEd’s, PECO’s or BGE’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II as each Registrant financed its equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 —Debt and Credit Agreements for additional information.

Regulatory_Matters_Exelon_Gene

Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)	Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)
	The following matters below discuss the current status of material regulatory and legislative proceedings of the Registrants.
	Illinois Regulatory Matters
	Energy Infrastructure Modernization Act (Exelon and ComEd).
	Background
	Since 2011, ComEd’s 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. 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 December 31, 2014, and December 31, 2013, ComEd had a regulatory asset associated with the distribution formula rate of $371 million and $463 million, respectively. The regulatory asset associated with distribution true-up is amortized to Operating revenues as the associated amounts are recovered through rates.
	Annual Reconciliation
	2014 Filing. On April 16, 2014, ComEd filed its annual distribution formula rate to request a total increase to the revenue requirement of $269 million. On December 11, 2014, the ICC issued its final order which increased the revenue requirement by $232 million, reflecting an increase of $160 million for the initial revenue requirement for 2014 and an increase of $72 million related to the annual reconciliation for 2013. Approximately $23 million of the total $37 million revenue requirement disallowance is recoverable through other rider-based mechanisms. The rate increase was set using an allowed return on capital of 7.06% (inclusive of an allowed return on common equity of 9.25% for 2014 less a performance metrics penalty of 5 basis points for the 2013 reconciliation). The rates took effect in January 2015. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC on January 28, 2015.
	2013 Filing. On April 29, 2013, ComEd filed its annual distribution formula rate, which was updated in August 2013, to request a total increase to the revenue requirement of $353 million. On December 19, 2013, the ICC issued its final order which increased the revenue requirement by $341 million, reflecting an increase of $160 million for the initial revenue requirement for 2013 and an increase of $181 million for the annual reconciliation for 2012. The final revenue requirement reflected the impacts of Senate Bill 9, which became effective in May 2013 and clarified the intent of EIMA on three issues: an allowed return on ComEd’s pension asset; the use of year-end rather than average rate base and capital structure in the annual reconciliation; and the use of ComEd’s weighted average cost of capital interest rate rather than a short-term debt rate to apply to the annual reconciliation. The rate increase was set using an allowed return on capital of 6.94% (inclusive of an allowed return on common equity of 8.72%). The rates took effect in January 2014. ComEd requested a rehearing on specific issues, which was denied by the ICC. ComEd also filed an appeal, which was subsequently withdrawn.
	2012 Filing. On April 30, 2012, ComEd filed its annual distribution formula rate. On December 20, 2012, the ICC, issued its final order, which increased the revenue requirement by $73 million, reflecting an increase of $80 million for the initial revenue requirement for 2012 and a decrease of $7 million for the annual reconciliation for 2011. The rate increase was set using an allowed return on capital of 7.54% (inclusive of an allowed return on common equity of 9.81%). The rates took effect in January 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court. The Illinois Appellate Court upheld the ICC's decision on the issues on appeal. On May 30, 2013, ComEd updated its revenue requirement allowed in the December 2012 Order to reflect the impacts of Senate Bill 9, which resulted in a reduction to the current revenue requirement in effect of $14 million. The rates took effect in July 2013. ComEd and intervenors requested a rehearing on specific issues, which was denied by the ICC. ComEd and intervenors also filed appeals with the Illinois Appellate Court. The Illinois Appellate Court reaffirmed the ICC's order.
	Formula Rate Structure Investigation
	In October 2013, the ICC opened an investigation (the Investigation), in response to a complaint filed by the Illinois Attorney General, to change the formula rate structure by requesting three changes: the elimination of the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance, the netting of associated accumulated deferred income taxes against the annual reconciliation balance in calculating interest, and the use of average rather than year-end rate base for determining any ROE collar adjustment. On November 26, 2013, the ICC issued its final order in the Investigation, rejecting two of the proposed changes but accepting the proposed change to eliminate the income tax gross-up on the weighted average cost of capital used to calculate interest on the annual reconciliation balance. The accepted change became effective in January 2014, and reduced ComEd’s 2014 revenue by approximately $8 million. This change had no financial statement impact on ComEd in 2013. ComEd and intervenors requested rehearing, however all rehearing requests were denied by the ICC. ComEd and intervenors have filed appeals with the Illinois Appellate Court. ComEd cannot predict the results of any such appeals.
	Appeal of Initial Formula Rate Tariff
	On March 26, 2014, the Illinois Appellate Court issued an opinion with respect to ComEd’s appeal of the ICC’s order relating to ComEd’s initial formula rate tariff.  The most significant financial issues under appeal related to ICC findings that were counter to the formula rate legislation and were clarified by subsequent legislation (Senate Bill 9).  Therefore, only a subset of the issues originally appealed remained.  The Court found against ComEd on each of the remaining issues: compensation related adjustments, billing determinants and the use of certain allocators. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s final Order.
	ComEd asked the Illinois Supreme Court to hear the issue of allocation between State and Federal regulatory jurisdictions. On June 4, 2014, ComEd filed a Petition for Leave to Appeal with the Illinois Supreme Court solely on the issue of allocation between FERC and ICC jurisdictional costs. On July 2, 2014, the ICC filed its Answer to the Petition, arguing that Supreme Court review is not necessary or appropriate.  Under the procedural rules of the Illinois Supreme Court, ComEd is not allowed to reply to the ICC filing.  There is no set time by which the Court must rule on the Petition.  ComEd cannot predict whether the Court will grant the appeal, or if it does, the ultimate outcome.
	Expenditures and Capital Investment
	As part of the enactment of EIMA legislation ComEd made an initial contribution of $15 million (recognized as expense in 2011) to a new Science and Technology Innovation Trust fund on July 31, 2012, and will make recurring annual contributions of $4 million, the first of which was made on December 31, 2012, which will be used for customer education for as long as the AMI Deployment Plan remains in effect. In addition, ComEd will contribute $10 million per year for five years, as long as ComEd is subject to EIMA, to fund customer assistance programs for low-income customers, which will not be recoverable through rates. These contributions began in 2012.
	EIMA also provides a structure for substantial capital investment by utilities over a ten-year period to modernize Illinois' electric utility infrastructure. Participating utilities are required to file an annual update on their AMI implementation progress. In March 2014, ComEd filed a petition with the ICC for approval to accelerate the deployment of AMI meters. 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. To date, nearly 550,000 smart meters have been installed in the Chicago area.
	Appeal of 2007 Illinois Electric Distribution Rate Case (Exelon and ComEd). The ICC issued an order in ComEd’s 2007 electric distribution rate case (2007 Rate Case) approving a $274 million increase in ComEd’s annual delivery services revenue requirement, which became effective in September 2008. In the order, the ICC authorized a 10.3% rate of return on common equity. ComEd and several other parties filed appeals of the rate order with the Illinois Appellate Court (Court). The Court issued a decision on September 30, 2010, ruling against ComEd on the treatment of post-test year accumulated depreciation and the recovery of system modernization costs via a rider (Rider SMP).
	The court held the ICC abused its discretion in not reducing ComEd’s rate base to account for an additional 18 months of accumulated depreciation while including post-test year pro forma plant additions through that period. ComEd continued to bill rates as established under the ICC’s order in the 2007 Rate Case until June 1, 2011 when the rates set in the 2010 electric distribution rate case became effective. In subsequent ICC proceedings, the ICC issued an order requiring ComEd to provide a refund of approximately $37 million to customers related to the treatment of post-test year accumulated depreciation issue. On March 26, 2012, ComEd filed a notice of appeal with the Court. However, on September 27, 2013 the Court ruled against ComEd on the accumulated depreciation issue and affirmed that ComEd owes a refund to customers of approximately $37 million, including interest. On September 18, 2014, the ICC issued an order requiring the refund to occur in November 2014, rather than the eight month period previously approved. The refund was included with the Rider AMP refund discussed below. Former ComEd customers were eligible for a refund. ComEd was fully reserved for this liability at December 31, 2013. As of December 31, 2014 ComEd had refunded substantially all amounts to customers.
	Advanced Metering Program Proceeding (Exelon and ComEd). As part of ComEd’s 2007 Rate Case, the ICC approved recovery of costs associated with ComEd’s Rider SMP for the limited purpose of implementing a pilot program for AMI. In October 2009, the ICC approved ComEd’s AMI pilot program and associated rider (Rider AMP). ComEd collected approximately $24 million under Rider AMP and had no collections under Rider SMP through December 31, 2014. In ComEd’s 2010 electric distribution rate case, the ICC approved ComEd’s transfer of certain other costs from recovery under Rider AMP to recovery through electric distribution rates.
	Several parties, including the Illinois Attorney General, appealed the ICC’s orders on Rider SMP and Rider AMP. The Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP and Rider AMP on September 30, 2010 and March 19, 2012, respectively. In both cases, the Court ruled that the ICC’s approval of the rider constituted single-issue ratemaking. ComEd filed Petitions for Leave to Appeal to the Illinois Supreme Court, which were denied.
	In October 2013, the ICC opened an investigation on Rider AMP to determine if a refund is required and if so, to determine the appropriate refund amount. The ALJ presiding over the investigation requested each party provide a pre-trial memorandum describing their positions, which were submitted on April 10, 2014. The ICC Staff and the Illinois Attorney General proposed a refund of $14.6 million, representing the amount they claim was collected under Rider AMP since September 30, 2010, the date the Illinois Appellate Court reversed the ICC’s approval of the cost recovery provisions of Rider SMP. During the second quarter of 2014, ComEd reached a tentative agreement to jointly resolve the disputed refund claim. On September 18, 2014, the ICC approved a refund of $9.5 million plus interest to be issued to current customers in November 2014. Former ComEd customers also were eligible for a refund. As of December 31, 2014 ComEd had refunded substantially all amounts to customers.
	Grand Prairie Gateway Transmission Line (ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois.  On May 28, 2014, in a separate proceeding, FERC issued an order granting ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s transmission rate base.  If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate base. 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. Four parties filed timely applications for rehearing before the ICC. On November 25, 2014, the ICC denied the rehearing application filed by the Forest Preserve District of Kane County, but granted rehearing on the application of certain landowners who requested that the ICC consider an alternate route for a three-mile segment of the line in Kane County. The rehearing proceeding is currently pending and the ICC must enter a final order on rehearing by April 24, 2015. On December 10, 2014, the ICC denied the remaining two applications for rehearing. On January 15, 2015, those two parties, the City of Elgin and the SKP landowner group and Utility Risk Management Corporation (collectively, the SKP/URMC party), each filed a Notice of Appeal with the Second District Appellate Court. On February 3, 2015, the ICC filed motions with the Second District Appellate Court seeking to extend the time for the ICC to file the record on appeal until after the ICC issues its Order on rehearing. The ICC also filed a motion to consolidate those appeals. 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.
	Utility Consolidated Billing and Purchase of Receivables (Exelon and ComEd). ComEd is required to buy certain RES receivables, primarily residential and small commercial and industrial customers, at the option of the RES, for electric supply service and then include those amounts on ComEd’s bill to customers. Receivables are purchased at a discount to compensate ComEd for uncollectible accounts. ComEd produces consolidated bills for the aforementioned retail customers reflecting charges for electric delivery service and purchased receivables. As of December 31, 2014, the balance of purchased accounts receivable was $139 million. ComEd recovers from RES and customers the costs for implementing and operating the program under an ICC approved tariff. A number of municipalities, including the City of Chicago have switched to RES electric supply. As a result, ComEd experienced a significant increase in the amount of RES receivables it purchased in 2013.
	Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from retail customers without mark-up. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation.
	ComEd is required to purchase an increasing percentage of the electricity for customer deliveries from renewable energy resources.  Purchases by customers of electricity from competitive generation suppliers, whether as a result of the customers’ own actions or as a result of municipal aggregation, are not included in this calculation and have the effect of reducing ComEd’s purchase obligation. ComEd entered into several 20-year contracts with unaffiliated suppliers in December 2010 regarding the procurement of long-term renewable energy and associated RECs in order to meet its obligations under the state’s RPS. All associated costs are recoverable from customers.
	On December 18, 2013, the ICC approved the IPA’s 2014-2019 procurement plan, which provided for two separate energy procurements during 2014 to address potential fluctuations in energy due to customers switching between ComEd and competitive electric generation suppliers. During May and September 2014, ComEd conducted energy procurements to meet the IPA’s 2014-2019 procurement plan. On December 17, 2014, the ICC approved the IPA’s 2015-2020 procurement plan. See Note 22 — Commitments and Contingencies for additional information on ComEd’s energy commitments.
	FutureGen Industrial Alliance, Inc (Exelon and ComEd). During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to enter into 20-year sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date in 2017. The sourcing agreement provides that ComEd and Ameren will pay FutureGen’s contract prices, which are set annually pursuant to a formula rate. The contract prices are based on the difference between the costs of the facility and the revenues FutureGen receives from selling capacity and energy from the unit into the MISO or other markets, as well as any other revenue FutureGen receives from the operation of the facility.  The order also directs ComEd and Ameren to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from ComEd or Ameren, or from competitive electric generation suppliers.
	In February 2013, ComEd filed an appeal with the Illinois Appellate Court questioning the legality of requiring ComEd to procure power for retail customers purchasing electricity from competitive electric generation suppliers.  On July 22, 2014, the Illinois Appellate Court issued its ruling re-affirming the ICC’s order requiring ComEd to enter into the sourcing agreement with FutureGen and allowing the use of a tariff to recover its costs. ComEd decided not to appeal the Illinois Appellate Court’s decision to the Illinois Supreme Court.  However, the competitive electric generation suppliers and several large consumers petitioned for leave to appeal the Illinois Appellate Court’s decision. On November 26, 2014, the Illinois Supreme Court granted the petition. A decision from the Illinois Appellate Court is expected in late 2015.
	A significant portion of the cost of the development of FutureGen was being funded by the DOE under the American Recovery and Reinvestment Act of 2009. In early February 2015, the DOE suspended funding for the project until further clarity could be obtained on certain significant hurdles facing the project, including the outcome of the litigation described above. Whether or not the DOE funding will be reinstated at some later date is unknown at this time.
	ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order.  In addition, ComEd filed a petition with the ICC seeking approval of the tariff allowing for the recovery of its costs associated with the FutureGen contract from all of its electric distribution customers, which was approved by the ICC on September 30, 2014.  Depending on eventual market conditions and the cost of the facility, the sourcing agreement could have a material adverse impact on Exelon’s and ComEd’s cash flows and financial positions.
	See Note 22 — Commitments and Contingencies for additional information on ComEd’s energy commitments.
	Energy Efficiency and Renewable Energy Resources (Exelon and ComEd). Electric utilities in Illinois are required to include cost-effective energy efficiency resources in their plans to meet an incremental annual program energy savings requirement of 0.2% of energy delivered to retail customers for the year ended June 1, 2009, which increases annually to 2.0% of energy delivered in the year commencing June 1, 2015 and each year thereafter. Additionally, during the ten-year period that began June 1, 2008, electric utilities must implement cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers. The energy efficiency and demand response goals are subject to rate impact caps each year. Utilities are allowed recovery of costs for energy efficiency and demand response programs, subject to approval by the ICC. In January 2014, the ICC approved ComEd’s third three-year Energy Efficiency and Demand Response Plan covering the period June 2014 through May 2017. The plans are designed to meet Illinois' energy efficiency and demand response goals through May 2017, including reductions in delivered energy to all retail customers and in the peak demand of eligible retail customers.
	EIMA provides for additional energy efficiency in Illinois. Starting in the June 2013 through May 2014 period and occurring annually thereafter, as part of the IPA procurement plan, ComEd is to include cost-effective expansion of current energy efficiency programs, and additional new cost-effective and/or third-party energy efficiency programs that are identified through a request for proposal process. All cost-effective energy efficiency programs are included in the IPA procurement plan for consideration of implementation. While these programs are monitored separately from the Energy Efficiency Portfolio Standard (EEPS), funds for both the EEPS portfolio and IPA energy efficiency programs are collected under the same rider.
	Illinois utilities are required to procure cost-effective renewable energy resources in amounts that equal or exceed 2% of the total electricity that each electric utility supplies to its eligible retail customers. ComEd is also required to acquire amounts of renewable energy resources that will cumulatively increase this percentage to at least 10% by June 1, 2015, with an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set forth by Illinois legislation. As of December 31, 2014, ComEd had purchased sufficient renewable energy resources or equivalents, such as RECs, to comply with the Illinois legislation. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover procurement costs of RECs from retail customers without mark-up through rates. See Note 22 — Commitments and Contingencies for information regarding ComEd’s future commitments for the procurement of RECs.
	Pennsylvania Regulatory Matters
	2010 Pennsylvania Electric and Natural Gas Distribution Rate Cases (Exelon and PECO). On December 16, 2010, the PAPUC approved the settlement of PECO’s electric and natural gas distribution rate cases, which were filed in March 2010, providing increases in annual service revenue of $225 million and $20 million, respectively. The electric settlement provides for recovery of PJM transmission service costs on a full and current basis through a rider. The approved electric and natural gas distribution rates became effective on January 1, 2011.
	In addition, the settlements included a stipulation regarding how tax benefits related to the application of any new IRS guidance on repairs deduction methodology are to be handled from a rate-making perspective. The settlements require that the expected cash benefit from the application of any new guidance to tax years prior to 2011 be refunded to customers over a seven-year period. On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for electric transmission and distribution property. PECO adopted the safe harbor and elected a method change for the 2010 tax year. The expected total refund to customers for the tax cash benefit from the application of the safe harbor to costs incurred prior to 2010 is $171 million. On October 4, 2011, PECO filed a supplement to its electric distribution tariff to execute the refund to customers of the tax cash benefit related to the IRC Section 481(a) “catch-up” adjustment claimed on the 2010 income tax return, which is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2012.
	In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The expected total refund to customers for the tax cash benefit from the application of the new method to costs incurred prior to 2011 is $54 million. This amount is subject to adjustment based on the outcome of IRS examinations. Credits have been reflected in customer bills since January 1, 2013. PECO currently anticipates that the IRS will issue guidance during 2015 providing a safe harbor method of accounting for gas transmission and distribution property.
	The prospective tax benefits claimed as a result of the new methodology will be reflected in tax expense in the year in which they are claimed on the tax return and will be reflected in the determination of revenue requirements in the next electric and natural gas distribution rate cases. See Note 14 — Income Taxes for additional information.
	The 2010 electric and natural gas distribution rate case settlements did not specify the rate of return upon which the settlement rates are based, but rather provided for an increase in annual revenue. PECO has not filed a transmission rate case since rates have been unbundled.
	Pennsylvania Procurement Proceedings (Exelon and PECO). PECO’s first PAPUC approved DSP Program, under which PECO was providing default electric service, had a 29-month term that ended May 31, 2013. 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. Under the DSP Programs, PECO is permitted to recover its electric procurement costs from retail default service customers without mark-up through the GSA. The GSA provides for the recovery of energy, capacity, ancillary costs and administrative costs and is subject to adjustments at least quarterly for any over or under collections. In addition, PECO’s second DSP Program provides for the recovery of AEPS compliance costs through the GSA rather than a separate AEPS rider.
	In the second DSP Program, PECO procured electric supply for its default electric customers through five competitive procurements. The load for the residential and small and medium commercial classes is served through competitively procured fixed price, full requirements contracts of two years or less. For the large commercial and industrial class load, PECO has competitively procured contracts for full requirements default electric generation with the price for energy in each contract set to be the hourly price of the spot market during the term of delivery. PECO entered into contracts with PAPUC approved bidders, including Generation, for its five competitive procurements. 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.
	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. On May 1, 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 28, 2014, the Commonwealth Court issued the requested stay, pending a full review of the appeal. Pending the Commonwealth Court’s review, PECO will not implement CAP Shopping. The Commonwealth Court’s decision is expected in 2015.
	On March 10, 2014, PECO filed its third DSP Program with the PAPUC. 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. On August 28, 2014, PECO filed a Joint Petition for Partial Settlement, which affirmed PECO’s procurement plan for Residential and Small Commercial customers. On December 4, 2014, the PAPUC approved PECO's third DSP Program, as modified by the Joint Petition for Partial Settlement, without modification or limitation. Separate from the Joint Petition for Partial Settlement, the PAPUC also approved other items related to the program. The plan outlines how PECO will purchase electric supply for default service customers. PECO will procure 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.
	Smart Meter and Smart Grid Investments (Exelon and PECO). Pursuant to Act 129 and the follow-on Implementation Order of 2009, in April 2010, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million electric smart meters and an AMI communication network by 2020. The first phase of PECO’s SMPIP, which was completed on June 19, 2013, included the installation of an AMI communications network and the deployment of 600,000 smart meters to communicate with that network. On May 31, 2013, PECO and interested parties filed a Joint Petition for Settlement of the universal deployment plan with the PAPUC which was approved without modification on August 15, 2013. The Joint Petition for Settlement supports all material aspects of PECO’s universal deployment plan, including cost recovery, excluding certain amounts discussed below. Universal deployment is the second phase of PECO’s SMPIP, under which PECO will deploy all of the 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 $583 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $155 million on smart grid investments through final deployment of which $200 million has been funded by SGIG as discussed below. As of December 31, 2014, PECO has spent $540 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received.
	Pursuant to the ARRA of 2009, PECO and the DOE entered into a Financial Assistance Agreement to extend PECO $200 million in non-taxable SGIG funds of which $140 million relates to smart meter deployment and $60 million relates to smart grid infrastructure. As part of the agreement, the DOE has a conditional ownership interest in qualifying Federally-funded project property and equipment, which is subordinate to PECO’s existing mortgage. The SGIG funds were used by PECO to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of the third quarter of 2014, PECO received all of the $200 million, including $4 million for sub-recipients, in reimbursements. On October 15, 2014, the DOE issued a Close Out of Post-Award Project Cost Verification Audit, in which it was determined that PECO fully met its required cost share, and the audit was closed with no further action required.
	On August 15, 2012, PECO suspended installation of smart meters for new customers based on a limited number of incidents involving overheating meters. Following its own internal investigation and additional scientific analysis and testing by independent experts completed after September 30, 2012, PECO announced its decision to resume meter deployment work on October 9, 2012. PECO has replaced the previously installed meters with an alternative vendor’s meters. PECO is moving forward with the alternative meters during universal deployment and continues to evaluate meters from several vendors and may use more than one meter vendor during universal deployment.
	Following PECO’s decision, as of October 9, 2012 PECO will no longer use the original smart meters. For the meters that will no longer be used, the accounting guidance requires that any difference between the carrying value and net realizable value be recognized in the current period’s earnings, before considering potential regulatory recovery. The cost of the original meters, including installation and removal costs, owned by PECO was approximately $17 million, net of approximately $16 million of reimbursements from the DOE and approximately $2 million of depreciation. PECO requested and received approval from the DOE that the original meters continue to be allowable costs and that any agreement with the vendor will not be considered project income. In addition, PECO remained eligible for the full $200 million in SGIG funds. On August 15, 2013, PECO entered into an agreement with the original vendor, which was part of the final agreement discussed below, under which PECO transferred the original uninstalled meters to the vendor and will receive $12 million in return. On January 23, 2014, PECO entered a final agreement with the vendor pursuant to which PECO will be reimbursed for amounts incurred for the original meters and related installation and removal costs, via cash payments and rebates on future purchases of licenses, goods and services primarily through 2017. PECO previously had intended to seek regulatory rate recovery in a future filing with the PAPUC of amounts not recovered from the vendor. As PECO believed such costs were probable of rate recovery based on applicable case law and past precedent on reasonably and prudently incurred costs, a regulatory asset was established at the time of the removals.  Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations. On March 14, 2014, PECO filed its quarterly smart meter recovery surcharge with the PAPUC which included PECO’s proposed treatment of the final agreement with the vendor. On March 27, 2014, the PAPUC approved the surcharge as proposed by PECO.
	Energy Efficiency Programs (Exelon and PECO). PECO’s PAPUC-approved Phase I EE&C Plan had a four-year term that began on June 1, 2009 and concluded on May 31, 2013. The Phase I plan set forth how PECO would meet the required reduction targets established by Act 129’s EE&C provisions, which included a 3% reduction in electric consumption in PECO’s service territory and a 4.5% reduction in PECO’s annual system peak demand in the 100 hours of highest demand by May 31, 2013.
	The peak demand period ended on September 30, 2012 and PECO communicated its compliance with the reduction targets in a preliminary filing with the PAPUC on March 1, 2013. The final compliance report for all Phase I targets, was filed with the PAPUC on November 15, 2013.
	On March 29, 2013, PECO filed a Petition with the PAPUC to change the recovery period of certain Direct Load Control (DLC) Program costs necessary to implement the Phase I Plan. The Petition sought approval to allow PECO to recover $12 million in equipment, installation and information technology costs for its Residential DLC program with the amounts collected for the Phase I Plan. As the Phase I Plan was implemented at a cost less than originally budgeted, PECO proposed to recover these expenses from its Phase I Energy Efficiency Program Charge over-collection consistent with PAPUC guidance to recover all Phase I costs through Phase I funding. The PAPUC approved PECO’s Petition on May 9, 2013. A regulatory liability was established for the DLC program costs that will be amortized as a credit to the income statement to offset the related depreciation expense during the same period.
	The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that provides energy consumption reduction requirements for the second phase of Act 129’s EE&C programs, which went into effect on June 1, 2013. The order tentatively established PECO’s three-year cumulative consumption reduction target at 1,125,852 MWh, which was reaffirmed by the PAPUC on December 5, 2012.
	Pursuant to the Phase II implementation order, PECO filed its three-year EE&C Phase II plan with the PAPUC on November 1, 2012. The plan sets forth how PECO will reduce electric consumption by at least 1,125,852 MWh in its service territory for the period June 1, 2013 through May 31, 2016, adjusted for weather and extraordinary loads. The implementation order permits PECO to apply any excess savings achieved during Phase I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation order, at least 10% and 4.5% of the total consumption reductions must be through programs directed toward PECO’s public and low income sectors, respectively. If PECO fails to achieve the required reductions in consumption, it will be subject to civil penalties of up to $20 million, which would not be recoverable from ratepayers. Act 129 mandates that the total cost of the plan may not exceed 2% of the electric company’s total annual revenue as of December 31, 2006.
	On March 15, 2013, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2013 to May 31, 2014. PECO proposed to fund the estimated $10 million costs of the one-year program by modifying incentive levels for other Phase II programs. On May 9, 2013, the PAPUC approved PECO’s amended EE&C Phase II plan. The costs of DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with all other Phase II Plan costs.
	On November 14, 2013, the PAPUC issued a Tentative Order on Act 129 demand reduction programs which seeks comments on a proposed demand response program methodology for future Act 129 demand reduction programs as well as demand response potential and wholesale prices suppression studies. In its February 20, 2014 Final Order, the PAPUC stated that it does not expect to make a decision as to whether it will prescribe additional demand response obligations until 2015. Any decision reached would affect PECO's EE&C Plan subsequent to its Phase II Plan.
	On February 28, 2014, PECO filed a Petition for Approval to amend its EE&C Phase II Plan to continue its DLC demand reduction program for mass market customers from June 1, 2014 to May 31, 2016. PECO proposed to fund the estimated $10 million annual costs of the program by modifying incentive levels for other Phase II programs. The costs of the DLC program will be recovered through PECO’s Energy Efficiency Program Charge along with other Phase II Plan costs. In an April 23, 2014 Tentative Order, the PAPUC granted PECO’s Petition. The Order became final on May 5, 2014.
	Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act mandated that beginning in 2011, following the expiration of PECO’s rate cap transition period, certain percentages of electric energy sold to Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8% and the requirement for Tier II alternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual compliance period, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energy sources as set forth in Act 129 and the AEPS Act.
	PECO has entered into five-year and ten-year agreements with accepted bidders, including Generation, totaling 452,000 non-solar and 8,000 solar Tier I AECs annually in accordance with a PAPUC approved plan. The plan allowed PECO to bank AECs procured prior to 2011 and use the banked AECs to meet its AEPS Act obligations over two compliance years ending May 2013. The PAPUC also approved the procurement of Tier II AECs and supplemental AECs as well as the sale of excess AECs through independent third-party auctions or brokers.
	All AEPS administrative costs and costs of AECs are being recovered on a full and current basis from default service customers through a surcharge.
	PECO’s second DSP Program eliminated the AEPS surcharge. Beginning in June 2013, AEPS compliance costs are being recovered through the GSA.
	Pennsylvania Retail Electricity and Gas Markets (Exelon and PECO). Beginning in 2011, the PAPUC issued an order outlining the next steps in its investigation into the status of competition in Pennsylvania’s retail electricity market. The PAPUC found that the existing default service model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets Oversight to evaluate potential intermediate and long-term structural changes to the default service model. Through various orders, the PAPUC issued default electric service pricing for customers in PECO’s service territory. See Pennsylvania procurement proceedings discussed above for additional details.
	In early 2014, the extreme weather in PECO's service territory resulted in increased electricity commodity costs causing certain shopping customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3, 2014, the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers to provide more consumer education regarding their contract. The second rulemaking order requires electric distribution companies to enable customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated switching were to be in place within 30 days and six months of approval of the orders, respectively. The orders became final on June 14, 2014. On December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowing PECO to implement accelerated switching by the December 15, 2014 deadline.
On September 12, 2013, the PAPUC issued an Order that initiated an investigation into Pennsylvania’s natural gas retail market, including the role of the existing default service model and opportunities for market enhancements. On December 18, 2014, the PAPUC issued a Final Order directing the Office of Competitive Market Oversight to continue its investigation, confirming that natural gas distribution companies should remain with the default service model for the time being and directing establishment of a working group to examine other competitive issues. Comments on the Final Order were due on February 2, 2015. PECO will continue to monitor the Order and assess compliance, as necessary.
Pennsylvania Act 11 of 2012 (Exelon and PECO). On February 13, 2012, Act 11 was signed into law by the Governor. Act 11 seeks to clarify the PAPUC’s authority to approve alternative ratemaking mechanisms, which would allow 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. Act 11 also includes a provision that allows utilities to use a fully projected future test year under which the PAPUC may permit the inclusion of projected capital costs in rate base for assets that will be placed in service during the first year rates are in effect. On August 2, 2012, the PAPUC issued a Final Order establishing rules and procedures to implement the ratemaking provisions of Act 11. The implementation order requires a utility to have a long-term infrastructure improvement plan (LTIIP) which outlines how the utility is planning to increase its investment for repairing, improving, or replacing aging infrastructure, approved by the Commission prior to implementing a DSIC. On May 9, 2013, the PAPUC approved PECO’s LTIIP for its gas operations, which was filed on February 8, 2013. On February 5, 2015, PECO filed a petition to modify its approved Gas LTIIP with the PAPUC.  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 a recent PAPUC rulemaking.
Maryland Regulatory Matters
2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, and as amended on September 15, 2014, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $99 million and $68 million, respectively.
On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the Settlement Agreement) reached with all parties to the case under which it would receive an increase of $22 million in electric base rates and an increase of $38 million in gas base rates. The Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately $20 million, primarily for electric. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement without modification, which became a final order on December 12, 2014. The approved distribution rate order authorizing BGE to increase electric and gas distribution rates became effective for services rendered on or after December 15, 2014.
2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $83 million and $24 million, respectively. In addition to these requested rate increases, BGE’s application includes a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the "ERI initiative") in response to a MDPSC order through a surcharge separate from base rates.
On December 13, 2013, the MDPSC issued an order in BGE’s 2013 electric and natural gas distribution rate case for increases in annual distribution service revenue of $34 million and $12 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. Rates became effective for services rendered on or after December 13, 2013. The MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific projects in advance of cost recovery. On March 31, 2014, after reviewing comments filed by the parties and conducting a hearing on the matter, the MDPSC approved all but one project proposed for completion in 2014 as part of the ERI initiative. The ERI initiative surcharge became effective June 1, 2014. On November 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.
2012 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 27, 2012, BGE filed an application for increases to its electric and gas base rates with the MDPSC. On February 22, 2013, the MDPSC issued an order for increases in annual distribution service revenue of $81 million and $32 million, respectively, and an allowed return on equity of 9.75% and 9.60%, respectively. The rates became effective for services rendered on or after February 23, 2013. As part of the rate order, the MDPSC approved both recovery of and return on the merger integration costs, including severance, incurred during the test year for the Exelon and Constellation merger. As a result, the order affirmed the treatment of $20 million of severance-related costs that BGE had recorded as a regulatory asset in 2012, consistent with prior MDPSC decisions. Additionally, BGE established a new regulatory asset of $8 million related to non-severance merger integration costs, which includes $6 million of costs incurred during 2012. Current MDPSC treatment of these merger integration regulatory assets is to provide recovery over a five year period.
2011 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). In March 2011, the MDPSC issued a comprehensive rate order setting forth the details of the decision contained in its abbreviated electric and gas distribution rate order issued in December 2010. As part of the March 2011 comprehensive rate order, BGE was authorized to defer $19 million of costs as regulatory assets. These costs are being recovered over a 5-year period that began in December 2010 and include the deferral of $16 million of storm costs incurred in February 2010. The regulatory asset for the storm costs earns a regulated rate of return.
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 December 31, 2014 and December 31, 2013, BGE recorded a regulatory asset of $128 million and $66 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 discussed above, the cost of the retired non-AMI meters will be amortized over 10 years.
On February 26, 2014, the MDPSC issued an order authorizing BGE to impose a $75 upfront fee and an $11 recurring fee to customers electing to opt-out of BGE's smart meter installation program, effective the later of the first full billing cycle following July 1, 2014, or the AMI installation date in a customer's community. The fees authorized by the order will be reviewed after an initial 12 to 18 month period. On November 25, 2014, the MDPSC issued a decision approving BGE's proposal to automatically enroll unresponsive customers into the opt-out program and to charge those customers opt-out fees after BGE has exhausted attempts to schedule a meter installation. The ultimate impact of opt-out could affect BGE's ability to demonstrate cost-effectiveness of the advanced metering system.
Overall, BGE continues to believe the recovery of smart grid initiative costs in future rates is probable as BGE expects to be able to demonstrate that the program benefits exceed costs.
New Electric Generation (Exelon and BGE). On April 12, 2012, the MDPSC issued an order directing BGE and two other Maryland utilities to enter into a contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV will construct an approximately 700MW natural gas-fired combined-cycle generation plant in Waldorf, Maryland, that CPV projected will be in commercial operation by June 1, 2015. The initial term of the proposed contract is 20 years. The CfD mandates that BGE and the other utilities pay (or receive) the difference between CPV’s contract prices and the revenues CPV receives for capacity and energy from clearing the unit in the PJM capacity market. The MDPSC’s order requires the three Maryland utilities to enter into a CfD in amounts proportionate to their relative SOS load.
On April 16, 2013, the MDPSC issued an order that required BGE to execute a specific form of contract with CPV, and the parties executed the contract as of June 6, 2013. As of December 31, 2014, there is no impact on Exelon’s and BGE’s results of operations, cash flows and financial positions. Furthermore, the agreement does not become effective until the resolution of certain items, including all current litigation.
On April 27, 2012, a civil complaint was filed in the U.S. District Court for the District of Maryland by certain unaffiliated parties that challenged the actions taken by the MDPSC on Federal law grounds. On October 24, 2013, the U.S. District Court issued a judgment order finding that the MDPSC’s Order directing BGE and the two other Maryland utilities to enter into a CfD, which assures that CPV receives a guaranteed fixed price regardless of the price set by the federally regulated wholesale market, violates the Supremacy Clause of the United States Constitution. On November 22, 2013, the MDPSC and CPV appealed the District Court’s ruling to the United States Court of Appeals for the Fourth Circuit.
On May 4, 2012, BGE filed a petition in the Circuit Court for Anne Arundel County, Maryland, seeking judicial review of the MDPSC order under state law. That petition was subsequently transferred to the Circuit Court for Baltimore City and consolidated with similar appeals that have been filed by other interested parties. On October 1, 2013, the Circuit Court Judge issued a Memorandum Opinion and Order finding the decisions of the MDPSC were within its statutory authority under Maryland law. This decision is separate from the judgment in the federal litigation that the MDPSC Order is unconstitutional and the CfD is unenforceable under federal law. The federal judgment, if upheld, would prevent enforcement of the CfD even if the Circuit Court decision stands. On October 29, 2013, BGE and the two other Maryland utilities appealed the Circuit Court’s ruling to the Maryland Court of Special Appeals.
Depending on the ultimate outcome of the pending state and federal litigation, on the eventual market conditions, and on the manner of cost recovery as of the effective date of the agreement, the CfD could have a material impact on Exelon and BGE’s results of operations, cash flows and financial positions.
Exelon believes that this and other states’ projects may have artificially suppressed capacity prices in PJM and may continue to do so in future auctions to the detriment of Exelon’s market driven position. In addition to this litigation, Exelon is working with other market participants to implement market rules that will appropriately limit the market suppressing effect of such state activities.
MDPSC Derecho Storm Order (Exelon and BGE). Following the June 2012 Derecho storm which hit the mid-Atlantic region interrupting electrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 requiring BGE and other Maryland utilities to file several comprehensive reports with short-term and long-term plans to improve reliability and grid resiliency that were due at various times before August 30, 2013.
On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of the electric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various storm scenarios. During the summer of 2014, an evaluation of the reports filed by BGE and other Maryland utilities was undertaken by consultants on behalf of the MDPSC and MDPSC Staff. The MDPSC Staff also proposed standards for reliability during major events and estimated times of restoration as well as undertaking an evaluation of performance-based ratemaking principles and methodologies that would more directly and transparently align reliable service with the utilities’ distribution rates and that reduce returns or otherwise penalize sub-standard performance. The MDPSC held hearings in September 2014. BGE currently cannot predict the outcome of these proceedings, which may result in increased capital expenditures and operating costs.
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to promptly recover 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 costs 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. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to Exelon and BGE as of December 31, 2014.
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, however, a procedural schedule for the matter has not yet been set.
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, 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. While the RSSA is expected to be approved, in absence of such an agreement and in the event the plant was 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 December 31, 2014, and 2013, ComEd had a regulatory asset associated with the transmission formula rate of $21 million and $17 million, respectively, and BGE had a net regulatory asset associated with the transmission formula rate of $1 million and a net regulatory liability which was not material as of December 31, 2013. The regulatory asset associated with transmission true-up is amortized to Operating revenues as the associated amounts are recovered through rates.
In April 2014, ComEd filed its annual 2014 formula rate update with the FERC, reflecting an increased revenue requirement of $22 million, including an increase of $36 million for the initial revenue requirement, offset by a decrease of $14 million related to the annual reconciliation. The filing established the revenue requirement used to set rates that took effect in June 2014. ComEd’s 2014 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.62%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. The time period for any challenges to ComEd's annual 2014 formula rate update expired in October 2014 with no challenges submitted.
In April 2013, ComEd filed its annual 2013 formula rate update with the FERC, reflecting an increased revenue requirement of $68 million, including an increase of $38 million for the initial revenue requirement and an increase of $30 million related to the annual reconciliation. The filing established the revenue requirement used to set rates that took effect in June 2013. ComEd’s 2013 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.70%, inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.91% average debt and equity return previously authorized. The time period for any challenges to ComEd's annual 2013 formula rate update expired in October 2013 with no challenges submitted.
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 2014, BGE filed its 2014 formula rate update with the FERC reflecting an increased revenue requirement of $14 million, including an increase of $9 million for the initial revenue requirement and an increase of $5 million related to the annual reconciliation. The annual update established the revenue requirement used to set rates that took effect in June 2014. The time period for any challenges to BGE's annual update expired in October 2014 with no challenges submitted.
BGE’s 2014 formula transmission rate provides for a weighted average debt and equity return on transmission rate base of 8.53%, an increase from the 8.35% 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 11.3%, 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 the Pepco Holdings, Inc. 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.
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. After FERC ultimately denied all requests for rehearing on all issues, several parties filed petitions in the U.S. Court of Appeals for the Seventh Circuit for review of the decision. On August 6, 2009, that court issued its decision affirming FERC’s order with regard to the costs of existing facilities but reversing and remanding to FERC for further consideration its decision with regard to the costs of new facilities 500 kV and above.  On March 30, 2012, FERC issued an order on remand affirming the cost allocation in its April 2007 order.  On March 22, 2013, FERC issued an order denying rehearing and made it clear that the cost allocation at issue concerns only projects approved prior to February 1, 2013.  A number of entities have filed appeals of the FERC orders. On June 25, 2014, the U.S. Court of Appeals for the Seventh Circuit issued a decision once again remanding to FERC the cost allocation of new facilities 500 kV and above.  On December 18, 2014, FERC issued an order setting an evidentiary hearing and settlement proceeding regarding the issue of the cost allocation for facilities 500 kV and above. The hearing only concerns new facilities approved by the PJM Board prior to February 1, 2013. ComEd anticipates that all impacts of any rate design changes effective after December 31, 2006, should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on ComEd’s results of operations, cash flows or financial position. PECO anticipates that all impacts of any rate design changes should be recoverable through the transmission service charge rider approved in PECO’s 2010 electric distribution rate case settlement and, thus, the rate design changes are not expected to have a material impact on PECO’s results of operations, cash flows or financial position.  To the extent any rate design changes are retroactive to periods prior to January 1, 2011, there may be an impact on PECO’s results of operations. BGE anticipates that all impacts of any rate design changes effective after the implementation of its standard offer service programs in Maryland should be recoverable through retail rates and, thus, the rate design changes are not expected to have a material impact on BGE’s results of operations, cash flows or financial position.
ComEd, PECO and BGE are committed to the construction of transmission facilities under their operating agreements with PJM to maintain system reliability. ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE’s estimated commitments are as follows:
	Total			2015			2016			2017			2018		2019
ComEd	$	335		$	150		$	172		$	5		$	4	$	4
PECO	100			32			31			25			8		4
BGE	351			77			104			77			57		36
PJM Minimum Offer Price Rule (Exelon and Generation). PJM’s capacity market rules include a Minimum Offer Price Rule (MOPR) that is intended to preclude sellers from artificially suppressing the competitive price signals for generation capacity. The FERC orders approving the MOPR were upheld by the United States Court of Appeals for the Third Circuit in February 2014.
Exelon continues to work with PJM stakeholders and through the FERC process to implement several proposed changes to the PJM tariff aimed at ensuring that capacity resources (including those with state-sanctioned subsidy contracts and capacity market speculators) cannot inappropriately affect capacity auction prices in PJM.
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.
Market-Based Rates (Exelon, Generation, ComEd, PECO and BGE). Generation, ComEd, PECO and BGE are public utilities for purposes of the Federal Power Act and are required to obtain FERC’s acceptance of rate schedules for wholesale electricity sales. Currently, Generation, ComEd, PECO and BGE have authority to execute wholesale electricity sales at market-based rates. As is customary with market-based rate schedules, FERC has reserved the right to suspend market-based rate authority on a retroactive basis if it subsequently determines that Generation, ComEd, PECO or BGE has violated the terms and conditions of its tariff or the Federal Power Act. FERC is also authorized to order refunds in certain instances if it finds that the market-based rates are not just and reasonable under the Federal Power Act.
As required by FERC’s regulations, as promulgated in the Order No. 697 series, Generation, ComEd, PECO and BGE file market power analyses using the prescribed market share screens to demonstrate that Generation, ComEd, PECO and BGE qualify for market-based rates in the regions where they are selling energy, capacity, and ancillary services under market-based rate tariffs. On June 29, 2012, Generation, ComEd, PECO and BGE filed their updated market power analysis for the Central Region which the FERC accepted on November 13, 2012. On December 21, 2012, Generation, ComEd, PECO, and BGE filed their updated market power analysis for the SPP region, which the FERC accepted on October 8, 2013. On December 30, 2013, Generation, ComEd, PECO and BGE filed its updated analysis for the Northeast Region, based on 2012 historic test period data which the FERC accepted on August 5, 2014. On December 23, 2014, Generation filed its updated market power analysis for the Southeast Region and the FERC has not yet acted on the filing.
Reliability Pricing Model (Exelon, Generation and BGE). PJM’s RPM Base Residual Auctions take place approximately 36 months ahead of the scheduled delivery year. The most recent auction for the delivery year ending May 31, 2018 occurred in May 2014.
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 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 FERC's secretary 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 U.S. DC Circuit Court of Appeals. It is not clear whether such appeal would be effective as there is no action by the Commission to be considered. Nonetheless, while we think any change in the auction results 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).  In June 2012, the United States Court of Appeals for the DC Circuit vacated the NRC’s temporary storage rule on the grounds that the NRC should have conducted a more comprehensive environmental review to support the rule. The temporary storage rule (also referred to as the “waste confidence decision”) recognized that licensees can safely store spent nuclear fuel at nuclear plants for up to 60 years beyond the original and renewed licensed operating life of the plants and that licensing renewal decisions do not require discussion of the environmental impact of spent fuel stored on site. In August 2012, the NRC placed a hold on issuing new or renewed operating licenses that depend on the temporary storage rule until the court’s decision is addressed. On August 26, 2014, the NRC Commissioners approved the issuance of a revised rule codifying the NRC's generic determinations regarding the environmental impacts of continued storage of spent nuclear fuel beyond a reactor's licensed operating life and removed the hold on final licensing decision as of the effective date of the final rule. On September 19, 2014, the NRC issued the Continued Storage Rule, which became effective on October 20, 2014. On October 24, 2014, New York, Vermont, and Connecticut filed a petition for review in federal court which alleges that the Continued Storage Rule violates various federal laws and regulations.  The petition additionally challenges the Continued Storage Rule's supporting generic environmental impact statement (GEIS) as well as the August 26, 2014 NRC order lifting the suspension of all final licensing decisions for affected applications in view of the rule and GEIS.
On May 29, 2013, Generation submitted applications to the NRC to extend the current operating licenses of Byron Units 1 and 2, which are currently set to expire in 2024 and 2026, respectively, and Braidwood Units 1 and 2, currently set to expire in 2026 and 2027, respectively, by 20 years. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until late 2015 at the earliest.
On October 20, 2014, the NRC approved Generation's request to extend the operating licenses of Limerick Units 1 and 2 by 20 years to 2044 and 2049, respectively.
On December 9, 2014, Generation submitted applications to the NRC to extend the operating licenses of LaSalle Units 1 and 2 by 20 years, which are currently set to expire in 2022 and 2023, respectively. Generation does not expect the NRC to issue license renewals for LaSalle until 2016 at the earliest.
On August 29, 2012 and August 30, 2012, Generation submitted hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run Pumped Storage Facility 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, Generation is working with MDE to coordinate the refiling of its application for certification within the 90-day period. 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. Exelon 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, subsequently amended 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. 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 were set to expire on August 31, 2014 and September 1, 2014 respectively. 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.  The stations are currently being depreciated over their estimated useful lives, which includes the license renewal period. As of December 31, 2014, $39 million of direct costs associated with licensing efforts have been capitalized.
Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)
Exelon, ComEd, PECO and BGE prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2014 and 2013.
December 31, 2014	Exelon						ComEd						PECO				BGE
	Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	247		$	3,009		$	—		$	—		$	—	$	—	$	—	$	—
Deferred income taxes	6			1,536			—			64			—		1,400		6		72
AMI programs	25			271			10			81			15		62		—		128
Under-recovered distribution service costs	251			120			251			120			—		—		—		—
Debt costs	8			49			6			47			2		2		1		8
Fair value of BGE long-term debt	7			183			—			—			—		—		—		—
Severance	4			8			—			—			—		—		4		8
Asset retirement obligations	1			115			1			73			—		26		—		16
MGP remediation costs	36			221			30			189			6		31		—		1
Under-recovered uncollectible accounts	—			67			—			67			—		—		—		—
Renewable energy	20			187			20			187			—		—		—		—
Energy and transmission programs	37			11			26			7			—		—		11		4
Deferred storm costs	1			2			—			—			—		—		1		2
Electric generation-related regulatory asset	10			20			—			—			—		—		10		20
Rate stabilization deferral	75			85			—			—			—		—		75		85
Energy efficiency and demand response programs	89			159			—			—			—		—		89		159
Merger integration costs	2			6			—			—			—		—		2		6
Conservation voltage reduction	1			1			—			—			—		—		1		1
Under-recovered electric revenue decoupling	7			—									—		—		7		—
Other (a)	20			26			5			17			6		8		7		—
Total regulatory assets	$	847		$	6,076		$	349		$	852		$	29	$	1,529	$	214	$	510
December 31, 2014	Exelon						ComEd						PECO				BGE
	Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
Regulatory liabilities
Other postretirement benefits	$	51		$	37		$	—		$	—		$	—	$	—	$	—	$	—
Nuclear decommissioning	—			2,879			—			2,389			—		490		—		—
Removal costs	118			1,448			94			1,249			—		—		24		199
Energy efficiency and demand response programs	25			2			25			—			—		2		—		—
DLC program costs	—			10			—			—			—		10		—		—
Energy efficiency phase II	—			32			—			—			—		32		—		—
Electric distribution tax repairs	8			94			—			—			8		94		—		—
Gas distribution tax repairs	20			29			—			—			20		29		—		—
Energy and transmission programs	68			16			3			16			58		—		7		—
Over-recovered electric universal service fund costs	2			—			—			—			2		—		—		—
Revenue subject to refund	3			—			3			—			—		—		—		—
Over-recovered gas revenue decoupling	12			—			—			—			—		—		12		—
Other	3			3			—			1			2		—		1		1
Total regulatory liabilities	$	310		$	4,550		$	125		$	3,655		$	90	$	657	$	44	$	200
December 31, 2013	Exelon						ComEd						PECO				BGE
	Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
Regulatory assets
Pension and other postretirement benefits	$	221		$	2,794		$	—		$	—		$	—	$	—	$	—	$	—
Deferred income taxes	10			1,459			2			65			—		1,317		8		77
AMI programs	5			159			5			35			—		58		—		66
AMI meter events	—			5			—			—			—		5		—		—
Under-recovered distribution service costs	178			285			178			285			—		—		—		—
Debt costs	12			56			9			53			3		3		1		8
Fair value of BGE long-term debt	—			219			—			—			—		—		—		—
Fair value of BGE supply contracts	12			—			—			—			—		—		—		—
Severance	16			12			12			—			—		—		4		12
Asset retirement obligations	1			102			1			67			—		25		—		10
MGP remediation costs	40			212			33			178			6		33		1		1
RTO start-up costs	2			—			2			—			—		—		—		—
Under-recovered uncollectible accounts	—			48			—			48			—		—		—		—
Renewable energy	17			176			17			176			—		—		—		—
Energy and transmission programs	53			9			52			6			—		—		1		3
Deferred storm costs	3			3			—			—			—		—		3		3
Electric generation-related regulatory asset	13			30			—			—			—		—		13		30
Rate stabilization deferral	71			154			—			—			—		—		71		154
Energy efficiency and demand response programs	73			148			—			—			—		—		73		148
Merger integration costs	2			9			—			—			—		—		2		9
Other (a)	31			30			18			20			8		7		4		3
Total regulatory assets	$	760		$	5,910		$	329		$	933		$	17	$	1,448	$	181	$	524
December 31, 2013	Exelon						ComEd						PECO				BGE
	Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
Regulatory liabilities
Other postretirement benefits	$	2		$	43		$	—		$	—		$	—	$	—	$	—	$	—
Nuclear decommissioning	—			2,740			—			2,293			—		447		—		—
Removal costs	99			1,423			78			1,219			—		—		21		204
Energy efficiency and demand response programs	53			—			45			—			8		—		—		—
DLC Program Costs	1			10			—			—			1		10		—		—
Energy efficiency phase II	—			21			—			—			—		21		—		—
Electric distribution tax repairs	20			114			—			—			20		114		—		—
Gas distribution tax repairs	8			37			—			—			8		37
Energy and transmission programs	78			—			9			—			58		—		11		—
Over-recovered gas universal service fund costs	8			—			—			—			8		—		—		—
Revenue subject to refund	38			—			38			—			—		—		—		—
Over-recovered electric and gas revenue decoupling	16			—			—			—			—		—		16		—
Other	4			—			—			—			3		—		—		—
Total regulatory liabilities	$	327		$	4,388		$	170		$	3,512		$	106	$	629	$	48	$	204
__________________________
(a)	For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively.
Pension and other postretirement benefits. As of December 31, 2014, Exelon had regulatory assets of $3,256 million and regulatory liabilities of $88 million related to ComEd’s and BGE’s portion of deferred costs associated with Exelon’s pension plans and ComEd’s, PECO’s and BGE’s portion of deferred costs associated with Exelon’s other postretirement benefit plans. PECO’s pension regulatory recovery is based on cash contributions and is not included in the regulatory asset (liability) balances. The regulatory asset (liability) is amortized in proportion to the recognition of prior service costs (gains), transition obligations and actuarial losses (gains) attributable to Exelon’s pension and other postretirement benefit plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE will recover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirement benefit regulatory asset balance includes a regulatory asset established at the date of the Constellation merger related to BGE’s portion of the deferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. The BGE-related regulatory asset is being amortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participants at the date of the Constellation merger. See Note 16 — Retirement Benefits for additional detail. No return is earned on Exelon’s regulatory asset.
Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income taxes and how income taxes would be recorded under GAAP. Regulatory assets and liabilities associated with deferred income taxes, recorded in compliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects associated principally with accelerated depreciation accounted for in accordance with the ratemaking policies of the ICC, PAPUC and MDPSC, as well as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For ComEd and BGE, this amount includes the impacts of a reduction in the deductibility, for Federal income tax purposes, of certain retiree health care costs pursuant to the March 2010 Health Care Reform Acts. ComEd was granted recovery of these additional income taxes on May 24, 2011 in the ICC’s 2010 Rate Case order. The recovery period for these costs was through May 31, 2014. For BGE, these additional income taxes are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. For PECO, this amount includes the impacts of electric and gas distribution repairs in the deductibility pursuant to PUC’s 2010 rate case settlement agreement. See Note 14 — Income Taxes and Note 16 — Retirement Benefits for additional information. ComEd, PECO and BGE are not earning a return on the regulatory asset in base rates.
AMI programs. For ComEd, this amount represents operating and maintenance expenses and meter costs associated with ComEd’s AMI pilot program approved in the May 24, 2011, ICC order in ComEd’s 2010 rate case. The recovery periods for operating and maintenance expenses and meter costs through May 31, 2014, and January 1, 2020, respectively. As of December 31, 2014 and December 31, 2013, ComEd had regulatory assets of $88 million and $35 million, respectively, related to accelerated depreciation costs resulting from the early retirements of non-AMI meters, which will be amortized over an average ten year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a return on the regulatory asset. For PECO, this amount represents accelerated depreciation and filing and implementation costs relating to the PAPUC-approved Smart Meter Procurement and Installation Plan as well as the return on the un-depreciated investment, taxes, and operating and maintenance expenses. The approved plan allows for recovery of filing and implementation costs incurred through December 31, 2012. In addition, the approved plan provides for recovery of program costs, which includes depreciation on new equipment placed in service, beginning in January 2011 on full and current basis, which includes interest income or expense on the under or over recovery. The approved plan also provides for recovery of accelerated depreciation on PECO’s non-AMI meter assets over a 10-year period ending December 31, 2020. For BGE, this amount represents smart grid pilot program costs as well as the incremental costs associated with implementing full deployment of a smart grid program. Pursuant to a MDPSC order, pilot program costs of $11 million were deferred in a regulatory asset, and, beginning with the MDPSC’s March 2011 rate order, is earning BGE’s most current authorized rate of return. In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE, authorizing BGE to establish a separate regulatory asset for incremental costs incurred to implement the initiative, including the net depreciation and amortization costs associated with the meters, and an authorized rate of return on these costs, a portion of which is not recognized under GAAP until cost recovery begins. Additionally, the MDPSC order requires that BGE prove the cost-effectiveness of the entire smart grid initiative prior to seeking recovery of the costs deferred in these regulatory assets. Therefore, the commencement and timing of the amortization of these deferred costs is currently unknown. BGE’s AMI regulatory asset excludes costs for non-AMI meters being replaced by AMI meters, as recovery of those costs commenced with the new rates approved and implemented with the MDPSC order in BGE's 2014 electric and gas distribution case.
AMI Meter Events. This amount represents the remaining cost value of the original smart meters, net of accumulated depreciation, DOE reimbursements and amounts recovered from the vendor, of smart meter deployment that will no longer be used, including installation and removal costs. PECO intended to seek through regulatory rate recovery in a future filing with the PAPUC, any amounts not recovered from the vendor. PECO believed the amounts incurred for the original meters and related installation and removal costs were probable of recovery based on applicable case law and past precedent on reasonably and prudently incurred costs. As such, PECO deferred these costs on Exelon’s and PECO’s Consolidated Balance Sheet, beginning in 2012. PECO did not earn a return on the recovery of these costs. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which has been fully collected, with no gain or loss impacts on future results of operations.
Under-recovered distribution services costs. Under EIMA, ComEd is allowed recovery of distribution services costs through a formula rate tariff. The legislation provides for an annual reconciliation of the revenue requirement in effect to reflect the actual costs that the ICC determines are prudently and reasonably incurred in a given year. The over recovery associated with the 2011 reconciliation was recovered through rates over a one-year period, that began in January 2013. The under recovery associated with the 2012 reconciliation was recovered through rates over a one-year period that began in January 2014. The under recovery associated with the 2013 reconciliation will be recovered through rates over a one-year period beginning in January 2015. ComEd is earning a return on these costs. The regulatory asset also includes costs associated with certain one-time events, such as large storms, which will be recovered over a five-year period. As of December 31, 2014, the regulatory asset was comprised of $286 million for the applicable annual reconciliations and $85 million related to significant one-time events. In addition to $66 million in deferred storm costs, net of amortization, the December 31, 2014 balance related to significant one-time events contains $19 million of Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. As of December 31, 2013, the regulatory asset was comprised of $377 million for the applicable annual reconciliations and $86 million related to significant one-time events. In addition to $58 million in deferred storm costs, net of amortization, the December 31, 2013 balance related to significant one-time events contains $28 million of Constellation merger and integration related costs, net of amortization, incurred as a result of the Constellation merger. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information.
Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd’s, PECO’s and BGE’s recoverable losses on reacquired long-term debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced. Interest-rate swap settlements are deferred and amortized over the period that the related debt is outstanding or the life of the original issuance retired. These debt costs are used in the determination of the weighted cost of capital applied to rate base in the rate-making process. ComEd and BGE are not earning a return on the recovery of these costs, while PECO is earning a return on the premium of the cost of the reacquired debt through base rates.
Fair value of BGE long-term debt. These amounts represent the regulatory asset recorded at Exelon for the difference in the fair value of the long-term debt of BGE as of the Constellation merger date based on the MDPSC practice to allow BGE to recover its debt costs through rates. Exelon is amortizing the regulatory asset and the associated fair value over the life of the underlying debt and is not earning a return on the recovery of these costs.
Fair value of BGE supply contract. These amounts represent the regulatory asset recorded at Exelon representing the fair value of BGE’s supply contracts as of the close of the Constellation merger date based on the MDPSC practice to allow BGE to recover its supply contracts through rates. Exelon amortized the regulatory asset and the associated fair value through December 31, 2014 and was not earning a return on the recovery of these contracts.
Severance. For ComEd, these costs represent previously incurred severance costs that ComEd was granted recovery of in the December 20, 2006, ICC rehearing rate order and the May 24, 2011, ICC order in ComEd’s 2010 rate case, and such costs were fully recovered as of December 31, 2014. ComEd did not earn a return on these costs. For BGE, these costs represent deferred severance costs that BGE has previously been granted recovery of in rates. Costs include the portion of costs associated with a 2008 workforce reduction that relate to BGE’s gas business which were deferred in 2009 as a regulatory asset in accordance with the MDPSC’s orders in prior rate cases and are being amortized over a 5-year period through December 31, 2013. Also included are costs associated with a 2010 workforce reduction that were deferred as a regulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. Finally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance with the MDPSC’s orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return on the regulatory asset included in base rates.
Asset retirement obligations. These costs represent future legally required removal costs associated with existing asset retirement obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd and BGE will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have been performed. See Note 15 — Asset Retirement Obligations for additional information.
MGP remediation costs. ComEd is allowed recovery of these costs under ICC approved rates. For PECO, these costs are recoverable through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. The period of recovery for both ComEd and PECO will depend on the timing of the actual expenditures. ComEd and PECO are not earning a return on the recovery of these costs. While BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. For BGE, $5 million of clean-up costs incurred during the period from July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in accordance with MDPSC orders. These costs are being amortized over 10-year periods that began in January 2006 and December 2010, respectively. BGE is earning a return on this regulatory asset. See Note 22 — Commitments and Contingencies for additional information.
RTO start-up costs. Recovery of these RTO start-up costs was approved by FERC. The recovery period is through March 31, 2015. ComEd is earning a return on these costs.
Under (Over)-recovered universal service fund costs. The universal service fund cost is a recovery mechanism that allows PECO to recover discounts issued to electric and gas customers enrolled in assistance programs. As of December 31, 2014, PECO was under-recovered for its gas program and over-recovered for its electric program. Whereas, as of December 31, 2013, PECO was over-recovered for both its electric and gas programs PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers.
Under (Over)-recovered uncollectible accounts. ComEd adjusts its rates annually to reflect the increases and decreases in annual uncollectible accounts costs. The recovery or refund of the difference in the uncollectible accounts costs takes place over a 12-month time frame beginning in June of the following year. ComEd is not earning a return or paying interest on these under (over)-recovered costs.
Renewable Energy. 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. Delivery under the contracts began in June 2012. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation, ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). The basis for the mark-to-market derivative asset or liability position is based on the difference between ComEd’s cost to purchase energy on the spot market and the contracted price.
Energy and transmission programs. ComEd’s energy and transmission costs are recoverable (refundable) under ComEd’s ICC and/or FERC-approved rates. ComEd earns interest on under-recovered costs and pays interest on over-recovered costs to customers. 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. As of December 31, 2013, ComEd's regulatory asset of $58 million included $35 million related to under-recovered energy costs for hourly and non-hourly customers, $17 million associated with transmission costs recoverable through its FERC-approved formula rate, and $6 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2013, ComEd's regulatory liability of $9 million related to revenues received for renewable energy requirements.
The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO’s GSA and PGC, respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas costs to customers. In addition, beginning in 2013, the deferred DSP I and II Program costs are presented on a net basis with PECO’s GSA under (over)-recovered energy costs. See discussion below of each program. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2014, PECO had a regulatory liability that included $39 million related to the DSP program, $16 million related to over-recovered natural gas supply costs under the PGC and $3 million related to over-recovered electric transmission costs. As of December 31, 2013, PECO had a regulatory liability that included $34 million related to the DSP program, $8 million related the over-recovered electric transmission costs and $16 million related to over-recovered natural gas supply costs under the PGC.
DSP Program costs. These amounts represent recoverable administrative costs incurred relating to filing, procurement, and information technology improvements associated with PECO’s PAPUC- approved DSP Program for the procurement of electric supply following the expiration of PECO’s generation rate caps on December 31, 2010. The filing and implementation costs of this DSP Program are recoverable through the GSA over its 29-month term that began January 1, 2011. The independent evaluator costs associated with conducting procurements is recoverable over a 12-month period after the PAPUC approves the results of the procurements. Costs relating to information technology improvements are recoverable over a 5-year period that began January 1, 2011. PECO earns a return on the recovery of information technology costs. These costs are included within the energy and transmission programs line item.
DSP II Program Costs. These amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO’s second PAPUC-approved DSP program for the procurement of electric supply. The filing and procurement of this DSP Program are recoverable through the GSA over its 24-month term that began June 1, 2013. The independent evaluator costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements. PECO is not earning a return on these costs. These costs are included within the energy and transmission programs line item.
The BGE energy costs represent the electric and gas supply related costs recoverable (refundable) from (to) customers under BGE’s market-based SOS and MBR programs, respectively. BGE does not earn or pay interest on under- or over-recovered costs to customers. 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. As of December 31, 2013, BGE's regulatory asset of $4 million included $3 million of Constellation merger and integration costs and $1 million of abandonment costs to be recovered upon FERC approval. As of December 31, 2013, BGE's regulatory liability of $11 million related to over-recovered natural gas supply costs.
Deferred storm costs. In the MDPSC’s March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February 2010. These costs are being amortized over a 5-year period that began in December 2010. BGE is earning a return on this regulatory asset.
Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual, generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The portion of this regulatory asset that does not earn a regulated rate of return was $28 million as of December 31, 2014, and $37 million as of December 31, 2013. BGE will continue to amortize this amount through 2017.
Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 to January 1, 2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2014 and 2013, BGE recovered $65 million and $66 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings over a period not to exceed ten years when collection from customers began in June 2007.
Energy efficiency and demand response programs. These amounts represent costs recoverable (refundable) under ComEd’s ICC approved Energy Efficiency and Demand Response Plan, PECO’s PAPUC-approved EE&C Plan, and the BGE Smart Energy Savers Program®. ComEd recovers these costs through a rider. ComEd earns a return on the capital investment incurred under the program but does not earn (pay) interest on under (over) collections. For PECO, this amount represents an over-collection of program costs related to both Phase I and Phase II of its EE&C Plan. PECO does not earn (pay) interest on under (over) collections. PECO began recovering the costs of its Phase I and Phase II EE&C Plans through a surcharge in January 2010 and June 2013, respectively, based on projected spending under the programs. Phase I recovery continued over the life of the program, which expired on May 31, 2013 and excess funds collected began being refunded in June 2013. Phase II of the program began on June 1, 2013, and will continue over the life of the program, which will expire on May 31, 2016. Excess funds collected are required to be refunded beginning in June 2016. PECO earned a return on the capital investment incurred under Phase I of the program. BGE’s Smart Energy Savers Program® includes both MDPSC approved demand response and energy efficiency programs. For the BGE Peak RewardsSM demand response program which began in January 2008, actual marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment. Also included in the demand response program are customer bill credits related to BGE’s Smart Energy Rewards program which began in July 2013. Actual costs incurred in the conservation program are being amortized over a 5-year period with recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a rate of return on the capital investments and deferred costs incurred under the program and earns (pays) interest on under (over) collections.
Merger integration costs. These amounts represent integration costs to achieve distribution synergies related to the Constellation merger transaction. As a result of the MDPSC’s February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costs incurred during 2012 and the first quarter of 2013. Of these costs, $4 million was authorized to be amortized over a 5-year period that began in March 2013. The recovery of the remaining $4 million was deferred. In the MDPSC’s December 2013 rate order, BGE was authorized to recover the remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are being amortized over a 5-year period that began in December 2013. BGE is earning a return on this regulatory asset included in base rates.
Under (Over)-recovered electric and gas revenue decoupling. These amounts represent the electric and gas distribution costs recoverable from or (refundable) to customers under BGE’s decoupling mechanism, which does not earn a rate of return. As of December 31, 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. As of December 31, 2013, BGE had a regulatory liability of $7 million related to over-recovered electric revenue decoupling and $9 million related to over-recovered natural gas revenue decoupling.
Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for the Regulatory Agreement Units that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund assets, including prospective earnings thereon and any future collections from customers, will be sufficient to fund the associated future decommissioning costs at the time of decommissioning. See Note 15 — Asset Retirement Obligations for additional information.
Removal costs. These amounts represent funds ComEd and BGE have received from customers through depreciation rates to cover the future non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking purposes. This liability is reduced as costs are incurred.
DLC Program Costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement the DLC Program under PECO’s EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as a credit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaining useful life of the assets. PECO is not paying interest on these over-recovered costs.
Electric distribution tax repairs. PECO’s 2010 electric distribution rate case settlement required that the expected cash benefit from the application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year period. Credits began being reflected in customer bills on January 1, 2012. No interest will be paid to customers.
Gas distribution tax repairs. PECO’s 2010 natural gas distribution rate case settlement required that the expected cash benefit from the application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits began being reflected in customer bills on January 1, 2013. No interest will be paid to customers.
Under (Over)-recovered AEPS costs current asset (liability). The AEPS costs represent the administrative and AEC costs incurred to comply with the requirements of the AEPS Act, which are recoverable on a full and current basis. PECO earns interest on under-recovered costs and pays interest on over-recovered costs to customers. These costs are included within the energy and transmission programs line item.
Revenue subject to refund. These amounts represent refunds and associated interest ComEd owes to customers primarily related to the treatment of the post-test year accumulated depreciation issue in the 2007 Rate Case. As of December 31, 2014, and December 31, 2013, ComEd owed $3 million and $37 million with $1 million of interest, respectively. See above discussion of the 2007 Rate Case for further information.
Purchase of Receivables Programs (Exelon, ComEd, PECO, and BGE)
ComEd, PECO and BGE are required, under separate legislation and regulations in Illinois, Pennsylvania and Maryland, respectively, to purchase certain receivables from retail electric and natural gas suppliers. For retail suppliers participating in the utilities’ consolidated billing, ComEd, PECO and BGE must purchase their customer accounts receivables. ComEd purchases receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. BGE’s tariff provides that receivables are to be purchased at a discount, primarily to recover uncollectible accounts expense from the suppliers. However, if the discount rate is negative, the tariff provides that the receivable is purchased at a zero discount rate. BGE is currently purchasing certain receivables at a zero discount rate. PECO is required to purchase receivables at face value and is permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO, and BGE do not record unbilled commodity receivables under their POR programs. Purchased billed receivables are classified in other accounts receivable, net on Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of December 31, 2014 and 2013.
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
As of December 31, 2013	Exelon			ComEd			PECO			BGE
Purchased receivables (a)	$	263		$	105		$	72		$	86
Allowance for uncollectible accounts (b)	(30		)	(16		)	(7		)	(7		)
Purchased receivables, net	$	233		$	89		$	65		$	79
_________________________
(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.

Mergers_Acquisitions_and_Dispo

Mergers, Acquisitions and Dispositions (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
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 $126 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI as of December 31, 2014, 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, Exelon and PHI proposed a package of benefits to the PHI utilities’ respective customers, providing for direct investment of more than $100 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.
	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 11, 2015, the NJBPU approved the proposed merger and the previously filed settlement signed and filed by Exelon, PHI, Atlantic City Electric (ACE), NJBPU staff, and the Independent Energy Coalition. The settlement provides a package of benefits to ACE customers and the state of New Jersey. This package of benefits includes the establishment of customer rate credit programs, with an aggregate value of $62 million for ACE customers and energy efficiency programs that will provide savings for ACE customers of $15 million.
	Completion of the transaction also remains conditioned upon approval by the Public Services Commissions of the District of Columbia, Delaware and Maryland. Procedural schedules have been set in these commission proceedings and final approval decisions are expected in the first half of 2015.
	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 will continue to work cooperatively with the DOJ regarding the proposed merger.
	Exelon and PHI continue to expect to complete the merger 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. In September 2014, the parties reached a proposed settlement which is subject to court approval. Final court approval of the proposed settlement is not expected to occur until the second quarter of 2015, at the earliest. Exelon has also been named in a federal court case with similar claims and is in the process of negotiating a settlement.  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.
	Through December 31, 2014, Exelon has incurred approximately $179 million of expense associated with the proposed merger, primarily $48 million related to acquisition and integration costs and $131 million of costs incurred to finance the transaction. The Merger Agreement also provides for termination rights on behalf of 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 does not close 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.
	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 debt and equity security issuances and the net after-tax cash proceeds from generating asset divestitures during the second half of 2014. See Note 13 — Debt and Credit Agreements and Note 19 — Common Stock for more information.
	Acquisitions (Exelon and Generation)
	Acquisition of Integrys Energy Services, Inc. (Exelon and Generation)
	On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $332 million, including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income tax purposes. As of December 31, 2014, Generation had remitted $319 million to Integrys Energy Group, Inc. and the remaining balance of $13 million, which is included in Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets, will be paid during the first or second quarter of 2015. The generation and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.
	Consistent with the applicable accounting guidance, the fair value of the assets acquired and liabilities assumed was determined as of the acquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in the future cash flows; and future power and fuel market prices.
	The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the Integrys acquisition by Generation:
	Total consideration transferred		$	332
	Identifiable assets acquired and liabilities assumed
	Working capital assets		$	389
	Mark-to-market derivative assets		185
	Unamortized energy contract assets		115
	Customer relationships		48
	Working capital liabilities		(195		)
	Mark-to-market derivative liabilities		(57		)
	Unamortized energy contract liabilities		(109		)
	Deferred tax liability		(16		)
	Total net identifiable assets, at fair value		$	360
	Bargain purchase gain (after-tax)		$	28
	The purchase accounting is preliminary, and although not expected, may be further adjusted from what is shown above.
	The after-tax bargain purchase gain of $28 million is primarily the result of IES executing additional contract volumes between the date the acquisition agreement was signed and the closing of the transaction resulting in an increase in the fair value of the net assets acquired as of the acquisition date. The after-tax gain is included within Gain on consolidation and acquisition of businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
	IES's operating revenue and net loss included in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the period from November 1, 2014 to December 31, 2014 were approximately $386 million and $(42) million, respectively. The net loss includes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchase gain of $28 million. Exelon and Generation incurred approximately $7 million of merger and integration related costs which are included within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
	Merger with Constellation (Exelon, Generation, ComEd, PECO and BGE)
	Description of Constellation Merger Transaction
	On March 12, 2012, Exelon completed the merger contemplated by the Merger Agreement among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including those with generation and customer supply operations that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.
	Regulatory Matters from the Constellation Merger
	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 following costs were recognized after the closing of the merger and are included in Exelon’s, Generation’s and BGE’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012:
	Description	Payment		BGE				Generation			Exelon			Statement of
		Period												Operations
														Location
	BGE rate credit of $100 per	Q2 2012		$	113			$	—		$	113		Revenues
	residential customer (a)
	Customer investment fund to invest	2012 to 2014		—				—			114			O&M Expense
	in energy efficiency and low-income energy assistance to BGE customers
	Contribution for renewable energy,	2012 to 2014		—				—			2			O&M Expense
	energy efficiency or related projects in Baltimore
	Charitable contributions at $7 million	2012 to 2021		28				35			70			O&M Expense
	per year for 10 years
	State funding for offshore wind	Q2 2012		—				—			32			O&M Expense
	development projects
	Miscellaneous tax benefits	Q2 2012		(2		)		—			(2		)	Taxes Other Than Income
	Total			$	139			$	35		$	329
	_______________________
	(a)	Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.
	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. See Note 22 — Commitments and Contingencies for further information regarding Generation's total commitments under the lease agreement.
	The direct investment estimate also includes $600 million to $650 million for Exelon’s and Generation’s commitment to develop or assist in development of 285—300MWs of new generation in Maryland, 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.
	To date, Generation has placed into service 40MW and has commenced development of 150MW of new generation in Maryland towards the 300MW commitment. In July 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland site with at least 120MW of natural gas-fired generation to satisfy one of the commitments to Maryland with achievement of commercial operation expected in 2015. In December 2013, Generation entered into contracts associated with the construction of the 40MW Fourmile Wind project, which was placed in service in December 2014. In December 2014, Generation entered into contracts associated with the construction of the 30MW Fair Wind project in western Maryland with achievement of commercial operations expected in 2015. The wind projects will satisfy a portion of the 125MW Tier I land-based renewables commitment. See Note 22 — Commitments and Contingencies for additional information. Exelon’s and Generation’s consolidated financial statements include $185 million and $24 million of capitalized expenditures within Property, plant and equipment, net as of December 31, 2014 and 2013, respectively, and $3 million and $6 million of development costs within Operating and maintenance expense for the periods ended December 31, 2014 and 2013, respectively, associated with the pursuit of these commitments for new generation in the State of Maryland.
	Associated with certain of the regulatory approvals required for the merger, on November 30, 2012, a subsidiary of Generation sold three Maryland generating stations and associated assets, Brandon Shores and H.A. Wagner in Anne Arundel County, Maryland, and C.P. Crane in Baltimore County, Maryland, to Raven Power Holdings LLC (Raven Power), a subsidiary of Riverstone Holdings LLC. The sale agreement included a base price with purchase price adjustments based on fuel inventory, working capital, capital expenditures, and timing of the closing, resulting in net proceeds from the sale of approximately $371 million. Decisions by certain market participants to remove themselves from the bidding process, combined with the deadlines and limitations on the pool of potential buyers imposed by the merger approval orders, resulted in realized sales proceeds below Generation’s estimated fair value of the Maryland generating stations. Consequently, Exelon and Generation recorded a pre-tax loss of $272 million in 2012 to reflect the difference between the sales price and the carrying value of the generating stations and associated assets. In the first quarter of 2013, Exelon and Generation recorded a pre-tax gain of $8 million to reflect the final settlement of the sales price with Raven Power.
	In connection with the sale of the Maryland generating stations, Exelon agreed to indemnify Raven Power for certain costs associated with the treatment of hazardous substances at off-site disposal facilities and any claims arising as a result of, or in connection with, any toxic tort, natural resource damages, loss of life or injury to persons due to releases of, or exposure to hazardous substances in connection with Raven Power’s remediation of environmental contamination or Exelon’s non-compliance with environmental laws or permits prior to the closing date of the sale.
	Pursuant to the MDPSC merger approval conditions, BGE was restricted from paying any dividend on its common shares through the end of 2014, was required to maintain specified minimum capital and O&M expenditure levels in 2012 and 2013, and was not permitted to reduce employment levels due to involuntary attrition associated with the merger integration process for two years following the closing of the merger. Additionally, BGE is subject to other merger approval conditions to enhance BGE’s ring-fencing measures established by order of the MDPSC.
	Subsequent to the merger, Generation discovered that, for the first two weeks following the merger, due to a software error, Generation inadvertently bid certain generating units into the PJM energy market at prices that slightly exceeded the cost-based caps to which it had agreed. This error was a violation of the commitments made in connection with merger approvals by DOJ, FERC and the MDPSC. Generation reported the error to the DOJ, FERC and the MDPSC and committed to remedy the impacts of its error. The MDPSC held a hearing to review the error, and accepted Generation’s proposed remediation. Subsequent close examination by Generation of its cost-based bids also revealed the need for some minor adjustments to the cost build up for certain of its PJM units. Generation has coordinated with PJM to determine the impact on Generation’s revenues and the market from this error and these adjustments, and Generation has worked with PJM to reverse the financial impacts. In November 2012, Generation reached a settlement with the DOJ regarding this matter. The final resolution did not have a material impact on Exelon’s or Generation’s results of operations, cash flows or financial position.
	Exelon was named in suits filed in the Circuit Court of Baltimore City, Maryland alleging that individual directors of Constellation breached their fiduciary duties by entering into the proposed merger transaction and Exelon aided and abetted the individual directors’ breaches. Similar suits were also filed in the United States District Court for the District of Maryland. The suits sought to enjoin a Constellation shareholder vote on the proposed merger until all material information was disclosed and sought rescission of the proposed merger. During the third quarter of 2011, the parties to the suits reached an agreement in principle to settle the suits through additional disclosures to Constellation shareholders. On June 26, 2012, the court approved the settlement and entered final judgment.
	Accounting for the Constellation Merger
The fair value of Constellation’s non-regulated business assets acquired and liabilities assumed was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed.
The financial statements of BGE do not include fair value adjustments for assets or liabilities subject to ratesetting provisions for BGE. BGE is subject to the rate-setting authority of FERC and the MDPSC and is accounted for pursuant to the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for BGE provide revenue derived from costs including a return on investment of assets and liabilities included in rate base. Except for debt, fuel supply contracts and regulatory assets not earning a return, the fair values of BGE’s tangible and intangible assets and liabilities subject to these rate-setting provisions are assumed to approximate their carrying values and, therefore, do not reflect any net adjustments related to these amounts. For BGE’s debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as a regulatory asset and liability at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 1 — Significant Accounting Policies for additional information on BGE’s push-down accounting treatment. Also see Note 3 — Regulatory Matters for additional information on BGE’s regulatory assets.
The preliminary valuations performed in the first quarter of 2012 were updated in the second, third and fourth quarters of 2012, with the most significant adjustments to the preliminary valuation amounts having been made to the fair values assigned to the acquired power supply and fuel contracts, unregulated property, plant and equipment and investments in affiliates. There were no significant adjustments to the purchase price allocation in the first quarter of 2013 and the purchase price allocation was final as of March 31, 2013.
The final purchase price allocation of the Merger of Exelon with Constellation and Exelon’s contribution of certain subsidiaries of Constellation to Generation was as follows:
Preliminary Purchase Price Allocation, excluding amortization		Exelon				Generation
Current assets		$	4,936			$	3,638
Property, plant, and equipment		9,342				4,054
Unamortized energy contracts		3,218				3,218
Other intangibles, trade name and retail relationships		457				457
Investment in affiliates		1,942				1,942
Pension and OPEB regulatory asset		740				—
Other assets		2,265				1,266
Total assets		22,900				14,575
Current liabilities		3,408				2,804
Unamortized energy contracts		1,722				1,512
Long-term debt, including current maturities		5,632				2,972
Noncontrolling interest		90				90
Deferred credits and other liabilities and preferred securities		4,683				1,933
Total liabilities, preferred securities and noncontrolling interest		15,535				9,311
Total purchase price		$	7,365			$	5,264
Impact of the Constellation Merger
It is impracticable to determine the overall financial statement impact for the Constellation subsidiaries contributed down to Generation following the Upstream Merger for the year ended December 31, 2012. Upon closing of the merger, the operations of these Constellation subsidiaries were integrated into Generation’s operations and are therefore not fully distinguishable after the merger.
The impact of BGE on Exelon’s Consolidated Statement of Operations and Comprehensive Income includes operating revenues of $3,165 million, $3,065 million and $2,091 million and net income (loss) $211 million, $210 million and $(31) million during the years ended December 31, 2014, 2013 and 2012, respectively.
During the year ended December 31, 2014, Exelon and Generation both incurred merger and integration-related costs of $22 million.  Of these amounts, nothing was deferred as a regulatory asset as of December 31, 2014.
During the year ended December 31, 2013, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $142 million, $106 million, $16 million, $9 million and $6 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $17 million, $11 million and $6 million, respectively, as a regulatory asset as of December 31, 2013. Additionally, Exelon and BGE established a regulatory asset of $6 million as of December 31, 2013 for previously incurred 2012 merger and integration-related costs.
During the year ended December 31, 2012, Exelon, Generation, ComEd, PECO and BGE incurred merger and integration-related costs of $804 million, $340 million, $41 million, $17 million and $182 million, respectively. Of these amounts, Exelon, ComEd and BGE deferred $58 million, $36 million and $22 million, respectively, as a regulatory asset as of December 31, 2012.
The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and Comprehensive Income, with the exception of the BGE customer rate credit and the credit facility fees, which are included as a reduction to Operating revenues and Other, net, respectively, for years ended December 31, 2014, 2013, and 2012. See Note 22 — Commitments and Contingencies for additional information.
Pro-forma Impact of the Constellation Merger
The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon and Generation as if the merger with Constellation had taken place on January 1, 2011. The unaudited pro forma information was calculated after applying Exelon’s and Generation’s accounting policies and adjusting Constellation’s results to reflect purchase accounting adjustments.
The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
	Exelon						Generation
	Year Ended December 31,						Year Ended December 31,
(unaudited)	2012			2011 (a)			2012		2011 (a)
Total revenues	26,700			30,712			17,013		19,494
Net income attributable to Exelon	2,092			974			1,205		324
Basic earnings per share	2.56			1.15			n.a.		n.a.
Diluted earnings per share	2.55			1.14			n.a.		n.a.
_____________________
(a) The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.
(b) The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.
Asset Divestitures (Exelon and Generation)
Including the Quail Run generating facility that was sold on January 21, 2015, Generation has sold certain generating assets with a total net book value of approximately $1.8 billion prior to consideration of asset impairments (See Note 8 — Impairment of Long-Lived Assets for further information), for total pre-tax proceeds of approximately $1.8 billion (after-tax proceeds of approximately $1.4 billion), which resulted in cumulative pre-tax gains on sale of approximately $412 million, which are included in Gain (loss) on sales of assets on Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income. The proceeds are expected to be used primarily to finance a portion of the acquisition of PHI.
Station		Net Generation Capacity		Location		Operating Segment		Percent Owned
Fore River		726		North Weymouth, MA		New England		100%
West Valley		185		Salt Lake City, UT		Other		100%
Keystone		714		Shelocta, PA		Mid-Atlantic		41.98%
Conemaugh		532		New Florence, PA		Mid-Atlantic		31.28%
Safe Harbor		278		Conestoga, PA		Mid-Atlantic		66.70%
Quail Run		488		Odessa, TX		ERCOT		100%
At December 31, 2014, the assets and liabilities of the Quail Run generating facility were reported as Assets held for sale and within Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. The table below presents the major classes of assets and liabilities held for sale at December 31, 2014.
		December 31, 2014
Assets:
Property, plant and equipment, net (a)		$	143
Inventory		4
Total assets held for sale		$	147
Liabilities:
Accrued expenses		$	1
Asset retirement obligations		4
Total liabilities held for sale (b)		$	5
_____________
(a) The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8 — Impairment of Long-Lived Assets for further information.
(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Investment_in_Constellation_En

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)	12 Months Ended
	Dec. 31, 2014
Business Combinations [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.
	On April 1, 2014, Generation and subsidiaries of Generation, EDF, EDF, Inc. (EDFI) (a subsidiary of EDF) and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDFI’s rights as a member of CENG (the Integration Transaction). CENG will reimburse Generation for its direct and allocated costs for such services. As part of the arrangement, Nine Mile Point Nuclear Station, LLC, a subsidiary of CENG, also assigned to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with Long Island Power Authority, the Unit 2 co-owner. In addition, on April 1, 2014, the Power Services Agency Agreement (PSAA) was amended and extended until the permanent cessation of power generation by the CENG generation plants.
	In addition, on April 1, 2014, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified available cash flows of CENG and, in any event, payable upon the settlement of the Put Option Agreement discussed below (if the put option is exercised) or payable upon the maturity date of April 1, 2034, whichever occurs first. Immediately following receipt of the proceeds of such loan, CENG made a $400 million special distribution to EDFI.
	Exelon, Generation, and subsidiaries of Generation, EDFI and its parent (E.D.F. International S.A.S.), and CENG also executed a Fourth Amended and Restated Operating Agreement for CENG on April 1, 2014, pursuant to which, among other things, CENG committed to make preferred distributions to Generation (after repayment of the $400 million loan and associated interest) quarterly out of specified available cash flows until Generation has received aggregate distributions of $400 million plus a return of 8.5% per annum from April 1, 2014 (Preferred Distribution Rights).
	Generation and 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.
	On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified 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.
	In addition, on April 1, 2014, Generation, EDFI, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement (EMA) that provides for the transfer of CENG employees to Exelon or one of its affiliates and Exelon's assumption of the sponsorship of the employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their related trusts by Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the obligation related to pre-transfer service of employees, including the underfunded balance of the pension and other postretirement welfare benefit plans measured as of July 14, 2014 by making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF’s disposition of a majority of its interest in CENG.
	As a condition to obtaining regulatory approval for the NOSA and related transactions from the NRC, Exelon executed a support agreement pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to CENG (Exelon Support Agreement). The Exelon Support Agreement supersedes a previous support agreement under which Generation had agreed to provide up to $205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified circumstances to provide up to $165 million in additional financial support for CENG. A previous support agreement executed by an affiliate of EDF remains in effect under which the EDF affiliate may be required to provide up to approximately $145 million of financial support for CENG under specified circumstances. The agreements were executed on April 1, 2014 when the NRC licenses were transferred to Generation. No liability has been recognized by Exelon for the guarantees.
	Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1, 2014, through March 31, 2014, Generation recorded $19 million of equity in losses of unconsolidated affiliates related to its investment in CENG and recorded $17 million of revenues from CENG. For the twelve months ended December 31, 2013, Generation recorded $9 million of equity in losses of unconsolidated affiliates related to its investment in CENG and $56 million of revenues from CENG. The book value of Generation’s investment in CENG prior to the consolidation was $1.9 billion, and the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million.
	As a result of the consolidation of CENG on April 1, 2014, there are several additional transactions included in Exelon’s and Generation’s Consolidated Financial Statements between CENG and EDF that are considered related party transactions to Generation. As further described in Note 25 — Related Party Transactions 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. Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For the year ended December 31, 2014, Generation had sales to EDF of $137 million. See discussion above and Note 2 — Variable Interest Entities for additional information regarding other transactions, between CENG and EDF included within Exelon and Generation’s financial statements.
	See Note 2 — Variable Interest Entities for additional information about the Registrant's VIEs.
	Accounting for the Consolidation of CENG
	The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interest in CENG at fair value on Exelon’s and Generation’s Consolidated Balance Sheets. As a result of the consolidation, Exelon and Generation recorded a net gain of $261 million within their respective Consolidated Statements of Operations and Comprehensive Income. This gain consists of approximately $136 million related to the step up to fair value basis of our ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactions between CENG and Generation. The net gain on the consolidation of CENG of $261 million is net of a $7 million payment to EDF.
	The fair value of CENG’s assets and liabilities recorded in consolidation was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed.
	The valuations necessary to assess the fair values of certain assets and liabilities are considered preliminary as a result of the short time period between the execution of the NOSA and the end of the second quarter of 2014. The estimates of the fair value of assets and liabilities may be modified up to one year from April 1, 2014, as more information is obtained about the fair value of assets and liabilities. The principal items that have been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updated with inputs from a third party engineering firm with corresponding adjustments recorded in 2014. See Note 15—Asset Retirement Obligations for discussion of the impacts of adjustments recorded during 2014 related to updated estimates of the CENG asset retirement obligation liabilities. In the period of such revisions, these and any other material changes to the fair value assessments have resulted in adjustments to the amounts recorded upon consolidation. In addition, the asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation date have impacted Generation’s post-consolidation results of operations. No material changes are expected to the fair value of assets and liabilities.
	Generation recorded the assets and liabilities of CENG at fair value as of April 1, 2014. The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above:
	Fair Values	Exelon and Generation
	Current assets	$	499
	Nuclear decommissioning trust fund	1,955
	Property, plant and equipment	3,017
	Nuclear fuel	482
	Other assets	10
	Total assets	5,963
	Current liabilities	237
	Asset retirement obligation	1,760
	Pension and other employee benefit obligations	281
	Unamortized energy contract liabilities	171
	Other liabilities	114
	Total liabilities	2,563
	Total net assets	$	3,400
	Generation also recorded the fair value of the noncontrolling interest on its Consolidated Balance Sheets of approximately $1.5 billion, net of the fair value of $152 million for certain specified additional distribution rights under the Operating Agreement. In addition, the noncontrolling interest was further reduced by the $400 million special cash distribution to EDF.
	Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interest on the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’S net assets. For the year ended December 31, 2014, Generation reduced by $13 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 $218 million and CENG’s net income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $407 million during the year ended December 31, 2014.
	Exelon and Generation incurred integration-related costs of $26 million for the year ended December 31, 2014. The costs incurred are classified primarily within Operating and maintenance expense in Exelon’s and Generation’s respective Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014.
	See Note 17—Severance for integration-related severance costs incurred by Exelon and Generation during the year ended December 31, 2014.

Accounts_Receivable_Exelon_Gen

Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE)	Accounts Receivable (Exelon, Generation, ComEd, PECO and BGE)
	Accounts receivable at December 31, 2014 and 2013 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:
	2014	Exelon			Generation				ComEd			PECO				BGE
	Unbilled customer revenues	$	1,381		$	823		(a)	$	204		$	140			$	214
	Allowance for uncollectible	(311		)	(60		)		(84		)	(100		)	(c)	(67		)	(d)
	accounts (b)
	2013	Exelon			Generation				ComEd			PECO				BGE
	Unbilled customer revenues	$	1,151		$	584		(a)	$	201		$	161			$	205
	Allowance for uncollectible	(272		)	(57		)		(62		)	(107		)	(c)	(46		)	(d)
	accounts (b)
	_________________________
	(a)	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.
	(b)	Includes the allowance for uncollectible accounts on customer and other accounts receivable.
	(c)	Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below.
	(d)	At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income.
	PECO Installment Plan Receivables (Exelon and PECO). PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $15 million and $19 million as of December 31, 2014 and 2013, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1—Significant Accounting Policies. The allowance for uncollectible accounts balance associated with these receivables at December 31, 2014 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance at December 31, 2013 of $18 million consists of $1 million, $4 million and $13 million for low risk, medium risk and high risk segments, respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement. Installment receivables outstanding as of December 31, 2014 and 2013 include balances not yet presented on the customer bill, accounts currently billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved for in accordance with the methodology discussed in Note 1—Significant Accounting Policies.

Property_Plant_and_Equipment_E

Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)	Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)
	Exelon
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014				2013
		Service Life
		(years)
	Asset Category
	Electric—transmission and distribution	May-90		$	30,157			$	28,123
	Electric—generation	Jan-56		22,911				20,420
	Gas—transportation and distribution	May-90		3,505				3,296
	Common—electric and gas	May-50		1,169				1,101
	Nuclear fuel (a)	8-Jan		5,947				5,196
	Construction work in progress	N/A		2,167				1,890
	Other property, plant and equipment (b)	May-50		973				1,017
	Total property, plant and equipment			66,829				61,043
	Less: accumulated depreciation (c)			14,742				13,713
	Property, plant and equipment, net			$	52,087			$	47,330
	_________________________
	(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.
	(b)	Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation.
	(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.
	The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
	Average Service Life Percentage by Asset Category	2014			2013			2012
	Electric—transmission and distribution	2.93	%		2.91	%		2.76	%
	Electric—generation	3.5	%		3.35	%		3.15	%
	Gas	2.13	%		2.06	%		2.03	%
	Common—electric and gas	7.32	%		7.53	%		7.61	%
	Generation
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014					2013
		Service Life
		(years)
	Asset Category
	Electric—generation	Jan-56		$	22,911		19,004,000,000		$	20,420
	Nuclear fuel (a)	8-Jan		5,947			4,815,000,000		5,196
	Construction work in progress	N/A		1,404			1,352,000,000		1,129
	Other property, plant and equipment (b)	Jun-31		295			374,000,000		400
	Total property, plant and equipment			30,557					27,145
	Less: accumulated depreciation (c)			7,612					7,034
	Property, plant and equipment, net			$	22,945				$	20,111
	_________________________
	(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.
	(b)	Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities.
	(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.
	The annual depreciation provisions as a percentage of average service life for electric generation assets were 3.5%, 3.35% and 3.15% for the years ended December 31, 2014, 2013 and 2012, respectively.
	License Renewals. Generation’s depreciation provisions are based on the estimated useful lives of its generating stations, which assume the renewal of the licenses for all nuclear generating stations (except for Oyster Creek) and the hydroelectric generating stations. As a result, the receipt of license renewals has no impact on the Consolidated Statements of Operations. See Note 3—Regulatory Matters for additional information regarding license renewals.
	ComEd
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014				2013
		Service Life
		(years)
	Asset Category
	Electric—transmission and distribution	May-80		$	18,884			$	17,334
	Construction work in progress	N/A		276				456
	Other property, plant and equipment (a)	39-50		65				60
	Total property, plant and equipment			19,225				17,850
	Less: accumulated depreciation			3,432				3,184
	Property, plant and equipment, net			$	15,793			$	14,666
	_________________________
	(a)	Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively.
	The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 3.05%, 2.97% and 2.79% for the years ended December 31, 2014, 2013 and 2012, respectively.
	PECO
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014				2013
Service Life
(years)
Asset Category
Electric—transmission and distribution	May-65		$	6,886			$	6,669
Gas—transportation and distribution	May-70		2,039				1,932
Common—electric and gas	May-50		618				600
Construction work in progress	N/A		154				101
Other property, plant and equipment (a)	50		21				17
Total property, plant and equipment			9,718				9,319
Less: accumulated depreciation			2,917				2,935
Property, plant and equipment, net			$	6,801			$	6,384
_________________________
(a)	Represents land held for future use and non utility property.
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
Average Service Life Percentage by Asset Category	2014			2013			2012
Electric—transmission and distribution	2.55	%		2.73	%		2.51	%
Gas	1.84	%		1.79	%		1.77	%
Common—electric and gas	5.16	%		6.65	%		7.54	%
BGE
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
	Average		2014				2013
	Service Life
	(years)
Asset Category
Electric—transmission and distribution	May-90		$	6,339			$	6,100
Gas—distribution	May-90		1,761				1,660
Common—electric and gas	May-40		623				578
Construction work in progress	N/A		317				196
Other property, plant and equipment (a)	20		32				32
Total property, plant and equipment			9,072				8,566
Less: accumulated depreciation			2,868				2,702
Property, plant and equipment, net			$	6,204			$	5,864
_______________________
(a)	Represents land held for future use and non utility property.
Average Service Life Percentage by Asset Category	2014			2013			2012
Electric—transmission and distribution	2.96	%		2.91	%		2.92	%
Gas	2.47	%		2.36	%		2.33	%
Common—electric and gas	9.49	%		8.45	%		7.68	%
See Note 1—Significant Accounting Policies for further information regarding property, plant and equipment policies and accounting for capitalized software costs for Exelon, Generation, ComEd, PECO and BGE. See Note 13—Debt and Credit Agreements for further information regarding Exelon’s, ComEd’s, and PECO’s property, plant and equipment subject to mortgage liens.

Impairment_of_Longlived_Assets

Impairment of Long-lived Assets (Exelon and Generation)	12 Months Ended
	Dec. 31, 2014
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Impairment Of Long-Lived Assets (Exelon and Generation)	Impairment of Long-Lived Assets (Exelon and Generation)
	Long-Lived Assets (Exelon and Generation)
	Generation evaluates long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. In 2014, updates to the long-term fundamental energy prices, which included a thorough evaluation of key assumptions including gas prices, load growth, plant retirements and renewable growth, suggested that the carrying value of certain wind assets with market price exposure may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014. As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 million was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	In 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects with market price exposure for either all or a portion of the life of the asset may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of eleven wind projects, primarily located in West Texas and Minnesota, were less than their respective carrying values at September 30, 2013. As a result, long-lived assets held and used with a carrying amount of approximately $75 million were written down to their fair value of $32 million and a pre-tax impairment charge of $43 million, net of the impairment amount attributable to noncontrolling interests for certain of the projects, was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	In 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon's and Generation's Consolidated Balance Sheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset's carrying value exceeds its estimated fair value less costs to sell. Long-lived assets with a carrying amount of approximately $1 billion were written down to their fair value of $556 million and a pre-tax impairment charge of $450 million was recorded in Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
	In 2012, a subsidiary of Generation sold three Maryland generating stations in connection with the Constellation merger. As a result of the transaction, Exelon and Generation recorded a pre-tax impairment charge of $272 million to reflect the difference between the sales price and the carrying value of the generating stations, which was included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	See Note 4—Mergers, Acquisitions, and Dispositions for further information on asset sales.
	In the fourth quarter of 2014, a significant decline in oil prices suggested that the carrying value of certain Upstream assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of various Upstream properties, primarily located in Oklahoma and Texas, were less than their respective carrying values at December 31, 2014. As a result, long-lived assets with a combined net book value of approximately $163 million were written down to their fair value of $39 million and a pre-tax impairment charge of $124 million was recorded in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. After reflecting the impairment, Generation has $189 million of Upstream assets remaining on its Consolidated Balance Sheets at December 31, 2014. Further declines in commodity prices could potentially result in future impairments of the Upstream assets.
	The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.
	Nuclear Uprate Program (Exelon and Generation)
	Generation is engaged in individual projects as part of a planned power uprate program across its nuclear fleet. When economically viable, the projects take advantage of new production and measurement technologies, new materials and application of expertise gained from a half-century of nuclear power operations. Based on ongoing reviews, the nuclear uprate implementation plan was adjusted during 2013 to cancel certain projects. The Measurement Uncertainty Recapture (MUR) uprate projects at the Dresden and Quad Cities nuclear stations were cancelled as a result of the cost of additional plant modifications identified during final design work which, when combined with then current market conditions, made the projects not economically viable. Additionally, the market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. During 2013, Generation recorded a pre-tax charge to Operating and maintenance expense and Interest expense of approximately $111 million and $8 million, respectively, to accrue remaining costs and reverse the previously capitalized costs.
	Like-Kind Exchange Transaction (Exelon)
	Prior to the PECO/Unicom Merger in October 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon, entered into a like-kind exchange transaction pursuant to which approximately $1.6 billion was invested in coal-fired generating station leases located in Georgia and Texas with two separate entities unrelated to Exelon. The generating stations were leased back to such entities as part of the transaction. See Note 14—Income Taxes for further information. For financial accounting purposes, the investments are accounted for as direct financing lease investments. UII holds the leasehold interests in the generating stations in several separate bankruptcy remote, special purpose companies it directly or indirectly wholly owns. The lease agreements provide the lessees with fixed purchase options at the end of the lease terms. If the lessees do not exercise the fixed purchase options, Exelon has the ability to operate the stations and keep or market the power itself or require the lessees to arrange for a third-party to bid on a service contract for a period following the lease term. In any event, Exelon will be subject to residual value risk if the lessees do not exercise the fixed purchase options. This risk is partially mitigated by the fair value of the scheduled payments under the service contract. However, such payments are not guaranteed. Further, the term of the service contract is less than the expected remaining useful life of the plants and, therefore, Exelon’s exposure to residual value risk will not be mitigated by payments under the service contract in this remaining period. In 2000, under the terms of the lease agreements, UII received a prepayment of $1.2 billion for all rent, which reduced the investment in the leases. There are no minimum scheduled lease payments to be received over the remaining term of the leases.
	On February 26, 2014, UII and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases on the generating station located in Texas, as described above, prior to its expiration dates. As a result of the lease termination, UII received a net early termination amount of $335 million from CPS and wrote down the net investment in the CPS long-term lease of $336 million in Investments in Exelon's Consolidated Balance Sheets in 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income in 2014.
	Pursuant to the applicable accounting guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least annually and record an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. Exelon estimates the fair value of the residual values of its direct financing lease investments under the income approach, which uses a discounted cash flow analysis, which takes into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates, and the estimated remaining useful lives of the plants. The estimated fair values also reflect the cash flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions contained in the lease agreements.
	Based on the annual reviews performed in 2014 and 2013, the estimated residual value of Exelon’s direct financing leases for the Georgia generating stations experienced other than temporary declines given reduced long-term energy and capacity price expectations. As a result, Exelon recorded a $24 million and $14 million pre-tax impairment charge in 2014 and 2013, respectively, for these stations. These impairment charges were recorded in Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the Consolidated Statements of Operations and Comprehensive Income, respectively. Changes in the assumptions described above could potentially result in future impairments of Exelon’s direct financing lease investments, which could be material. Through December 31, 2014, no events have occurred that would require Exelon to review the estimated residual values of its direct financing lease investments subsequent to the review performed in the second quarter of 2014.
	At December 31, 2014 and 2013, the components of the net investment in long-term leases were as follows:
		December 31, 2014		December 31, 2013
	Estimated residual value of leased assets	$	685	$	1,465
	Less: unearned income	324		767
	Net investment in long-term leases	$	361	$	698

Jointly_Owned_Electric_Utility

Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment [Abstract]
Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)	Jointly Owned Electric Utility Plant (Exelon, Generation, PECO and BGE)
	Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2014 and 2013 were as follows:
		Nuclear generation												Fossil fuel generation							Transmission					Other
		Quad Cities			Peach			Salem (a)			Nine Mile Point Unit 2(g)			Keystone		Conemaugh		Wyman			PA (b)		DE/NJ (c)			Other (d)
					Bottom
														(f)		(f)
	Operator	Generation			Generation			PSEG			Generation			GenOn		GenOn		FP&L			First		PSEG
								Nuclear													Energy
	Ownership interest	75		%	50		%	42.59		%	82		%	—		—		5.89		%	Various		42.55		%	44.24		%
	Exelon’s share at December 31, 2014:
	Plant (e)	$	995		$	1,095		$	531		$	676		$	—	$	—	$	3		$	14	$	64		$	2
	Accumulated	266			343			150			14			—		—		3			7		34			1
	depreciation (e)
	Construction work	15			133			29			48			—		—		—			—		—			—
	in progress
	Exelon’s share at December 31, 2013:
	Plant (e)	$	941		$	883		$	501		$	—		$	725	$	399	$	3		$	14	$	64		$	2
	Accumulated depreciation (e)	226			326			134			—			268		220		3			7		34			1
	Construction work	27			174			24			—			6		121		—			—		—			—
	in progress
	________________________
	(a)	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2014 and 2013.
	(b)	PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.
	(c)	PECO owns a 42.55% share in 131 miles of 500kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.
	(d)	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.
	(e)	Excludes asset retirement costs.
	(f)	As of December 31, 2014, Generation sold its ownership interest in Keystone and Conemaugh. At December 31, 2013, Generation held 41.98% and 31.28% ownership interest in Keystone and Conemaugh, respectively. See Note 4—Mergers, Acquisitions, and Dispositions for additional information.
	(g)	On April 1, 2014, Generation assumed operational control of CENG's nuclear fleet, and as of that date, CENG’s operations are consolidated into Generation’s financial statements. As of December 31, 2013, Generation’s ownership interest in CENG, including Nine Mile Point, was treated as an equity method investment, and thus did not represent an undivided Interest. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.
	Exelon’s, Generation’s, PECO’s and BGE’s undivided ownership interests are financed with their funds and all operations are accounted for as if such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO’s and BGE’s share of direct expenses of the jointly owned plants are included in Purchased power and fuel and Operating and maintenance expenses on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses on PECO’s and BGE’s Consolidated Statements of Operations and Comprehensive Income.

Intangible_Assets_Exelon_Gener

Intangible Assets (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Intangible Assets (Exelon, Generation, ComEd, PECO and BGE)	Intangible Assets (Exelon, Generation, ComEd and PECO)
	Goodwill
	Exelon’s and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2014 and 2013 were as follows:
		ComEd												Generation								Exelon
		Gross				Accumulated				Carrying				Gross				Carrying				Gross				Accumulated				Carrying
		Amount (a)				Impairment				Amount				Amount				Amount				Amount				Impairment				Amount
						Losses																				Losses
	Balance, January 1, 2013	$	4,608			$	1,983			$	2,625			$	—			$	—			$	4,608			$	1,983			$	2,625
	Goodwill from business combination	—				—				—				47				47				47				—				47
	Balance, December 31, 2014	$	4,608			$	1,983			$	2,625			$	47			$	47			$	4,655			$	1,983			$	2,672
	_______________________
	(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.
	Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of the ComEd reporting unit below its carrying amount. Under the authoritative guidance for goodwill, a reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. A component of an operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are regularly reviewed by segment management. ComEd has a single operating segment for its combined business. There is no level below this operating segment for which operating results are regularly reviewed by segment management. Therefore, ComEd’s operating segment is considered its only reporting unit.
	Entities assessing goodwill for impairment have the option of first performing a qualitative assessment before calculating the fair value of the reporting unit (i.e., step one of the two-step fair value based impairment test). If an entity determines, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not less than the carrying amount, the two-step fair value based impairment test is required. Otherwise, no further testing is required.
	If an entity bypasses the qualitative assessment or performs the qualitative assessment, but determines that it is more likely than not that its fair value is less than its carrying amount, a quantitative two-step, fair value based test is performed. The first step compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step is performed. The second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation in order to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Any goodwill impairment charge at ComEd will affect Exelon’s consolidated results of operations.
	ComEd’s valuation approach is based on a market participant view, pursuant to authoritative guidance for fair value measurement, and utilizes a weighted combination of a discounted cash flow analysis and a market multiples analysis. The discounted cash flow analysis relies on a single scenario reflecting “base case” or “best estimate” projected cash flows for ComEd’s business and includes an estimate of ComEd’s terminal value based on these expected cash flows using the generally accepted Gordon Dividend Growth formula, which derives a valuation using an assumed perpetual annuity based on the entity’s residual cash flows. The discount rate is based on the generally accepted Capital Asset Pricing Model and represents the weighted average cost of capital of comparable companies. The market multiples analysis utilizes multiples of business enterprise value to earnings, before interest, taxes, depreciation and amortization (EBITDA) of comparable companies in estimating fair value. Significant assumptions used in estimating the fair value include discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd’s business and the fair value of debt. Management performs a reconciliation of the sum of the estimated fair value of all Exelon reporting units to Exelon’s enterprise value based on its trading price to corroborate the results of the discounted cash flow analysis and the market multiple analysis.
	2014 Goodwill Impairment Assessment. Pursuant to authoritative guidance, ComEd is required to test its goodwill for impairment annually and more frequently if an event occurs or circumstances change that suggest an impairment is more likely than not. ComEd performed a qualitative assessment as of November 1, 2014, for its 2014 annual goodwill impairment assessment and determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment. As part of its qualitative assessment, ComEd evaluated, among other things, management’s best estimate of projected operating and capital cash flows for ComEd’s business as well as changes in certain market conditions, including the discount rate and EBITDA multiples, while also considering the passing margin from its last quantitative assessment performed as of November 1, 2013.
	Prior Goodwill Impairment Assessments. Management concluded the remeasurement of the like-kind exchange position and the charge to ComEd’s earnings in the first quarter of 2013 triggered an interim goodwill impairment assessment and, as a result, ComEd tested its goodwill for impairment as of January 31, 2013. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required.
	ComEd performed a quantitative assessment as of November 1, 2013, for its 2013 annual goodwill impairment assessment. The first step of the annual impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required.
	In both the interim and annual assessments, the discounted cash flow analysis reflected Exelon’s indemnity to hold ComEd harmless from any unfavorable impacts of the after-tax interest amounts related to the like-kind exchange position on ComEd’s equity. While neither the interim nor the annual assessments indicated an impairment of ComEd’s goodwill, certain assumptions used to estimate the fair value of ComEd are highly sensitive to changes. Adverse regulatory actions, such as early termination of EIMA, or changes in significant assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows from ComEd’s business, and the fair value of debt could potentially result in a future impairment of ComEd’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2013, the estimated fair value of ComEd would have needed to decrease by more than 10% for ComEd to fail the first step of the impairment test.
	Management concluded that the May 2012 ICC final Order in ComEd’s 2011 formula rate proceeding triggered an interim goodwill impairment assessment and, as a result, ComEd tested its goodwill for impairment as of May 31, 2012. The first step of the interim impairment assessment comparing the estimated fair value of ComEd to its carrying value, including goodwill, indicated no impairment of goodwill; therefore, the second step was not required. ComEd performed a qualitative assessment as of November 1, 2012, for its 2012 annual goodwill impairment assessment and determined that its fair value was not more likely than not less than its carrying value. Therefore, ComEd did not perform a quantitative assessment. As part of its qualitative assessment, ComEd evaluated, among other things, management’s best estimate of projected operating and capital cash flows for ComEd’s business (including the impacts of the May 2012 Order) as well as changes in certain other market conditions, such as the discount rate and EBITDA multiples.
	Other Intangible Assets
	Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and Other long-term assets and liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 2014:
		Weighted													Estimated amortization expense
		Average
		Amortization
		Years (h)	Gross				Accumulated				Net				2015				2016				2017				2018				2019
							Amortization
	Exelon and Generation
	Unamortized Energy Contracts (a)
	Exelon Wind (b)	18	$	224			$	(55	)		$	169			$	14			$	14			$	14			$	14			$	14
	Antelope Valley (c)	25	190				(12		)		178				8				8				8				8				8
	Constellation (d)	1.5	1,499				(1,451		)		48				19				(31		)		(21		)		11				8
	CENG (e)	1.7	(97		)		29				(68		)		(20		)		(11		)		(15		)		(18		)		(15		)
	Integrys (d)	2.4	6				(5		)		1				(8		)		6				1				1				—
	Customer Relationships
	Constellation (d)	12.4	214				(58		)		156				18				18				18				18				17
	Integrys (d)	10	48				(1		)		47				5				5				5				5				5
	Trade Names
	Constellation (d)	10	243				(79		)		164				23				23				23				23				23
	ComEd
	Chicago settlement—1999 agreement (f)	21.8	100				(79		)		21				3				3				4				4				4
	Chicago settlement—2003 agreement (g)	17.9	62				(40		)		22				4				4				3				3				3
	Total intangible assets		$	2,489			$	(1,751	)		$	738			$	66			$	39			$	40			$	69			$	67
	_________________________
	(a)	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.
	(b)	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.
	(c)	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.
	(d)	See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions.
	(e)	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.
	(f)	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.
	(g)	In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago’s behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in Other deferred credits and other liabilities, and other long-term liabilities on Exelon's and ComEd's Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.
	(h)	Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.
	The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2014, 2013 and 2012:
	For the Year Ended December 31,	Exelon (a)				Generation (a)				ComEd
	2014	$	179			$	179			$	7
	2013	478				550				7
	2012	1,150				1,145				7
	_________________________
	(a) At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income
	Acquired Intangible Assets
	Accounting guidance for business combinations requires the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.
	Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy contracts that Generation has acquired. The valuation of unamortized energy contracts was estimated by applying either the market approach or the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information generated by market transactions involving comparable transactions were available. Otherwise, the income approach, which is based upon discounted projected future cash flows associated with the underlying contracts, was utilized. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The Exelon Wind unamortized energy contracts are amortized on a straight line basis over the period in which the associated contract revenues are recognized as a decrease in Operating revenue within Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income. In the case of Antelope Valley, Constellation, CENG and Integrys, the fair value amounts are amortized over the life of the contract in relation to the present value of the underlying cash flows as of the acquisition dates through either Purchase power and fuel expense or Operating revenues within Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.
	Customer Relationships. The customer relationship intangible was determined based on a “multi-period excess method” of the income approach. Under this method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account expected contract renewals based on customer attrition rates and costs to retain those customers. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the customer attrition rate and the discount rate. The accounting guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic benefit. The amortization of the customer relationships is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is determined to be the present value of the license fees avoided by owning the assets. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years. The amortization of the trade name is recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, ComEd and PECO).
Exelon’s, Generation’s, ComEd’s and PECO’s other intangible assets, included in Other current assets and Other deferred debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon, Generation and ComEd) and AECs (Exelon and PECO). Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract inception. Revenue for RECs that are part of a bundled power sale is recognized when the power is produced and delivered to the customer. As of December 31, 2014, and 2013, PECO had current AECs of $13 million and $19 million, respectively. PECO had no noncurrent AECs and $5 million as of December 31, 2014, and 2013, respectively. As of December 31, 2014, and 2013, Generation had current RECs of $191 million and $158 million, respectively, and $44 million of noncurrent REC's as of December 31, 2014. As of December 31, 2014, and 2013, ComEd, had current RECs of $4 million and $3 million, respectively. See Note 3—Regulatory Matters and Note 22—Commitments and Contingencies for additional information on RECs and AECs.

Fair_Value_of_Financial_Assets

Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
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 December 31, 2014 and 2013:
	Exelon
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	463			$	3			$	448			$	12			$	463			$	344			$	344
	Long-term debt (including amounts due within one year)	21,164				1,208				20,417				1,311				22,936				19,132				19,751
	Long-term debt to financing trusts	648				—				—				648				648				648				631
	SNF obligation	1,021				—				833				—				833				1,021				790
	Generation
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	36			$	—			$	24			$	12			$	36			$	22			$	22
	Long-term debt (including amounts due within one year)	8,266				—				7,511				1,311				8,822				7,729				7,648
	SNF obligation	1,021				—				833				—				833				1,021				790
	ComEd
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	304			$	—			$	304			$	—			$	304			$	184			$	184
	Long-term debt (including amounts due within one year)	5,958				—				6,788				—				6,788				5,675				6,255
	Long-term debt to financing trust	206				—				—				213				213				206				202
	PECO
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Long-term debt (including amounts due within one year)	$	2,246			$	—			$	2,537			$	—			$	2,537			$	2,197			$	2,358
	Long-term debt to financing trusts	184				—				—				199				199				184				180
	BGE
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	123			$	3			$	120			$	—			$	123			$	138			$	138
	Long-term debt (including amounts due within one year)	1,942				—				2,178				—				2,178				2,011				2,148
	Long-term debt to financing trusts	258				—				—				236				236				258				249
	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 year ended December 31, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.
	Generation and Exelon
	The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013:
		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
	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 securities	—					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 funds 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
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
	Generation																Exelon
As of December 31, 2013	Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3			Total
Assets
Cash equivalents (a)	$	1,006			$	—			$	—			$	1,006			$	1,230			$	—			$	—		$	1,230
Nuclear decommissioning trust fund investments
Cash equivalents	459				—				—				459				459				—				—			459
Equities
Domestic	1,642				2,271				—				3,913				1,642				2,271				—			3,913
Foreign	249				—				—				249				249				—				—			249
Equity funds subtotal	1,891				2,271				—				4,162				1,891				2,271				—			4,162
Fixed income
Corporate debt securities	—				1,753				31				1,784				—				1,753				31			1,784
U.S. Treasury and agencies	882				—				—				882				882				—				—			882
Foreign governments	—				87				—				87				—				87				—			87
State and municipal debt	—				294				—				294				—				294				—			294
Other	—				75				—				75				—				75				—			75
Fixed income subtotal	882				2,209				31				3,122				882				2,209				31			3,122
Middle market lending	—				—				314				314				—				—				314			314
Private equity	—				—				5				5				—				—				5			5
Other	—				14				—				14				—				14				—			14
Nuclear decommissioning trust funds subtotal (b)	3,232				4,494				350				8,076				3,232				4,494				350			8,076
Pledged assets for Zion Station
decommissioning
Cash equivalents	—				26				—				26				—				26				—			26
Equities	16				—				—				16				16				—				—			16
Fixed income
U.S. Treasury and agencies	45				4				—				49				45				4				—			49
Corporate debt	—				227				—				227				—				227				—			227
State and municipal debt	—				20				—				20				—				20				—			20
Fixed income subtotal	45				251				—				296				45				251				—			296
Middle market lending	—				—				112				112				—				—				112			112
Other	—				1				—				1				—				1				—			1
Pledged assets for Zion Station	61				278				112				451				61				278				112			451
decommissioning subtotal (c)
Rabbi trust investments (d)
Cash equivalents	—				—				—				—				2				—				—			2
Mutual funds (e)	13				—				—				13				54				—				—			54
Rabbi trust investments subtotal	13				—				—				13				56				—				—			56
Commodity derivative assets													—															—
Economic hedges	493				2,582				885				3,960				493				2,582				885			3,960
Proprietary trading	324				1,315				122				1,761				324				1,315				122			1,761
Effect of netting and allocation of collateral (f)	(863		)		(3,131		)		(430		)		(4,424		)		(863		)		(3,131		)		(430		)	(4,424		)
Commodity derivative assets subtotal	(46		)		766				577				1,297				(46		)		766				577			1,297
Interest rate and foreign currency derivative	30				32				—				62				30				39				—			69
assets
Effect of netting and allocation of collateral	(30		)		(2		)		—				(32		)		(30		)		(2		)		—			(32		)
Interest rate and foreign currency derivative	—				30				—				30				—				37				—			37
assets subtotal
Other investments	—				—				15				15				—				—				15			15
Total assets	4,266				5,568				1,054				10,888				4,533				5,575				1,054			11,162
Liabilities
Commodity derivative liabilities
Economic hedges	(540		)		(1,890		)		(397		)		(2,827		)		(540		)		(1,890		)		(590		)	(3,020		)
Proprietary trading	(328		)		(1,256		)		(119		)		(1,703		)		(328		)		(1,256		)		(119		)	(1,703		)
Effect of netting and allocation of collateral (f)	869				3,007				404				4,280				869				3,007				404			4,280
Commodity derivative liabilities subtotal	1				(139		)		(112		)		(250		)		1				(139		)		(305		)	(443		)
Interest rate and foreign currency derivative	(31		)		(13		)		—				(44		)		(31		)		(17		)		—			(48		)
liabilities
Effect of netting and allocation of collateral	31				1				—				32				31				1				—			32
Interest rate and foreign currency derivative	—				(12		)		—				(12		)		—				(16		)		—			(16		)
liabilities subtotal
Deferred compensation obligation	—				(29		)		—				(29		)		—				(114		)		—			(114		)
Total liabilities	1				(180		)		(112		)		(291		)		1				(269		)		(305		)	(573		)
Total net assets	$	4,267			$	5,388			$	942			$	10,597			$	4,534			$	5,306			$	749		$	10,589
_________________________
(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
(b)	Excludes net liabilities of $5 million at both December 31, 2014 and 2013. 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 $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(d)	Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation.
(e)	The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013.
(f)	Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/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. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value on the Utilities' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013:
	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	—				(8		)		—				(8		)		—				(15		)		—			(15		)		—				(5		)	—		(5		)
obligation
Mark-to-market derivative	—				—				(207		)		(207		)		—				—				—			—				—				—			—		—
liabilities (b)
Total liabilities	—				(8		)		(207		)		(215		)		—				(15		)		—			(15		)		—				(5		)	—		(5		)
Total net assets (liabilities)	$	25			$	(8	)		$	(207	)		$	(190	)		$	21			$	(15	)		$	—		$	6			$	108			$	(5	)	$	—	$	103
	ComEd																PECO															BGE
As of December 31, 2013	Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3			Total				Level 1				Level 2			Level 3		Total
Assets
Cash equivalents	$	—			$	—			$	—			$	—			$	175			$	—			$	—		$	175			$	31			$	—		$	—	$	31
Rabbi trust investments in Mutual funds (a)	5				—				—				5				9				—				—			9				6				—			—		6
Total assets	5				—				—				5				184				—				—			184				37				—			—		37
Liabilities
Deferred compensation	—				(8		)		—				(8		)		—				(17		)		—			(17		)		—				(6		)	—		(6		)
obligation
Mark-to-market derivative	—				—				(193		)		(193		)		—				—				—			—				—				—			—		—
liabilities (b)
Total liabilities	—				(8		)		(193		)		(201		)		—				(17		)		—			(17		)		—				(6		)	—		(6		)
Total net assets (liabilities)	$	5			$	(8	)		$	(193	)		$	(196	)		$	184			$	(17	)		$	—		$	167			$	37			$	(6	)	$	—	$	31
_________________________
(a)	At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013.
(b)	The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2014 and 2013:
	Generation																				ComEd							Exelon
For The Year Ended December 31, 2014	Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Other- ComEd (b)				Eliminated in Consolidation			Total
	Decommissioning				for Zion Station				Derivatives				Investments
	Trust Fund				Decommissioning
	Investments
Balance as of January 1, 2014	$	350			$	112			$	465			$	15			$	942			$	(193	)		$	—		$	749
Total realized / unrealized gains (losses)
Included in net income	6				—				526			(a)	—				532				—				—			532
Included in noncurrent payables to affiliates	14				—				—				—				14				—				(14		)	—
Included in payable for Zion Station decommissioning	—				2				—				—				2				—				—			2
Included in regulatory assets/liabilities	—				—				—				—				—				(14		)		14			—
Change in collateral	—				—				198				—				198				—				—			198
Purchases, sales, issuances and settlements
Purchases	400				120				76			(c)	2				598				—				—			598
Sales	(15		)		(50		)		(7		)		(8		)		(80		)		—				—			(80		)
Settlements	(64		)		—				—				—				(64		)		—				—			(64		)
Transfers into Level 3	—				—				(7		)		—				(7		)		—				—			(7		)
Transfers out of Level 3	—				—				(201		)		(6		)		(207		)		—				—			(207		)
Balance as of December 31, 2014	$	691			$	184			$	1,050			$	3			$	1,928			$	(207	)		$	—		$	1,721
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2014	$	4			$	—			$	640			$	—			$	644			$	—			$	—		$	644
	Generation																				ComEd							Exelon
For The Year Ended December 31, 2013	Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Other- ComEd (b)(f)				Eliminated in Consolidation			Total
	Decommissioning				for Zion Station				Derivatives (d)				Investments
	Trust Fund				Decommissioning
	Investments
Balance as of January 1, 2013	$	183			$	89			$	660			$	17			$	949			$	(293	)		$	—		$	656
Total realized / unrealized gains (losses)																												—
Included in net income	2				—				(51		)	(a)	—				(49		)		—				7			(42		)
Included in other	—				—				(219		)		2				(217		)		—				219			2
comprehensive income
Included in noncurrent payables to affiliates	8				—				—				—				8				—				(8		)	—
Included in payable for Zion Station decommissioning	—				—				—				—				—				—				—			—
Included in regulatory assets/liabilities	—				—				—				—				—				100				(218		)	(118		)
Change in collateral	—				—				7				—				7				—				—			7
Purchases, sales, issuances and settlements
Purchases	203				62				28				4				297				—				—			297
Sales	(28		)		(39		)		(11		)		(8		)		(86		)		—				—			(86		)
Settlements	(18		)		—				—				—				(18		)		—				—			(18		)
Transfers into Level 3	—				—				86			(e)	1				87				—				—			87
Transfers out of Level 3	—				—				(35		)		(1		)		(36		)		—				—			(36		)
Balance as of December 31, 2013	$	350			$	112			$	465			$	15			$	942			$	(193	)		$	—		$	749
The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2013	$	1			$	—			$	156			$	—			$	157			$	—			$	—		$	168
_________________________
(a)	Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively.
(b)	Includes $13 million and $133 million of decreases in fair value and $1 million and $(7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively.
(c)	Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition.
(d)	Includes $11 million of decreases in fair value and realized gains due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
(e)	Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations.
(f)	Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2014 and 2013:
	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 year ended December 31, 2014	$	614			$	(88	)		$	6			$	614			$	(88	)		$	6
Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014	$	663			$	(23	)		$	4			$	663			$	(23	)		$	4
	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 year ended December 31, 2013	$	(158	)		$	107			$	2			$	(152	)		$	108			$	2
Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2013	$	30			$	126			$	1			$	40			$	127			$	1
_________________________
(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 December 31, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $290 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.
See Note 15—Asset Retirement Obligations 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 investments in the Rabbi trusts are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of mutual funds. These 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.
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 12—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 notional investments are comprised primarily of mutual funds, which are based on observable market prices. However, 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 is generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.75 and $0.34 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 7A.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities.
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 12—Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.
The table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade	Fair Value at December 31,2014				Valuation		Unobservable		Range
					Technique		Input
Mark-to-market derivatives—Economic hedges (Generation) (a)(c)	$	893			Discounted		Forward power price		$15	-	$120	(d)
					Cash Flow
							Forward gas price		$1.52	-	$14.02	(d)
					Option Model		Volatility percentage		8%	-	257%
Mark-to-market derivatives—Proprietary trading (Generation) (a)(c)	$	(15	)		Discounted		Forward power price		$15	-	$117	(d)
					Cash Flow
Mark-to-market derivatives	$	(207	)		Discounted		Forward heat rate (b)		8x	-	9x
(ComEd)					Cash Flow
							Marketability reserve		3.50%	-	8%
							Renewable factor		86%	-	126%
_________________________
(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
(c)	The fair values do not include cash collateral 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.
Type of trade	Fair Value at December 31, 2013				Valuation		Unobservable		Range
					Technique		Input
Mark-to-market derivatives—Economic hedges (Generation) (a)(c)	$	488			Discounted		Forward power price		$8	-	$176	(d)
					Cash Flow
							Forward gas price		$2.98	-	$16.63	(d)
					Option Model		Volatility percentage		15%	-	142%
Mark-to-market derivatives—	$	3			Discounted		Forward power price		$10	-	$176	(d)
Proprietary trading (Generation) (a)(c)					Cash Flow
Mark-to-market derivatives	$	(193	)		Discounted		Forward heat rate (b)		8x	-	9x
(ComEd)					Cash Flow
							Marketability reserve		3.50%	-	8%
							Renewable factor		84%	-	128%
__________________________
(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
(c)	The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013
(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 $100 and $5.70, respectively.
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)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Financial 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 Exelon generates differs from the amount of energy it has contracted to sell, the Registrants are exposed to market fluctuations in the prices of electricity, fossil fuels and other commodities. The Registrants employ established policies and procedures to manage their risks associated with market fluctuations 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. 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 purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
	In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31, 2014, the percentage of expected generation hedged for the major reportable segments was 93%-96%, 61%-64% and 31%-34% for 2015, 2016, and 2017, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation (which reflects the divestiture impact of Quail Run). 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. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for more detail regarding divestitures.
	On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC's December 18, 2013 Order approved the reduction of ComEd's commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reductions was approved in March 2014. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3—Regulatory Matters for additional information.
	PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 3—Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.
	PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 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 10,571 GWh, 8,762 GWh and 12,958 GWh for the years ended December 31, 2014, 2013 and 2012, 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 may also utilize fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2014, Exelon and Generation had $1,450 million and $550 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $3,070 million and $770 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 approximate $8 million decrease in Exelon Consolidated pre-tax income for the year ended December 31, 2014. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedges as of December 31, 2014:
		Generation																				Other													Exelon
	Description	Derivatives				Economic				Proprietary				Collateral				Subtotal				Derivatives				Economic			Collateral			Subtotal			Total
		Designated as				Hedges				Trading  (a)				and Netting (b)								Designated as				Hedges			and Netting (b)
		Hedging																				Hedging
		Instruments																				Instruments
	Mark-to-market derivative	$	7			$	7			$	20			$	(22	)		$	12			$	3			$	—		$	—		$	3		$	15
	assets (current assets)
	Mark-to-market derivative	1				5				7				(7		)		6				20				1			(19		)	2			8
	assets (noncurrent assets)
	Total mark-to-market	8				12				27				(29		)		18				23				1			(19		)	5			23
	derivative assets
	Mark-to-market derivative	(8		)		(2		)		(14		)		25				1				—				—			—			—			1
	liabilities (current liabilities)
	Mark-to-market derivative	(4		)		—				(9		)		10				(3		)		(29		)		(101		)	19			(111		)	(114		)
	liabilities (noncurrent liabilities)
	Total mark-to-market	(12		)		(2		)		(23		)		35				(2		)		(29		)		(101		)	19			(111		)	(113		)
	derivative 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 between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
	(b)	Represents the netting of fair value balances with the same counterparty and any associated cash collateral.
	The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2013:
		Generation																				Other				Exelon
	Description	Derivatives				Economic				Proprietary				Collateral				Subtotal				Derivatives				Total
		Designated as				Hedges				Trading (a)				and Netting (b)								Designated as
		Hedging																				Hedging
		Instruments																				Instruments
	Mark-to-market derivative	$	—			$	3			$	15			$	(19	)		$	(1	)		$	—			$	(1	)
	assets (current assets)
	Mark-to-market derivative	26				3				15				(13		)		31				7				38
	assets (noncurrent assets)
	Total mark-to-market	26				6				30				(32		)		30				7				37
	derivative assets
	Mark-to-market derivative	(1		)		(1		)		(18		)		19				(1		)		—				(1		)
	liabilities (current liabilities)
	Mark-to-market derivative	(10		)		(1		)		(13		)		13				(11		)		(4		)		(15		)
	liabilities (noncurrent liabilities)
	Total mark-to-market	(11		)		(2		)		(31		)		32				(12		)		(4		)		(16		)
	derivative liabilities
	Total mark-to-market	$	15			$	4			$	(1	)		$	—			$	18			$	3			$	21
	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 between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
	(b)	Represents the netting of fair value balances with the same counterparty and any associated cash collateral.
	Fair Value Hedges. For derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk are recognized in current earnings. Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
				Year Ended December 31,
		Income Statement Location		2014				2013				2012				2014				2013				2012
				Gain (Loss) on Swaps												Gain (Loss) on Borrowings
Generation	Interest expense  (a)		$	(16	)		$	(15	)		$	(6	)		$	2			$	(6	)		$	—
Exelon	Interest expense		$	3			$	(24	)		$	(9	)		$	15			$	(3	)		$	(1	)
______________________
(a)	For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively.
During 2014, Exelon entered into $100 million and $75 million of notional amounts of fixed-to-floating fair value hedges related to interest rate swaps, which expire in 2019 and 2020, respectively. At December 31, 2014, Exelon and Generation had total 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. At December 31, 2013, Exelon and Generation had outstanding fixed-to-floating fair value hedges related to interest rate swaps of $1,275 million and $550 million, with a derivative asset of $26 million and $23 million, respectively. During the years ended December 31, 2014 and 2013, the impact on the results of operations, as a result of the ineffectiveness from fair value hedges, was a $18 million gain and $2 million gain, respectively.
Cash Flow Hedges. In connection with the DOE guaranteed loan for the Antelope Valley project financings, as discussed in Note 13—Debt and Credit Agreements, Generation entered into a floating-to-fixed forward starting interest rate swap with a notional amount of $485 million and a mandatory early termination date of September 30, 2014. The interest rate swap was designated as a cash flow hedge, and as a result, unrealized losses of approximately $21 million have been recorded to Accumulated OCI, net on Exelon's and Generation’s Consolidated Balance Sheets. During the third quarter of 2014, the interest rate swap was terminated consistent with the agreements. The unrealized loss of $21 million will be amortized into Interest expense on Exelon's and Generation’s Consolidated Statements of Operations and Comprehensive Income over the term of the DOE guaranteed loan.
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 for additional information regarding the financing. The swaps have a total notional amount of $26 million as of December 31, 2014 and expire in 2027. After the closing of the Constellation merger, the swaps were re-designated as cash flow hedges. At December 31, 2014, the subsidiary had a $3 million derivative liability related to these swaps.
During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swap has a notional amount of $26 million as of December 31, 2014, and expires in 2030. This swap is designated as a cash flow hedge. At December 31, 2014, the derivative asset related to the swap was immaterial.
During the first quarter of 2014, ExGen Renewables I, LLC, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $213 million as of December 31, 2014 and expire in 2020. The swaps are designated as cash flow hedges. At December 31, 2014, the subsidiary had a $2 million derivative liability related to the swaps.
During the third quarter of 2014, ExGen Texas Power, LLC, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its interest rate exposure in connection with the long-term borrowing. See Note 13—Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $505 million as of December 31, 2014 and expire in 2019. The swap was designated as a cash flow hedge in the fourth quarter of 2014. At December 31, 2014, the subsidiary had a $8 million derivative liability related to the swap.
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 refinance of existing debt. The swaps are designated as cash flow hedges. At December 31, 2014, Exelon had a $28 million derivative liability related to the swaps.
During the years ended December 31, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.
Economic Hedges. During 2014, Exelon entered into $1,900 million of floating-to-fixed forward starting interest rate swaps to manage a portion of the interest rate exposure associated with the anticipated future debt issuance related to the proposed PHI acquisition. At December 31, 2014, Exelon had a $100 million derivative liability related to the swaps.
During the fourth quarter, fixed-to-floating interest rate swaps, which were marked-to-market, acquired as part of the Constellation merger, expired for Exelon and Generation. The notional amounts of the swaps was $150 million.
At December 31, 2014, Generation had $126 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $349 million in notional amounts of foreign currency exchange rate swaps that are marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.
Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon Generation, ComEd, PECO and BGE)
Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Notes to the Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheet. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencing contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. Generation’s use of cash collateral is generally unrestricted unless Generation is downgraded below investment grade (i.e. to BB+ or Ba1). In the table below, Generation’s energy related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral including initial margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2014 and 2013, $8 million and $10 million of cash collateral posted, respectively, was not offset against derivative positions because such collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were no positions to offset. Excluded from the tables below are economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e. to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in a non affiliate major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2014:
	Generation																ComEd				Exelon
Derivatives	Economic				Proprietary				Collateral				Subtotal (b)				Economic				Total
	Hedges				Trading				and Netting (a)								Hedges  (c)				Derivatives
Mark-to-market	$	4,992			$	456			$	(4,184	)		$	1,264			$	—			$	1,264
derivative assets (current assets)
Mark-to-market	1,821				56				(1,112		)		765				—				765
derivative assets (noncurrent assets)
Total mark-to-market	6,813				512				(5,296		)		2,029				—				2,029
derivative assets
Mark-to-market	(4,947		)		(468		)		5,200				(215		)		(20		)		(235		)
derivative liabilities (current liabilities)
Mark-to-market	(1,540		)		(64		)		1,502				(102		)		(187		)		(289		)
derivative liabilities (noncurrent liabilities)
Total mark-to-market	(6,487		)		(532		)		6,702				(317		)		(207		)		(524		)
derivative liabilities
Total mark-to-market	$	326			$	(20	)		$	1,406			$	1,712			$	(207	)		$	1,505
derivative 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 $(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.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2013:
	Generation																ComEd				Exelon
Derivatives	Economic				Proprietary				Collateral				Subtotal (b)				Economic				Total
	Hedges				Trading				and								Hedges (c)				Derivatives
									Netting  (a)
Mark-to-market	$	2,616			$	1,476			$	(3,364	)		$	728			$	—			$	728
derivative assets (current assets)
Mark-to-market	1,344				285				(1,060		)		569				—				569
derivative assets (noncurrent assets)
Total mark-to-market	3,960				1,761				(4,424		)		1,297				—				1,297
derivative assets
Mark-to-market	(2,023		)		(1,410		)		3,292				(141		)		(17		)		(158		)
derivative liabilities (current liabilities)
Mark-to-market	(804		)		(293		)		988				(109		)		(176		)		(285		)
derivative liabilities (noncurrent liabilities)
Total mark-to-market	(2,827		)		(1,703		)		4,280				(250		)		(193		)		(443		)
derivative liabilities
Total mark-to-market	$	1,133			$	58			$	(144	)		$	1,047			$	(193	)		$	854
derivative 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 $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.
(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. Approximately $2 million of these net pre-tax unrealized gains within Accumulated OCI are expected to be reclassified from Accumulated OCI during the next twelve months by Generation. See Note 13—Debt and Credit Agreements for information about reclassifications from Accumulated OCI on interest rate swap activity that occurred after December 31, 2014.
The tables below provide the activity of Accumulated OCI related to cash flow hedges for the years ended December 31, 2014 and 2013, 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.
	Income Statement		Total Cash Flow Hedge OCI  Activity,
	Location		Net of Income Tax
			Generation				Exelon
			Energy-Related				Total Cash Flow
			Hedges				Hedges
Accumulated OCI derivative gain at January 1, 2013			$	532		(a)(d)	$	368
Effective portion of changes in fair value			—				29			(e)
Reclassifications from accumulated OCI to net	Operating Revenues		(413		)	(c)(b)	(277		)
income
Ineffective portion recognized in income	Operating Revenues		—				—
Accumulated OCI derivative gain at December 31, 2013			119			(d)	120
Effective portion of changes in fair value			—				(31		)	(e)
Reclassifications from accumulated OCI to net income	Operating Revenues		(117		)	(b)	(117		)
Accumulated OCI derivative gain at December 31, 2014			$	2		(d)	$	(28	)
_______________________
(a)	Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012.
(b)	Amount is net of related income tax expense of $78 million and $270 million for the years ended December 31, 2014 and 2013, respectively.
(c)	Includes $133 million of losses, net of taxes, reclassified from Accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the year ended December 31, 2013.
(d)	Excludes $20 million and $5 million,of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2014 and 2013, respectively.
(e)	Includes $15 million and $15 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the years ended December 31, 2014 and 2013, respectively.
During the years ended December 31, 2014, 2013, and 2012, Generation’s former energy-related cash flow hedge activity impact to pre-tax earnings based on the reclassification adjustment from Accumulated OCI to earnings was a $195 million, $683 million and $1,368 million pre-tax gain, respectively. Given that the cash flow hedges had primarily consisted of forward power sales and power swaps and did not include power and gas options or sales, the ineffectiveness of Generation’s cash flow hedges was primarily the result of differences between the locational settlement prices of the cash flow hedges and the hedged generating units. Changes in cash flow hedge ineffectiveness were losses of $5 million for the year ended December 31, 2012.
The effect of Exelon’s former energy-related cash flow hedge activity impact on pre-tax earnings based on the reclassification adjustment from Accumulated OCI to earnings was a $195 million, $464 million and $747 million pre-tax gain for the years ended December 31, 2014, 2013 and 2012, respectively. Changes in cash flow hedge ineffectiveness, primarily due to changes in market prices, were losses of $5 million for the year ended December 31, 2012. 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 Constellation merger date.
Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. 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 years ended December 31, 2014, 2013 and 2012, the following net pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel expense, or interest expense at Exelon and Generation in the Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
	Generation																Intercompany				Exelon Corporate				Exelon
																	Eliminations
Year Ended December 31, 2014	Operating				Purchased				Interest Expense				Total				Operating				Interest Expense				Total
	Revenues				Power												Revenues  (a)
					and Fuel
Change in fair value of commodity positions	$	(413	)		$	(194	)		$	—			$	(607	)		$	—			$	—			$	(607	)
Reclassification to realized at settlement of	231				(223		)		—				8				—				—				8
commodity positions
Net commodity mark-to-market gains (losses)	(182		)		(417		)		—				(599		)		—				—				(599		)
Change in fair value of treasury positions	10				—				(2		)		8				—				(100		)		(92		)
Reclassification to realized at settlement of	(2		)		—				—				(2		)		—				—				(2		)
treasury positions
Net treasury mark-to market gains	8				—				(2		)		6				—				(100		)		(94		)
(losses)
Net mark-to market gains (losses)	$	(174	)		$	(417	)		$	(2	)		$	(593	)		$	—			$	(100	)		$	(693	)
	Generation																Intercompany				Exelon Corporate				Exelon
																	Eliminations
Year Ended December 31, 2013	Operating				Purchased				Interest Expense				Total				Operating				Interest Expense				Total
	Revenues				Power												Revenues  (a)
					and Fuel
Change in fair value of commodity positions	$	286			$	180			$	—			$	466			$	(6	)		$	—			$	460
Reclassification to realized at settlement of	(64		)		104				—				40				13				—				53
commodity positions
Net commodity mark-to-market gains	222				284				—				506				7				—				513
(losses)
Change in fair value of treasury positions	(1		)		—				(4		)		(5		)		—				—				(5		)
Reclassification to realized at settlement of	(1		)		—				—				(1		)		—				—				(1		)
treasury positions
Net treasury mark-to market gains	(2		)		—				(4		)		(6		)		—				—				(6		)
(losses)
Net mark-to market gains (losses)	$	220			$	284			$	(4	)		$	500			$	7			$	—			$	507
	Generation																Intercompany				Exelon Corporate				Exelon
																	Eliminations
Year Ended December 31, 2012	Operating				Purchased				Interest Expense				Total				Operating				Interest Expense				Total
	Revenues				Power												Revenues  (a)
					and Fuel
Change in fair value of commodity positions	$	(362	)		$	215			$	—			$	(147	)		$	(94	)		$	—			$	(241	)
Reclassification to realized at settlement of	432				238				—				670				101				—				771
commodity positions
Net commodity mark-to-market gains	70				453				—				523				7				—				530
(losses)
Change in fair value of treasury positions	—				—				6				6				—				—				6
Reclassification to realized at settlement of	(3		)		—				—				(3		)		—				—				(3		)
treasury positions
Net treasury mark-to market gains	(3		)		—				6				3				—				—				3
(losses)
Net mark-to market gains (losses)	$	67			$	453			$	6			$	526			$	7			$	—			$	533
________________________
(a)	Prior to the Constellation merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation.
Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2014, 2013, and 2012 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		For the Years Ended
	Statement		December 31,
			2014				2013				2012
Change in fair value of commodity positions	Operating Revenues		$	(1	)		$	(22	)		$	(13	)
Reclassification to realized at settlement of commodity positions	Operating Revenues		(29		)		(15		)		108
Net commodity mark-to-market gains (losses)	Operating Revenues		(30		)		(37		)		95
Change in fair value of treasury positions	Operating Revenues		1				1				1
Reclassification to realized at settlement of treasury positions	Operating Revenues		3				(3		)		—
Net treasury mark-to market gains (losses)	Operating Revenues		4				(2		)		1
Net mark-to market gains (losses)	Operating Revenues		$	(26	)		$	(39	)		$	96
Credit Risk (Exelon, Generation, ComEd, PECO and BGE)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2014. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 7A.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively.
Rating as of December 31, 2014	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	$	1,629			$	62			$	1,567			1			$	452
Non-investment grade	49				19				30				—			—
No external ratings
Internally rated—investment grade	479				—				479				—			—
Internally rated—non-investment	60				4				56				—			—
grade
Total	$	2,217			$	85			$	2,132			1			$	452
Net Credit Exposure by Type of Counterparty	31-Dec-14
Financial institutions	$	295
Investor-owned utilities, marketers, power producers	958
Energy cooperatives and municipalities	862
Other	17
Total	$	2,132
______________________
(a)	As of December 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $69 million of cash and $16 million of letters of credit.
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on forward market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of December 31, 2014, ComEd’s net credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3 — Regulatory Matters for additional information.
PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of December 31, 2014, PECO had no net credit exposure with suppliers.
PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters for additional information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of December 31, 2014, PECO had credit exposure of $8 million under its natural gas supply and asset management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of December 31, 2014, BGE had no net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At December 31, 2014, BGE had credit exposure of $8 million related to off-system sales which is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers.
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e. capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
	For the Years Ended December 31,
Credit-Risk Related Contingent Feature	2014				2013
Gross Fair Value of Derivative Contracts Containing this Feature (a)	$	(1,433	)		$	(1,056	)
Offsetting Fair Value of In-the-Money Contracts Under Master Netting	1,140				846
Arrangements (b)
Net Fair Value of Derivative Contracts Containing This Feature (c)	$	(293	)		$	(210	)
__________________________
(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 $1,497 million and letters of credit posted of $672 million, and cash collateral held of $77 million and letters of credit held of $24 million as of December 31, 2014 for counterparties with derivative positions. Generation had cash collateral posted of $72 million and letters of credit posted of $364 million and cash collateral held of $206 million and letters of credit held of $34 million at December 31, 2013 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 $2.4 billion and $2.0 billion as of December 31, 2014 and 2013, respectively. These amounts represent the potential additional collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2014, Generation’s and Exelon’s swaps were in a liability position, with a fair value of $16 million and $90 million, respectively.
See Note 24 — Segment Information for further information regarding the letters of credit supporting the cash collateral.
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2014, 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 December 31, 2014, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and long-term REC obligations. See Note 3 — Regulatory Matters for additional information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of December 31, 2014, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of December 31, 2014, 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 December 31, 2014, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of December 31, 2014, BGE could have been required to post approximately $79 million of collateral to its counterparties.

Debt_and_Credit_Agreements_Exe

Debt and Credit Agreements (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
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.
	Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2014 and 2013:
		Maximum							Outstanding								Average Interest Rate on
		Program Size at							Commercial								Commercial Paper Borrowings for
		December 31,							Paper at								the Year Ended December 31,
									December 31,
	Commercial Paper Issuer	2014 (a)(b)				2013 (a)(b)			2014				2013				2014		2013
	Exelon Corporate	$	500			$	500		$	—			$	—			—	%	0.27	%
	Generation	5,600				5,600			—				—				0.32	%	0.32	%
	ComEd	1,000				1,000			304				184				0.33	%	0.4	%
	PECO	600				600			—				—				n.a.		n.a.
	BGE	600				600			120				135				0.29	%	0.31	%
	Total	$	8,300			$	8,300		$	424			$	319
	_____________________
	(a)	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.
	(b)	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
	In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have revolving credit facilities in place, at least equal to the amount of its commercial paper program. While the amount of its outstanding commercial paper does not reduce available capacity under a Registrant’s credit agreement, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit agreement.
	At December 31, 2014, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements:
													Available Capacity at December 31, 2014
	Borrower	Aggregate Bank				Facility Draws			Outstanding				Actual				To Support
		Commitment (a)							Letters of Credit(c)								Additional
																	Commercial
																	Paper (b)
	Exelon Corporate	$	500			$	—		$	6			$	494			$	494
	Generation	5,800				—			1,181				4,619				4,504
	ComEd	1,000				—			2				998				694
	PECO	600				—			1				599				599
	BGE	600				—			—				600				480
	Total	$	8,500			$	—		$	1,190			$	7,310			$	6,771
	_______________________
	(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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
	(b)	Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program.
	(c)	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
	As of December 31, 2014, there were no borrowings under the Registrants’ credit facilities.
	The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2014, 2013 and 2012. PECO did not have any short-term borrowings during 2014, 2013 or 2012.
	Exelon
		2014				2013			2012
	Average borrowings	$	571			$	254		$	199
	Maximum borrowings outstanding	1,164				682			505
	Average interest rates, computed on a daily basis	0.32		%		0.37		%	0.48		%
	Average interest rates, at December 31	0.53		%		0.35		%	n.a.
	Generation
		2014				2013			2012
	Average borrowings	$	93			$	42		$	4
	Maximum borrowings outstanding	552				291			165
	Average interest rates, computed on a daily basis	0.32		%		0.32		%	0.45		%
	Average interest rates, at December 31	n.a.				n.a.			n.a.
	ComEd
		2014				2013			2012
	Average borrowings	$	415			$	203		$	110
	Maximum borrowings outstanding	597				446			366
	Average interest rates, computed on a daily basis	0.33		%		0.4		%	0.5		%
	Average interest rates, at December 31	0.5		%		0.37		%	n.a.
	BGE
		2014				2013			2012
	Average borrowings	$	64			$	35		$	6
	Maximum borrowings outstanding	180				135			76
	Average interest rates, computed on a daily basis	0.29		%		0.31		%	0.43		%
	Average interest rates, computed at December 31	0.61		%		0.31		%	n.a.
	Credit Facilities
	On March 28, 2014, ComEd extended for an additional year the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $1.0 billion. Under this facility, ComEd may issue letters of credit in the aggregate amount of up to $500 million. The credit agreement expires on March 28, 2019. The credit facility also allows ComEd to request increases in the aggregate commitments of up to an additional $500 million. Any increases are subject to the approval of the lenders party to the credit agreement in their sole discretion. Costs incurred to extend the facility for ComEd were not material.
	On May 30, 2014, each of Exelon Corporate, Generation, PECO and BGE extended the expiration date of its unsecured revolving credit facility with aggregate bank commitments of $500 million, $5.3 billion, $600 million and $600 million, respectively, into May 2019, with the exception of a cumulative amount of $315 million in commitments, which expire in April 2018. Costs incurred to extend these facilities were not material.
On October 24, 2014, a $100 million bilateral CENG credit facility was amended and extended for an additional year. This facility has been utilized by CENG to fund working capital and capital projects. This facility does not back Generation's commercial paper program.
On November 24, 2014, Generation entered into a $25 million bilateral credit facility, scheduled to mature in December of 2016. This facility does not currently back Generation's commercial paper program.
On January 9, 2015, Generation amended and extended its $75 million bilateral credit facility for an additional two years. This facility does not back Generation's commercial paper program.
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.
An event of default under any of the Registrants' revolving credit facilities would not constitute an event of default under any of the other Registrants' revolving credit facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in the aggregate by Generation under its revolving credit facility would constitute an event of default under the Exelon Corporation revolving credit facility.
Each credit facility requires the affected borrower to maintain a minimum cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The ratios exclude revenues and interest expenses attributable to securitization debt, certain changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2014:
	Exelon		Generation		ComEd		PECO	BGE
Credit facility threshold	2.50 to 1		3.00 to 1		2.00 to 1		2.00 to 1	2.00 to 1
At December 31, 2014, the interest coverage ratios at the Registrants were as follows:
	Exelon			Generation			ComEd		PECO			BGE
Interest coverage ratio	9.19			12.35			7.03		8.72			9.28
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 debt and equity security issuances discussed below, as well as, the net after-tax proceeds from generating asset divestitures during the second half of 2014. During the year ended December 31, 2014, Exelon recorded $31 million to interest expense in connection with the bridge facility to temporarily finance the PHI acquisition. It is not currently expected that Exelon will be required to draw upon this credit facility to finance the proposed PHI acquisition.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Net proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds are expected to be used to finance a portion of the acquisition of PHI and for general corporate purposes.
Each equity unit represents an undivided beneficial ownership interest in Exelon’s 2.5% 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. In connection with the remarketing, Exelon may modify the maturity date of the notes to a date earlier than June 1, 2024 but not earlier than June 1, 2020, remove redemption provisions of the notes, or change the interest rate on the notes, including changing the interest rate from fixed to floating. Investors that participate in the remarketing receive the remarketing proceeds and may use those funds to either settle the equity forward upon settlement date or invest in the remarketed debt and use other funds for the share purchase. Exelon intends to use the remarketing proceeds to repay debt issued or for other corporate purposes as soon as practical following such settlements. If the remarketing fails, holders of the notes will have the right to put their notes to Exelon for an amount equal to the principal amount of notes held by such holder plus accrued interest. The equity units carry a total annual distribution rate of 6.5%, which is comprised of a quarterly coupon rate of interest of 2.5% and a quarterly contract payment of 4.0% (contract payments).
Each purchase contract obligates the holder to purchase, and Exelon to sell, for $50.00 a number of shares of Exelon’s common stock in accordance with the conversion ratios set forth below:
•	If the market price equals or exceeds $43.7484, then 1.1429 shares.
•	If the market price is less than $43.7484 but greater than $35.00, a number of shares of common stock having a value, based on the market price, equal to $50.00.
•	If the market price is less than or equal to $35.00, then 1.4286 shares.
A holder’s ownership interest in the notes is pledged to Exelon to secure the holder’s obligation under the related forward equity purchase contract. If a holder of the forward equity purchase contract chooses at any time to no longer be a holder of the notes, such holder’s obligation under the purchase contract must be secured by a U.S. Treasury security.
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.
Long-Term Debt
The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2014 and 2013:
Exelon
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
Rate stabilization bonds	5.72	%	-	5.82	%		2017	$	195			$	265
First mortgage bonds (a)(b)	1.2	%	-	6.45	%		2015 - 2044	8,079				7,746
Senior unsecured notes	2	%	-	7.6	%		2015 - 2042	7,071				7,571
Unsecured bonds	2.8	%	-	6.35	%		2016 - 2036	1,750				1,750
Pollution control note				4.1	%		2014	—				20
Nuclear fuel procurement contracts	3.25	%	-	3.35	%		2018	70				—
Junior subordinated notes				6.5	%		2017	1,150				—
Nonrecourse debt:
Fixed rates	2.33	%	-	6	%		2031 - 2037	1,166				1,077
Variable rates	2.41	%	-	5	%		2019 - 2030	1,101				150
Notes payable and other (c)	6.95	%	-	7.83	%		2015 - 2053	174				181
Total long-term debt								20,756				18,760
Unamortized debt discount and premium, net								(37		)		(19		)
Fair value adjustment								441				384
Fair value hedge carrying value adjustment,								4				7
net
Long-term debt due within one year								(1,802		)		(1,509		)
Long-term debt								$	19,362			$	17,623
Long-term debt to financing trusts (d)
Subordinated debentures to ComEd Financing				6.35	%		2033	$	206			$	206
III
Subordinated debentures to PECO Trust III				7.38	%		2028	81				81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103				103
Subordinated debentures to BGE Trust				6.2	%		2043	258				258
Total long-term debt to financing trusts								$	648			$	648
____________________
(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s assets are subject to the liens of their respective mortgage indentures.
(b)	Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.
(c)	Includes capital lease obligations of $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.
(d)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
Generation
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
Senior unsecured notes	2	%	-	7.6	%		2015 - 2042	$	5,771			$	6,271
Social Security Administration				2.93	%		2015	—				1
Pollution control notes				4.1	%		2014	—				20
Nuclear fuel procurement contracts	3.25	%	-	3.35	%		2018	70				—
Nonrecourse debt:
Fixed rates	2.33	%	-	6	%		2031 - 2037	1,166				1,077
Variable rates	2.41	%	-	5	%		2019 - 2030	1,101				150
Notes payable and other (a)				7.83	%		2014 - 2020	26				33
Total long-term debt								8,134				7,552
Fair value adjustment								146				166
Unamortized debt discount and premium, net								(14		)		11
Long-term debt due within one year								(614		)		(561		)
Long-term debt								$	7,652			$	7,168
______________________
(a)	Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.
On January 13, 2015, Generation issued $750 million in aggregate principal amount of Senior Notes. The Senior Notes carry an annual interest rate of 2.950%, payable semi-annually, commencing July 15, 2015 and due January 15, 2020. The proceeds of the Senior Notes will be used to fund the optional redemption of Exelon's $550 million, 4.550% Senior Notes due June 15, 2015 and for general corporate purposes. In addition to the issuance, Exelon terminated $400 million of floating-to-fixed interest rate swaps that had been designated as cash flow hedges. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments at this time are probable not to occur. As a result Exelon will reclassify $26 million of deferred losses in AOCI to Other, net in the first quarter of 2015.
ComEd
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
First mortgage bonds (a)(b)	1.95	%	-	6.45	%		2015 - 2044	$	5,829			$	5,546
Notes payable and other (c)	6.95	%	-	7.49	%		2015 - 2053	148				148
Total long-term debt								5,977				5,694
Unamortized debt discount and premium, net								(19		)		(19		)
Long-term debt due within one year								(260		)		(617		)
Long-term debt								$	5,698			$	5,058
Long-term debt to financing trust (d)
Subordinated debentures to ComEd Financing III				6.35	%		2033	$	206			$	206
______________________
(a)	Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.
(b)	Includes first mortgage bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.
(c)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053.
(d)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
PECO
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
First mortgage bonds (a)(b)	1.2	%	-	5.95	%		2016 - 2044	$	2,250			$	2,200
Total long-term debt								2,250				2,200
Unamortized debt discount and premium, net								(4		)		(3		)
Long-term debt due within one year								—				(250		)
Long-term debt								$	2,246			$	1,947
Long-term debt to financing trusts (c)
Subordinated debentures to PECO Trust III				7.38	%		2028	$	81			$	81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103				103
Long-term debt to financing trusts								$	184			$	184
_____________________
(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b)	Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.
(c)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
BGE
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
Rate stabilization bonds	5.72	%	-	5.82	%		2017	195				$	265
Notes	2.8	%	-	6.35	%		2016 - 2036	$	1,750			$	1,750
Total long-term debt								1,945				2,015
Unamortized debt discount and premium, net								(3		)		(4		)
Long-term debt due within one year								(75		)		(70		)
Long-term debt								$	1,867			$	1,941
Long-term debt to financing trusts (a)
Subordinated debentures to BGE Capital Trust II				6.2	%		2043	$	258			$	258
___________________
(a)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.
Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2014 through 2019 and thereafter are as follows:
Year	Exelon				Generation			ComEd				PECO				BGE
2015	$	1,739			$	604		$	260			$	—			$	75
2016	1,269				4			665				300				300
2017	2,400				705			425				—				120
2018	1,415				75			840				500				—
2019	982				682			300				—				—
Thereafter	13,599			(a)	6,064			3,693			(b)	1,634			(c)	1,708		(d)
Total	$	21,404			$	8,134		$	6,183			$	2,434			$	2,203
____________________
(a)	Includes $648 million due to ComEd, PECO and BGE financing trusts.
(b)	Includes $206 million due to ComEd financing trust.
(c)	Includes $184 million due to PECO financing trusts.
(d)	Includes $258 million due to BGE financing trust.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.7 billion of generating assets have been pledged as collateral at December 31, 2014.
Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement, fully amortizing by June 30, 2031 related to a solar construction project in Denver, Colorado. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of December 31, 2014, $7 million was outstanding.
CEU Upstream. In July 2011, Generation entered into a five year asset-based lending agreement associated with certain Upstream gas properties that it owns. The borrowing base committed under the facility is $110 million and can increase to a total of $500 million if the assets support a higher borrowing base and Generation is able to obtain additional commitments from lenders. The facility was amended and extended through January 2019. Borrowings under this facility are secured by the Upstream gas properties, and the lenders do not have recourse against Exelon or Generation in the event of a default. The agreement is scheduled to expire on January 14, 2019, at a fixed rate of 2.41% annually with interest payable quarterly. As of December 31, 2014, $77 million was outstanding under the facility. The facility includes a provision that requires the Generation entities owning the Upstream gas properties subject to the agreement to maintain a current ratio of one-to-one. As of December 31, 2014, Generation was in compliance with this provision.
Sacramento PV Energy.    In July 2011, a subsidiary of Generation entered into a 19-year, $41 million nonrecourse note to finance a 30MW solar facility in Sacramento, California. The note bears interest at a variable rate equal to the six-month LIBOR plus 2.25%. Interest is payable quarterly and is secured by the equity interests and assets of the subsidiary. The note is scheduled to mature on December 31, 2030. As of December 31, 2014, $35 million was outstanding. The subsidiary also executed interest rate swaps with an initial notional value of $30 million in order to convert the variable interest payments to fixed payments on 75% of the $41 million facility amount, as required by the debt covenants. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps.
Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $10 million solar loan agreement, fully amortizing by December 31, 2031 related to a solar construction project in Holyoke, Massachusetts. The agreement bears interest at a fixed rate of 5.25% annually with interest payable monthly. As of December 31, 2014, $10 million was outstanding. The agreement includes a provision that requires Generation to establish and maintain a reserve fund to be held by Holyoke Solar Cooperative. As of December 31, 2014, Generation was in compliance with this provision.
Antelope Valley Solar Ranch One.    In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in the first half of 2014. The loan will mature on January 5, 2037. Interest rates on the loan are fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. As of December 31, 2014, $557 million was outstanding.
In addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2014, Generation had $156 million in letters of credit outstanding related to the project. The letters of credit balance is expected to decline over time as scheduled equity contributions for the project are made. Generation expects to contribute approximately $2 million in additional equity contributions.
In connection with this agreement, on September 28, 2011, Generation entered into a floating-to-fixed interest rate swap with a notional amount of $485 million to mitigate interest-rate risk associated with the financing. As Generation received additional loan advances, it subsequently entered into a series of fixed-to-floating interest rate swaps to offset portions of the original interest rate hedge. During the third quarter of 2014, the original interest rate swap was terminated, consistent with the agreements. See Note 12 — Derivative Financial Instruments for additional information regarding the interest rate swaps associated with Antelope Valley.
Constellation Solar Horizons.    In September 2012, a subsidiary of Generation entered into an 18-year $38 million nonrecourse note to recover capital used to build a 16MW solar facility in Emmitsburg, Maryland. The note is schedule to mature on September 7, 2030. The note bears interest at a variable rate equal to the three-month LIBOR plus 2.25%. Interest is payable quarterly, and the note is secured by the equity interests and assets of the subsidiary. As of December 31, 2014, $34 million was outstanding. The subsidiary also executed interest rate swaps for an initial notional amount of $29 million in order to convert the variable interest payments to fixed payments on 75% of the $38 million facility amount, as required by the debt covenants. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps.
Continental Wind.    In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613 million aggregate principal amount of Continental Wind’s 6.00% senior secured notes due February 28, 2033 with interest payable semi-annually. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were distributed to Generation for its general business purposes. As of December 31, 2014, $592 million was outstanding. In connection with this nonrecourse project financing, Exelon terminated existing interest rate swaps with a total notional amount of $350 million during the third quarter of 2013, and realized a total gain of $26 million upon termination. The gain on the interest rate swaps was recorded within OCI and will reduce the effective interest rate over the life of the debt for Exelon. See Note 12 — Derivative Financial Instruments for additional information on the interest rate swaps.
In addition, Continental Wind entered into a $131 million letter of credit facility and $10 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2014, the Continental Wind letter of credit facility had $47 million in letters of credit outstanding related to the project.
ExGen Renewables I.    On February 6, 2014, ExGen Renewables I, LLC (EGR), an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal amount pursuant to a nonrecourse senior secured loan, due February 6, 2021. The proceeds were distributed to Generation for its general business purposes. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% floor with interest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2014, $282 million was outstanding. In addition to the financing, EGR entered into interest rate swaps with an initial notional amount of $240 million at an interest rate of 2.03% to manage a portion of the interest rate exposure in connection with the financing.  See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps.
ExGen Texas Power.    In September 2014, ExGen Texas Power, LLC (EGTP), an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a nonrecourse senior secured term loan, scheduled to mature on September 18, 2021.  The net proceeds were distributed to Generation for general business purposes. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2014, $673 million was outstanding. As part of the agreement, a revolving credit facility was established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. In addition to the financing, EGTP entered into interest rate swaps with an initial notional amount of approximately $505 million at an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants. See Note 12 — Derivative Financial Instruments for additional information regarding interest rate swaps.

Income_Taxes_Exelon_Generation

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
	Income tax expense (benefit) from continuing operations is comprised of the following components:
	For the Year Ended December 31, 2014	Exelon				Generation				ComEd			PECO			BGE
	Included in operations:
	Federal
	Current	$	121			$	360			$	(171	)	$	28		$	24
	Deferred	576				(35		)		395			87			90
	Investment tax credit amortization	(20		)		(16		)		(2		)	—			(1		)
	State
	Current	42				35				7			(2		)	—
	Deferred	(53		)		(137		)		39			1			27
	Total	$	666			$	207			$	268		$	114		$	140
	For the Year Ended December 31, 2013	Exelon				Generation				ComEd			PECO			BGE
	Included in operations:
	Federal
	Current	$	744			$	250			$	160		$	126		$	9
	Deferred	140				360				(27		)	23			100
	Investment tax credit amortization	(15		)		(11		)		(2		)	(1		)	(1		)
	State
	Current	181				50				50			16			—
	Deferred	(6		)		(34		)		(29		)	(2		)	26
	Total	$	1,044			$	615			$	152		$	162		$	134
	For the Year Ended December 31, 2012	Exelon				Generation				ComEd			PECO			BGE
	Included in operations:
	Federal
	Current	$	37			$	104			$	(40	)	$	88		$	(97	)
	Deferred	701				326				237			25			101
	Investment tax credit amortization	(11		)		(6		)		(2		)	(2		)	(1		)
	State
	Current	(25		)		(12		)		6			4			—
	Deferred	(75		)		88				38			12			4
	Total	$	627			$	500			$	239		$	127		$	7
	The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
	For the Year Ended December 31, 2014	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	1.3			(1.9	)		4.5			(0.1	)	5
	Qualified nuclear decommissioning trust fund income	2.4			4.8			—			—		—
	Tax exempt income	(0.2	)		(0.5	)		—			—		—
	Domestic production activities deduction	(2.0	)		(4.1	)		—			—		—
	Health care reform legislation	0.1			—			0.2			—		0.2
	Amortization of investment tax credit, net deferred	(1.1	)		(2.0	)		(0.3	)		(0.1	)	(0.3	)
	taxes
	Plant basis differences	(1.9	)		—			(0.1	)		(10.4	)	0.2
	Production tax credits and other credits	(2.4	)		(4.8	)		—			—		—
	Non-controlling interest	(1.8	)		(3.7	)		—			—		—
	Statute of limitations expiration	(2.6	)		(5.3	)		—			—		—
	Other	—			(0.6	)		0.3			0.1		(0.2	)
	Effective income tax rate	26.8	%		16.9	%		39.6	%		24.5	%	39.9	%
	For the Year Ended December 31, 2013	Exelon			Generation			ComEd			PECO		BGE
	U.S. Federal statutory rate	35	%		35	%		35	%		35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	4.8			1.8			3.4			1.6		4.9
	Qualified nuclear decommissioning trust fund income	3.7			6.1			—			—		—
	Tax exempt income	(0.2	)		(0.3	)		—			—		—
	Domestic production activities deduction	—			—			—			—		—
	Health care reform legislation	0.1			—			0.7			—		0.2
	Amortization of investment tax credit, net deferred	(1.9	)		(3.0	)		(0.6	)		(0.1	)	—
	taxes
	Plant basis differences	(1.6	)		—			(0.8	)		(7.1	)	(0.2	)
	Production tax credits and other credits	(2.1	)		(3.4	)		(0.1	)		—		—
	Statute of limitations expiration	(0.1	)		(0.2	)		—			—		—
	Other	(0.1	)		0.7			0.3			(0.3	)	(0.9	)
	Effective income tax rate	37.6	%		36.7	%		37.9	%		29.1	%	39	%
For the Year Ended December 31, 2012	Exelon (a)			Generation (a)			ComEd			PECO		BGE (b)
U.S. Federal statutory rate	35	%		35	%		35	%		35	%	35	%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit	(3.5	)		4.9			4.6			2		24.3
Qualified nuclear decommissioning trust fund income	5.4			9.1			—			—		—
Tax exempt income	(0.2	)		(0.4	)		—			—		—
Domestic production activities deduction	—			—			—			—		—
Health care reform legislation	0.1			—			0.4			—		11.6
Amortization of investment tax credit	(1.1	)		(1.3	)		(0.4	)		(0.3	)	(8.6	)
Plant basis differences	(2.4	)		—			(0.3	)		(11.5	)	(9.0	)
Production tax credits and other credits	(2.2	)		(3.7	)		—			—		—
Fines and Penalties	2.6			4.4			—			—		—
Merger expenses (c)	2.4			—			—			—		24.2
Statute of limitations expiration	(0.1	)		(0.3	)		—			—		—
Other	(1.1	)		(0.4	)		(0.6	)		(0.2	)	(13.9	)
Effective income tax rate	34.9	%		47.3	%		38.7	%		25	%	63.6	%
_____________________
(a)	Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012.
(b)	BGE activity represents the activity for the twelve months ended December 31, 2012.
(c)	Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger.
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2014 and 2013 are presented below:
For the Year Ended December 31, 2014	Exelon				Generation				ComEd			PECO			BGE
Plant basis differences	$	(12,143	)		$	(3,834	)		$	(3,945	)	$	(2,749	)	$	(1,661	)
Accrual based contracts	(178		)		(178		)		—			—			—
Derivatives and other financial instruments	(46		)		(79		)		(4		)	—			—
Deferred pension and postretirement obligation	1,914				(390		)		(543		)	2			(53		)
Nuclear decommissioning activities	(726		)		(726		)		—			—			—
Deferred debt refinancing costs	112				57				(18		)	(2		)	(4		)
Regulatory assets and liabilities	(1,824		)		—				(286		)	27			(258		)
Tax loss carryforward	111				48				—			11			39
Tax credit carryforward	97				143				—			—			—
Investment in CENG	(563		)		(563		)		—			—			—
Other, net	1,029				346				255			111			30
Deferred income tax liabilities (net)	$	(12,217	)		$	(5,176	)		$	(4,541	)	$	(2,600	)	$	(1,907	)
Unamortized investment tax credits	(555		)		(528		)		(20		)	(2		)	(5		)
Total deferred income tax liabilities (net) and	$	(12,772	)		$	(5,704	)		$	(4,561	)	$	(2,602	)	$	(1,912	)
unamortized investment tax credits
For the Year Ended December 31, 2013	Exelon				Generation				ComEd			PECO			BGE
Plant basis differences	$	(11,612	)		$	(3,879	)		$	(3,523	)	$	(2,573	)	$	(1,538	)
Accrual based contracts	(214		)		(214		)		—			—			—
Derivatives and other financial instruments	(509		)		(505		)		(4		)	—			—
Deferred pension and postretirement obligation	1,489				(362		)		(522		)	—			(74		)
Nuclear decommissioning activities	(647		)		(646		)		—			—			—
Deferred debt refinancing costs	173				79				(21		)	(3		)	(5		)
Regulatory assets and liabilities	(1,611		)		—				(241		)	42			(253		)
Tax loss carryforward	252				76				47			11			52
Tax credit carryforward	534				534				—			—			—
Investment in CENG	(541		)		(541		)		—			—			—
Other, net	804				67				154			122			26
Deferred income tax liabilities (net)	$	(11,882	)		$	(5,391	)		$	(4,110	)	$	(2,401	)	$	(1,792	)
Unamortized investment tax credits	(490		)		(454		)		(22		)	(3		)	(6		)
Total deferred income tax liabilities (net) and	$	(12,372	)		$	(5,845	)		$	(4,132	)	$	(2,404	)	$	(1,798	)
unamortized investment tax credits
The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2014.
	Exelon			Generation			ComEd			PECO		BGE
Federal
Federal general business credits carryforward	184		(a)	184			—			—		—
State
State net operating losses and other credit carryforwards	3,141			1,693			—			170		730		(e)
Deferred taxes on state tax attributes (net)	169			96			—			11		39
Valuation allowance on state tax attributes	50			48			—			—		1
_____________________
(a)	Exelon’s federal general business credit carryforwards will expire beginning in 2032.
(b)	Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015
(c)	Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015.
(d)	PECO’s state net operating losses will expire beginning in 2031.
(e)	BGE’s state net operating losses will expire beginning in 2026.
Tabular reconciliation of unrecognized tax benefits
The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2014, 2013 and 2012:
	Exelon				Generation				ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2014	$	2,175			$	1,415			$	324		$	44		$	—
Increases based on tax positions related to 2014	15				15				—			—			—
Change to positions that only affect timing	(255		)		33				(175		)	—			—
Increases based on tax positions prior to 2014	18				18				—			—			—
Decreases based on tax positions prior to 2014	(1		)		(2		)		—			—			—
Decrease from settlements with taxing authorities	(35		)		(34		)		—			—			—
Decreases from expiration of statute of limitations	(88		)		(88		)		—			—			—
Unrecognized tax benefits at December 31, 2014	$	1,829			$	1,357			$	149		$	44		$	—
	Exelon				Generation				ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2013	$	1,024			$	876			$	67		$	44		$	—
Increases based on tax positions related to 2013	19				19				—			—			—
Change to positions that only affect timing	649				36				257			—			—
Increases based on tax positions prior to 2013	493				493				—			—			—
Decreases based on tax positions prior to 2013	(6		)		(5		)		—			—			—
Decreases from expiration of statute of limitations	(4		)		(4		)		—			—			—
Unrecognized tax benefits at December 31, 2013	$	2,175			$	1,415			$	324		$	44		$	—
	Exelon				Generation				ComEd			PECO			BGE
Unrecognized tax benefits at January 1, 2012	$	807			$	683			$	70		$	48		$	11
Merger balance transfer	195				183				—			—			—
Increases based on tax positions related to 2012	34				3				—			—			—
Change to positions that only affect timing	(88		)		(69		)		(3		)	(4		)	(11		)
Increases based on tax positions prior to 2012	91				91				—			—			—
Decreases based on tax positions prior to 2012	(6		)		(6		)		—			—			—
Decreases related to settlements with taxing authorities	(2		)		(2		)		—			—			—
Decreases from expiration of statute of limitations	(7		)		(7		)		—			—			—
Unrecognized tax benefits at December 31, 2012	$	1,024			$	876			$	67		$	44		$	—
Included in Exelon’s unrecognized tax benefits balance at December 31, 2014 and 2013 are approximately $1,129 million and $1,387 million, respectively, of tax positions for which the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits. The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of the cash tax benefit from, the taxing authority to an earlier or later period respectively.
Unrecognized tax benefits that if recognized would affect the effective tax rate
Exelon and Generation have $701 million and $672 million, respectively, of unrecognized tax benefits at December 31, 2014 that, if recognized, would decrease the effective tax rate. Exelon and Generation had $788 million and $768 million, respectively, of unrecognized tax benefits at December 31, 2013 that, if recognized, would decrease the effective tax rate.
Reasonably possible that total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
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 has disallowed the claims. In November 2008, Generation received a final determination from the Appeals division of the IRS (IRS Appeals) disallowing AmerGen’s refund claims. Generation filed a complaint in the United States Court of Federal Claims on February 20, 2009 to contest this determination. During the first and second quarters of 2013, AmerGen and the DOJ completed and filed cross motions for summary judgment. 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 and oral arguments were heard in January of 2015.
Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the $661 million of total unrecognized tax benefits will significantly decrease in the next twelve months.
Settlement of Income Tax Audits and Litigation
As of December 31, 2014, Exelon and Generation have approximately $188 million of state unrecognized tax benefits that could significantly increase or decrease within the 12 months after the reporting date as a result of completing audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate.
See Other Tax Matters—Like Kind Exchange section below for information regarding the amount of unrecognized tax benefits associated with this matter that could change significantly within the next 12 months.
Total amounts of interest and penalties recognized
The following table represents the net interest receivable (payable), including interest related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.
Net interest receivable (payable) as of	Exelon				Generation				ComEd			PECO			BGE
December 31, 2014	$	(310	)		$	40			$	(203	)	$	3		$	(1	)
December 31, 2013	(349		)		(37		)		(174		)	3			—
The following table sets forth the net interest expense, including interest related to tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have not accrued any material penalties with respect to uncertain tax positions.
Net interest expense (income) for the years ended	Exelon				Generation				ComEd			PECO			BGE
December 31, 2014	$	(36	)		$	(50	)		$	6		$	—		$	1
December 31, 2013	391				17				281			(1		)	—
December 31, 2012	(1		)		11				(20		)	(1		)	9
Description of tax years that remain open to assessment by major jurisdiction
Taxpayer	Open Years
Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns	1999, 2001-2013
Constellation and subsidiaries consolidated Federal income tax returns	2011-March 2012
Exelon and subsidiaries Illinois unitary income tax returns	2007-2013
Constellation combined New York corporate income tax returns	2008-2013
Various separate company Pennsylvania corporate net income tax returns	2010-2013
BGE Maryland corporate net income tax returns	2011-2013
Various Exelon Maryland corporate net income tax returns	2012-2013
Various Constellation (Non-BGE) Maryland corporate net income tax returns	2011-2013
Other Tax Matters
Like-Kind Exchange
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.
Exelon has been unable to reach agreement with the IRS regarding the dispute over the like kind exchange position. The IRS has asserted that 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. 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 December 31, 2014 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 will increase 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 resulted 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. See Note 8 —Impairment of Long-Lived Assets for further details.
Accounting for Generation Repairs (Exelon and Generation)
On April 30, 2013, the IRS issued Revenue Procedure 2013-24 providing guidance for determining the appropriate tax treatment of costs incurred to repair electric generation assets. Generation will change its method of accounting for deducting repairs in accordance with this guidance beginning with its 2014 tax year. Generation has calculated that adoption of the new method will result in a cash tax detriment of approximately $120 million.
Accounting for Electric Transmission and Distribution Property Repairs (Exelon, Generation, ComEd, PECO and BGE)
On August 19, 2011, the IRS issued Revenue Procedure 2011-43 providing a safe harbor method of tax accounting for repair costs associated with electric transmission and distribution property. ComEd and PECO adopted the safe harbor in the Revenue Procedure for the 2011 and 2010 tax years, respectively. For the year ended December 31, 2011, the adoption of the safe harbor resulted in a $35 million reduction to income tax expense at PECO, while Generation incurred additional income tax expense in the amount of $28 million due to a decrease in its domestic production activities deduction, which was reflected in the effective income tax rate reconciliation in 2011 in the plant basis differences and domestic production activities deduction lines, respectively. For Exelon, the adoption had a minimal effect on consolidated earnings. In addition, the adoption of the safe harbor resulted in a cash tax benefit at Exelon, ComEd and PECO in the amount of approximately $300 million, $250 million, and $95 million, respectively, partially offset by a cash tax detriment at Generation in the amount of $28 million related to a decreased domestic production activities deduction.
BGE adopted the safe harbor for the short period 2012 pre-merger tax year. For the year ended December 31, 2012, the adoption of the safe harbor resulted in a cash tax benefit at BGE in the amount of $27 million.
See Note 3—Regulatory Matters for discussion of the regulatory treatment prescribed in the 2010 electric distribution rate case settlement for PECO’s cash tax benefit resulting from the application of the method change to years prior to 2010.
Accounting for Gas Distribution Property Repairs (Exelon, PECO and BGE).
In September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. The change to the newly adopted method for the 2011 tax year and 2012 resulted in a tax benefit of $26 million at Exelon, of which $29 million in tax benefit is recorded at PECO, partially offset by an expense recorded at Generation to reflect a reduction in its domestic production activities deduction. BGE changed its method of accounting for gas distribution repairs for the 2008 tax year. The IRS is expected to issue industry guidance in the near future. Exelon, PECO and BGE will determine the financial statement impacts of the gas distribution repair costs accounting method changes after guidance is issued.
Accounting for Final Tangible Property Regulations (Exelon, Generation, ComEd, PECO, and BGE)
On September 19, 2013, the Treasury Department and the IRS published final regulations regarding the tax treatment of costs incurred to acquire, produce, or improve tangible property. The Registrants have assessed the financial impact of this guidance and do not expect it to have a material impact. Any changes in method of accounting required to conform to the final regulations will be made for the Registrant’s 2014 taxable year.
Long-Term State Tax Apportionment (Exelon and Generation)
As a result of the merger with Constellation, Exelon and Generation re-evaluated their long-term state tax apportionment in the first quarter of 2012. The total effect of revising the long-term state tax apportionment resulted in the recording of a deferred state tax asset of $72 million (net of Federal taxes) for Exelon. Of this, a benefit in the amount of $116 million and $14 million (net of Federal taxes) was recorded for Exelon and Generation, respectively, for the three months ended March 31, 2012. Further, Exelon and Generation recorded deferred state tax liabilities of $44 million and $14 million (net of Federal taxes), respectively, as part of purchase accounting during the three months ended March 31, 2012. The long-term state tax apportionment also was updated in the fourth quarter of 2012, resulting in the recording of a deferred state tax benefit of $3 million (net of Federal taxes) for Exelon, and a deferred state tax expense of $7 million (net of Federal taxes) for Generation. There was no change to the long-term state tax apportionment for BGE, ComEd and PECO.
The long-term state tax apportionment was revised in the fourth quarter of 2014 pursuant to Exelon's long-term state tax apportionment policy, resulting in the recording of a deferred state tax benefit for Exelon and Generation of $28 million (net of Federal taxes) and $40 million (net of Federal taxes), respectively. The amounts recorded for 2013 in accordance with the policy were immaterial.
Allocation of Tax Benefits (Exelon, Generation, ComEd, PECO and BGE)
Generation, ComEd, PECO and BGE are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar to that which would be owed had the party been separately subject to tax. In addition, any net benefit attributable to Exelon is reallocated to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit. During 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $55 million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of tax net operating losses.
During 2013, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $26 million and $27 million, respectively. During 2013, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.
During 2012, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of $48 million and $9 million, respectively. During 2012, ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement as a result of ComEd’s and BGE’s tax net operating loss generated primarily by the bonus depreciation deduction allowed under the Tax Relief Act of 2010.
ComEd received a non-cash contribution to equity from Exelon in 2012 of $11 million, related to tax benefits associated with capital projects constructed by ComEd on behalf of Exelon and Generation.

Asset_Retirement_Obligations_E

Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations (Exelon, Generation, ComEd and PECO)	Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)
	Nuclear Decommissioning Asset Retirement Obligations
	Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
	The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2013 to December 31, 2014:
		Exelon and
		Generation
	Nuclear decommissioning ARO at January 1, 2013	$	4,741
	Accretion expense	259
	Net decrease due to changes in, and timing of, estimated future cash flows	(140		)
	Costs incurred to decommission retired plants	(5		)
	Nuclear decommissioning ARO at December 31, 2013 (a)	4,855
	Consolidation of CENG (b)	1,760
	Accretion expense	334
	Net increase due to changes in, and timing of, estimated future cash flows	19
	Costs incurred to decommission retired plants	(7		)
	Nuclear decommissioning ARO at December 31, 2014 (a)	$	6,961
	_________________________
	(a)	Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
	(b)	Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
	During 2014, Generation’s ARO increased by approximately $2.1 billion. The increase is largely driven by the recording of an ARO on Exelon’s and Generation’s Consolidated Balance Sheets at fair value, including subsequent purchase accounting adjustments, upon consolidation of CENG (see Note 5 — Investment in Constellation Energy Nuclear Group, LLC ). The change in the ARO was also driven by an increase for accretion of the obligation and an increase in the estimated costs to decommission Byron, Braidwood, and LaSalle nuclear units resulting from the completion of updated decommissioning costs studies received during 2014 as part of the annual assessment. These increases in the ARO were partially offset by decreases in the ARO due to a reduction in estimated escalation rates, primarily for labor and energy costs. The increase in the ARO due to the changes in, and timing of, estimated cash flows was offset within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets, aside from an approximate $16 million credit to income, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	During 2013, Generation’s ARO increased by approximately $114 million. The increase is largely driven by an increase in the estimated costs to decommission the Limerick and Three Mile Island nuclear units resulting from the completion of updated decommissioning costs studies received during 2013 and an increase for accretion of the obligation. These increases in the ARO were offset by decreases to the ARO due to changes in long-term escalation rates, primarily for labor and energy costs, as well as changes in the timing of the future nominal cash flows coupled with the fact that cash flows affected by this change in timing are re-measured and discounted at current credit adjusted risk free rates (CARFRs), which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows was entirely offset by decreases in Property, plant and equipment within Exelon’s and Generation’s Consolidated Balance Sheets.
	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. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to nuclear decommissioning trust funds that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
	At December 31, 2014, and 2013, Exelon and Generation had NDT fund investments totaling $10,537 million and $8,071 million, respectively. At December 31, 2014, approximately 52% of the funds were invested in equity securities and 48% were invested in fixed income securities. At December 31, 2013, approximately 48% of the funds were invested in equity securities and 52% were invested in fixed income securities. During 2012, the NDT fixed income portfolio completed its transition from solely core fixed income investments to a blend of Treasury Inflation Protected Securities (TIPS), investment-grade corporate credit and middle market lending. There was no change in the equity investment strategy.
	The following table provides unrealized gains on NDT funds for 2014, 2013 and 2012:
		Exelon and Generation
		For the Years Ended December 31,
		2014			2013			2012
	Net unrealized gains on decommissioning trust	$	180		$	406		$	386
	funds—Regulatory Agreement Units (a)
	Net unrealized gains on decommissioning trust	134			146			105
	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 $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.
	(c)	Net unrealized gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.
	Accounting Implications of the Regulatory Agreements with ComEd and PECO. Based on the regulatory agreement with the ICC that dictates Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis, as long as funds held in the NDT funds are expected to exceed the total estimated decommissioning obligation, decommissioning-related activities, including realized and unrealized gains and losses on the NDT funds and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability. Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income and the adverse impact to Exelon’s and Generation’s results of operations and financial position could be material. As of December 31, 2014, the NDT funds of each of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. For the purposes of making this determination, the decommissioning obligation referred to is different, as described below, from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
	Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess of trust funds necessary for decommissioning the former PECO units, regardless of whether the funds held in the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation, decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from Generation and a corresponding regulatory liability. Any changes to the PECO regulatory agreements could impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the impact to Exelon’s and Generation’s results of operations and financial position could be material.
	The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	Refer to Note 3 — Regulatory Matters and Note 25 — Related Party Transactions for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
	Zion Station Decommissioning
	On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. Specifically, Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds. In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of SNF and decommission the SNF dry storage facility, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs incurred related to its decommissioning efforts at Zion Station. During 2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another Company. Generation reviewed the acquisition as it relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact decommissioning activities under the ASA.
	ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $86 million, which is included within the nuclear decommissioning ARO at December 31, 2014. Generation also has retained NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by Generation. Any Zion Station NDT funds remaining after the completion of all decommissioning activities will be returned to ComEd customers in accordance with the applicable orders. The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2014 and 2013:
		Exelon and Generation
		2014			2013
	Carrying value of Zion Station pledged assets	$	319		$	458
	Payable to Zion Solutions (a)	292			414
	Current portion of payable to Zion Solutions (b)	137			109
	Cumulative withdrawals by Zion Solutions to pay decommissioning costs	666			498
	___________________
	(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.
	ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has committed to complete the required decommissioning work according to an established schedule and constructed a dry cask storage facility on the land and has loaded the SNF from the SNF pools onto the dry cask storage facility at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by ZionSolutions, EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into other agreements that will provide rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.
	NRC Minimum Funding Requirements
	NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from the ARO recorded on Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial guarantees.
	Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2014 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals and with an assumed end-of-operations date of 2019 for Oyster Creek); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).
	In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31, 2014 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain low-level radioactive waste); (3) the consideration of multiple scenarios where decommissioning activities are completed under three possible scenarios ranging from 10 to 70 years after the cessation of plant operations; (4) the assumption plants cease operating at the end of an extended license life (assuming 20-year license renewal extensions, except Oyster Creek with an assumed end-of-operations date of 2019); (5) the measurement of the obligation at the present value of the future estimated costs and an annual average accretion of the ARO of approximately 5% through a period of approximately 30 years after the end of the extended lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6% to 6.3% (as compared to a historical 5-year annual average pre-tax return of approximately 9%).
	Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or make additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial position may be significantly adversely affected.
	On April 1, 2013, Generation submitted its NRC-required biennial decommissioning funding status report as of December 31, 2012. As of December 31, 2012, Generation provided adequate funding assurance for all of its units, including Limerick Unit 1, where Generation had in place a $115 million parent guarantee to cover the NRC minimum funding assurance requirements. On October 2, 2013, the NRC issued summary findings from the NRC Staff’s review of the 2013 decommissioning funding status reports for all 104 operating reactors, including the Generation operating units. Based on that review, the NRC Staff determined that Generation provided decommissioning funding assurance under the NRC regulations for all of its operating units, including Limerick Unit 1. On March 26, 2014, in accordance with a NRC requirement with respect to units involved in a merger or acquisition, CENG submitted its NRC-required decommissioning funding status report as of December 31, 2013 and no additional financial assurance was required.
	On March 31, 2014, Generation submitted its NRC required annual decommissioning funding report as of December 31, 2013 for reactors that have been shut down except for Zion Station which is included on a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). This submittal also included the required updated financial tests for the Limerick Unit 1 parent guarantee. There was no change to the amount of the parent guarantee, or the funding status of these reactors. Adequate decommissioning funding assurance is in place for all reactors owned by Generation. During 2014, the operating license for Limerick Unit 1 was extended by 20 years. As a result of this extension, and the subsequent funding assurance calculation performed by the NRC, it was found that the parent company guarantee was no longer required and thus the parent guarantee for Limerick Unit 1 will be cancelled effective March 13, 2015. See Note 3 — Regulatory Matters for additional information regarding the operating license extension for Limerick Unit 1.
	Generation will file its next biennial decommissioning funding status report with the NRC on or before March 31, 2015. That report will reflect 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 do not have adequate funding assurance based on the most recent calculations as of December 31, 2014. NRC guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding assurance shortfalls. During this period, Generation will monitor funding assurance and new developments, including the impact of a 20-year license renewal for Braidwood and Byron, to assess the status of funding assurance and to take steps, if necessary, to address any funding shortfall on these funds on or before March 31, 2017.
On January 31, 2013, Generation received a letter from the NRC indicating that the NRC has identified potential “apparent violations” of its regulations because of alleged inaccuracies in the Decommissioning Funding Status reports for 2005, 2006, 2007, and 2009. The NRC asserted that Generation’s status reports deliberately reflected cost estimates for decommissioning its nuclear plants that were less than what the NRC says are the minimum amounts required by NRC regulations. The January 31, 2013 letter from the NRC does not take issue with Generation's current funding status, and as reflected in Generation's April 1, 2013 decommissioning funding status report referenced above, Generation continues to provide adequate funding assurance for each of its units. Generation met with the NRC on April 30, 2013 for a pre-decisional enforcement conference to provide additional information to explain why Generation believes that it complied with the regulatory requirements and did not deliberately or otherwise provide incomplete or inaccurate information in its decommissioning funding status reports. On May 1, 2014, the NRC issued its final determination. Although the NRC determined that these historical status reports did not provide complete and accurate information, the violation of the regulatory requirements was not a deliberate violation. The NRC noted the low safety significance and Generation's corrective actions to satisfy the NRC Staff's expectations and issued a Severity Level IV violation, with no monetary penalty. A Severity Level IV violation is the lowest level of violation.
In addition, on June 24, 2013, Exelon received a subpoena from the SEC requesting that Exelon provide the SEC with certain documents generally relating to Exelon and Generation’s reporting and funding of the future decommissioning of Generation’s nuclear power plants. Exelon and Generation have cooperated with the SEC and provided the requested documents. On February 13, 2014, Exelon received a letter from the SEC confirming that it had concluded its investigation and that no further action was anticipated based on information provided by Exelon.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related activities. ComEd, PECO and BGE have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2013 to December 31, 2014:
	Exelon			Generation			ComEd			PECO			BGE
Non-nuclear AROs at January 1, 2013	$	343		$	207		$	99		$	29		$	8
Net increase (decrease) due to changes in, and	1			(11		)	—			—			12
timing of, estimated future cash flows (a)
Development projects (b)	2			2			—			—			—
Accretion expense (c)	18			13			4			1			—
Payments	(13		)	(10		)	(2		)	—			(1		)
Non-nuclear AROs at December 31, 2013 (d)	351			201			101			30			19
Net increase (decrease) due to changes in, and	(1		)	(2		)	2			—			(1		)
timing of, estimated future cash flows (a)
Development projects (b)	11			11			—			—			—
Accretion expense (c)	15			11			3			1			—
Liabilities held for sale (e)	(4		)	(4		)	—			—			—
Sale of generating assets (f)	(20		)	(20		)	—			—			—
Payments	(6		)	(3		)	(2		)	(1		)	—
Non-nuclear AROs at December 31, 2014 (d)	$	346		$	194		$	104		$	30		$	18
________________________
(a)	During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013.
(b)	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.
(c)	For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(d)	During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.
(e)	Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.
(f)	Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.

Retirement_Benefits_Exelon_Gen

Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)	Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)
	As of December 31, 2014, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees. The table below shows the pension and postretirement benefit plans in which each operating company participated at December 31, 2014.
	On April 1, 2014, as a result of the consolidation of CENG into Generation, the obligations associated with CENG's pension and other postretirement plans are reflected in the disclosures below based on an April 1, 2014 valuation adjusted for subsequent activity. Exelon assumed sponsorship of the CENG pension and other postretirement benefit plans in the third quarter of 2014 when the employees transferred to Exelon. CENG will fund the underfunded balances of the pension and other postretirement benefit plans measured at July 14, 2014 on an agreed payment schedule or upon the occurrence of certain specified events, such as EDF's disposition of a majority of its interest in CENG. Payments received from CENG related to the funded plans will be contributed to the appropriate benefit trusts.
			Operating Company
	Name of Plan:		Generation		ComEd		PECO		BGE		BSC
	Qualified Pension Plans:
	Exelon Corporation Retirement Program(a)		X		X		X		X		X
	Exelon Corporation Cash Balance Pension Plan(a)		X		X		X		X		X
	Exelon Corporation Pension Plan for Bargaining		X		X						X
	Unit Employees(a)
	Exelon New England Union Employees Pension		X
	Plan(a)
	Exelon Employee Pension Plan for Clinton, TMI		X		X						X
	and Oyster Creek(a)
	Pension Plan of Constellation Energy Group, Inc.(b)		X		X		X		X		X
	Pension Plan of Constellation Energy Nuclear		X						X		X
	Group, LLC(c)
	Nine Mile Point Pension Plan(c)		X								X
	Constellation Mystic Power, LLC Union Employees		X
	Pension Plan Including Plan A and Plan B(b)
	Non-Qualified Pension Plans:
	Exelon Corporation Supplemental Pension Benefit		X		X		X				X
	Plan and 2000 Excess Benefit Plan(a)
	Exelon Corporation Supplemental Management		X		X		X		X		X
	Retirement Plan(a)
	Constellation Energy Group, Inc. Senior Executive		X						X		X
	Supplemental Plan(b)
	Constellation Energy Group, Inc. Supplemental		X						X		X
	Pension Plan(b)
	Constellation Energy Group, Inc. Benefits		X						X		X
	Restoration Plan(b)
	Constellation Nuclear Plan, LLC Executive		X								X
	Retirement Plan(c)
	Constellation Energy Nuclear Plan, LLC Benefits		X								X
	Restoration Plan(c)
	Baltimore Gas & Electric Company Executive		X						X		X
	Benefit Plan(b)
	Baltimore Gas & Electric Company Manager		X						X		X
	Benefit Plan(b)
			Operating Company
	Name of Plan:		Generation		ComEd		PECO		BGE		BSC
	Other Postretirement Benefit Plans:
	PECO Energy Company Retiree Medical Plan(a)		X		X		X		X		X
	Exelon Corporation Health Care Program(a)		X		X				X		X
	Exelon Corporation Employees’ Life Insurance		X		X		X		X		X
	Plan(a)
	Constellation Energy Group, Inc. Retiree Medical		X		X		X		X		X
	Plan(b)
	Constellation Energy Group, Inc. Retiree Dental		X						X		X
	Plan(b)
	Constellation Energy Group, Inc. Employee Life		X		X		X		X		X
	Insurance Plan and Family Life Insurance Plan(b)
	Constellation Mystic Power, LLC		X
	Post-Employment Medical Account Savings Plan(b)
	Exelon New England Union Post-Employment		X
	Medical Savings Account Plan(a)
	Retiree Medical Plan of Constellation Energy		X						X		X
	Nuclear Group LLC(c)
	Retiree Dental Plan of Constellation Energy		X						X		X
	Nuclear Group LLC(c)
	Nine Mile Point Nuclear Station, LLC Medical Care		X								X
	and Prescription Drug Plan for Retired
	Employees(c)
	______________________
(a)	These plans are collectively referred to as the Legacy Exelon plans.
(b)	These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans.
(c)	These plans are collectively referred to as the Legacy CENG plans.
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-represented employees participate in cash balance pension plans. Exelon has elected that the trusts underlying these plans be treated under the IRC as qualified trusts. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to certain IRC limitations.
Benefit Obligations, Plan Assets and Funded Status
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with offsetting entries to Accumulated other comprehensive income (AOCI) and regulatory assets (liabilities), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31.
During the first quarter of 2014, Exelon received an updated valuation of its legacy pension and other postretirement benefit obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $35 million and an increase to the other postretirement benefit obligation of $12 million. Additionally, Accumulated other comprehensive loss (AOCL) increased by approximately $12 million (after tax), regulatory assets increased by approximately $34 million, and regulatory liabilities increased by approximately $5 million. During the second quarter of 2014, Exelon received an updated valuation for the remainder of its pension and other postretirement obligations to reflect actual census data as of January 1, 2014. This valuation resulted in an increase to the pension obligation of $13 million and an increase to the other postretirement benefit obligation of $3 million. Additionally, AOCL increased by approximately $1 million (after tax) and regulatory assets increased by approximately $15 million.
In April 2014, Exelon announced plan design changes for certain other postretirement benefit plans, which required an interim remeasurement of the benefit obligation for those plans using assumptions as of April 30, 2014, including updated discount rates and asset values. The remeasurement resulted in a decrease to Exelon's non-pension postretirement benefit obligations, regulatory assets, and AOCL of approximately $790 million, $240 million, and $259 million (after tax), respectively, and an increase in regulatory liabilities of approximately $125 million.
The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:
	Pension Benefits								Other
									Postretirement Benefits
	2014				2013				2014				2013
Change in benefit obligation:
Net benefit obligation at beginning of year	$	15,459			$	16,800			$	4,451			$	4,820
Service cost	293				317				117				162
Interest cost	749				650				186				194
Plan participants’ contributions	—				—				42				34
Actuarial loss (gain)	2,095				(1,363		)		502				(551		)
Plan amendments	—				1				(1,012		)		15
Acquisitions/divestitures(a)	594				—				142				—
Curtailments	(8		)		—				—				—
Settlements	(30		)		(69		)		—				—
Gross benefits paid	(896		)		(877		)		(231		)		(223		)
Net benefit obligation at end of year	$	18,256			$	15,459			$	4,197			$	4,451
	Pension Benefits								Other
									Postretirement Benefits
	2014				2013				2014				2013
Change in plan assets:
Fair value of net plan assets at beginning of year	$	13,571			$	13,357			$	2,238			$	2,135
Actual return on plan assets	1,443				821				90				209
Employer contributions	332				339				291				83
Plan participants’ contributions	—				—				42				34
Benefits paid	(896		)		(877		)		(231		)		(223		)
Acquisitions/divestitures(a)	454				—				—				—
Settlements	(30		)		(69		)		—				—
Fair value of net plan assets at end of year	$	14,874			$	13,571			$	2,430			$	2,238
_______________________
(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet.  As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014.  See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
	Pension Benefits								Other
									Postretirement Benefits
	2014				2013				2014				2013
Other current liabilities	$	16			$	12			$	25			$	23
Pension obligations	3,366				1,876				—				—
Non-pension postretirement benefit obligations	—				—				1,742				2,190
Unfunded status (net benefit obligation less net plan	$	3,382			$	1,888			$	1,767			$	2,213
assets)
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan. The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.
The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.
	PBO in
	excess of plan assets
	2014				2013
Projected benefit obligation	$	18,256			$	15,452
Fair value of net plan assets	14,874				13,564
	ABO in
	excess of plan assets
	2014				2013
Projected benefit obligation	$	18,256			$	15,452
Accumulated benefit obligation	17,191				14,552
Fair value of net plan assets	14,874				13,564
On a PBO basis, the plans were funded at 81% at December 31, 2014 compared to 88% at December 31, 2013. On an ABO basis, the plans were funded at 87% at December 31, 2014 compared to 93% at December 31, 2013. The ABO differs from the PBO in that the ABO includes no assumption about future compensation levels.
Components of Net Periodic Benefit Costs
The majority of the 2014 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 4.80%. Certain of the pension plans were remeasured as of October 31, 2014 using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.95%. Costs incurred during the year ended December 31, 2014 reflect the impact of this remeasurement. The majority of the 2014 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets of 6.59% for funded plans and a discount rate of 4.90% for all plans. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for December 31, 2014 reflect the impact of this remeasurement.
On July 14, 2014 Exelon became the sponsor of the pension and other postretirement plans formerly sponsored by CENG. The components of cost for the CENG plans are included in the table below for the period from April 1, 2014 to December 31, 2014, and reflect the valuation performed on April 1, 2014 upon consolidation of CENG. Refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC for further details on the consolidation of CENG. The 2014 pension benefit cost for these plans is calculated using an expected long-term rate of return on plan assets of 7.75% and discount rates ranging from 3.60% - 4.30%. The majority of the 2014 other postretirement benefit cost for the CENG plans is calculated using a discount rate of 4.55%.
A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant's Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2014, 2013 and 2012.
	Pension Benefits												Other
													Postretirement Benefits
	2014				2013				2012				2014				2013			2012
Components of net periodic
benefit cost:
Service cost	$	293			$	317			$	280			$	117			$	162		$	156
Interest cost	749				650				698				186				194			205
Expected return on assets	(994		)		(1,015		)		(988		)		(154		)		(132		)	(115		)
Amortization of:
Transition obligation	—				—				—				—				—			11
Prior service cost (credit)	14				14				15				(122		)		(19		)	(17		)
Actuarial loss	420				562				450				50				83			81
Curtailment benefits	—				—				—				—				—			(7		)
Settlement charges	2				9				31				—				—			—
Contractual termination benefits (a)	—				—				14				—				—			6
Net periodic benefit cost	$	484			$	537			$	500			$	77			$	288		$	320
______________________
(a)	ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012.
Through Exelon’s postretirement benefit plans, the Registrants provide retirees with prescription drug coverage. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Modernization Act), enacted on December 8, 2003, introduced a prescription drug benefit under Medicare as well as a Federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to the Medicare prescription drug benefit (Part D subsidy). Management believes the prescription drug benefit provided under Exelon’s postretirement benefit plans meets the requirements for the subsidy. In December 2011, the Company decided that beginning in 2013, it would no longer elect to take the direct Part D subsidy. This resulted in a $17 million increase in cost for the year ended December 31, 2012 related to the amortization of an actuarial loss. Beginning in 2013, eligible employees are offered an Employee Group Waiver Plan (EGWP), a standard Medicare Part D Plan, with a supplemental “wrap," which contains a wraparound prescription drug design that allows the company to provide benefits above those available under the EGWP.
Components of AOCI and Regulatory Assets
Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2014, 2013 and 2012 for all plans combined.
	Pension Benefits												Other
													Postretirement Benefits
	2014				2013				2012				2014				2013			2012
Changes in plan assets and benefit
obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial (gain) loss	$	1,639			$	(1,169	)		$	1,693			$	561			$	(628	)	$	304
Amortization of actuarial loss	(420		)		(562		)		(450		)		(50		)		(83		)	(81		)
Current year prior service (credit) cost	—				—				1				(1,012		)		15			(109		)
Amortization of prior service (cost)	(14		)		(14		)		(15		)		122				19			17
credit
Current year transition (asset)	—				—				—				—				—			1
obligation
Amortization of transition asset	—				—				—				—				—			(11		)
(obligation)
Curtailments	—				—				(10		)		—				—			(1		)
Settlements	(2		)		(8		)		(31		)		—				—			—
Total recognized in AOCI and	$	1,203			$	(1,753	)		$	1,188			$	(379	)		$	(677	)	$	120
regulatory assets (liabilities) (a)
______________________
(a)	Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012.
The following table provides the components of Exelon’s gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as components of periodic benefit cost at December 31, 2014 and 2013, respectively, for all plans combined:
	Pension Benefits								Other
									Postretirement Benefits
	2014				2013				2014				2013
Prior service cost (credit)	$	49			$	62			$	(963	)		$	(73	)
Actuarial loss	7,407				6,192				985				474
Total (a)	$	7,456			$	6,254			$	22			$	401
_______________________
(a)	Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2013.
The following table provides the components of Exelon’s AOCI and regulatory assets at December 31, 2014 (included in the table above) that are expected to be amortized as components of periodic benefit cost in 2015. These estimates are subject to the completion of an actuarial valuation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2015 and actual claims activity as of December 31, 2014. The valuation is expected to be completed in the first quarter of 2015 for the majority of the benefit plans.
	Pension Benefits				Other
					Postretirement Benefits
Prior service cost (credit)	$	13			$	(175	)
Actuarial loss	562				74
Total (a)	$	575			$	(101	)
___________________
(a)	Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, respectively.
Assumptions
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirement plans involves various factors, including the development of valuation assumptions and accounting policy elections. When developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and costs is impacted by several assumptions including the discount rate applied to benefit obligations, the long-term EROA, Exelon’s expected level of contributions to the plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs. Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and rate of compensation increases, employee age and length of service, among other factors.
Expected Rate of Return. In selecting the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Mortality. For the December 31, 2014 actuarial valuation, Exelon changed its assumption of mortality to reflect more recent expectations of future improvements in life expectancy. The change was supported through completion of an experience study and supplemental analyses performed by its actuaries. The change in assumption resulted in increases of $361 million and $117 million in the pension and other postretirement benefits obligations, respectively.
The following assumptions were used to determine the benefit obligations for the plans at December 31, 2014, 2013 and 2012. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
Discount rate	3.94	%		4.8	%		3.92	%		3.92	%		4.9	%		4	%
Rate of			(a)			(b)			(c)			(a)			(b)			(c)
compensation
increase
Mortality table	RP-2000 table with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA			RP-2000 table with Scale AA improvements			RP-2000 table with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements
				improvements
Health care cost	N/A			N/A			N/A			6.00%			6.00%			6.50%
trend on covered										decreasing			decreasing			decreasing
charges										to			to			to
										ultimate			ultimate			ultimate
										trend of			trend of			trend of
										5.00% in			5.00% in			5.00% in
										2017			2017			2017
_____________________________
(a)	3.25% for 2015-2019 and 3.75% thereafter.
(b)	3.25% for 2014-2018 and 3.75% thereafter.
(c)	3.25% for 2013-2017 and 3.75% thereafter.
The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2014, 2013 and 2012:
	Pension Benefits									Other Postretirement Benefits
	2014			2013			2012			2014			2013			2012
Discount rate	4.8	%	(a)	3.92	%	(b)	4.74	%	(c)	4.9	%	(a)	4	%	(b)	4.8	%	(c)
Expected return on	7	%	(d)	7.5	%	(d)	7.5	%	(d)	6.59	%	(d)	6.45	%	(d)	6.68	%	(d)
plan assets
Rate of			(e)			(f)	3.75	%				(e)			(f)	3.75	%
compensation
increase
Mortality table	RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements
Health care cost	N/A			N/A			N/A			6.00%			6.50%			6.50%
trend on covered										decreasing			decreasing			decreasing
charges										to			to			to
										ultimate			ultimate			ultimate
										trend of			trend of			trend of
										5.00% in			5.00% in			5.00% in
										2017			2017			2017
___________________________
(a)	The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet.  As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.
(b)	The discount rates above represent the initial discount rates used to establish Exelon's pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these measurements.
(c)	The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurements.
(d)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.
(e)	3.25% for 2014-2018 and 3.75% thereafter.
(f)	3.25% for 2013-2017 and 3.75% thereafter.
Assumed health care cost trend rates impact the costs reported for Exelon's other postretirement benefit plans for participants populations with plan designs that do not have a cap on cost growth. A one percentage point change in assumed health care cost trend rates would have the following effects:
Effect of a one percentage point increase in assumed health care cost trend:
on 2014 total service and interest cost components	$	35
on postretirement benefit obligation at December 31, 2014	162
Effect of a one percentage point decrease in assumed health care cost trend:
on 2014 total service and interest cost components	(24		)
on postretirement benefit obligation at December 31, 2014	(113		)
Health Care Reform Legislation
In March 2010, the Health Care Reform Acts were signed into law, which contain a number of provisions that impact retiree health care plans provided by employers.  One such provision imposes an excise tax on certain high-cost plans beginning in 2018, whereby premiums paid over a prescribed threshold will be taxed at a 40% rate. Although the excise tax does not go into effect until 2018, accounting guidance requires Exelon to incorporate the estimated impact of the excise tax in its annual actuarial valuation. The application of the legislation is still unclear and Exelon continues to monitor the Department of Labor and IRS for additional guidance. Certain key assumptions are required to estimate the impact of the excise tax on Exelon’s other postretirement benefit obligation, including projected inflation rates (based on the CPI) and whether pre- and post- 65 retiree populations can be aggregated in determining the premium values of health care benefits. Exelon reflected its best estimate of the expected impact in its annual actuarial valuation.
Contributions
The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans:
	Pension Benefits												Other Postretirement Benefits
	2014(c)				2013				2012				2014				2013			2012 (a)
Generation	$	173			$	119			$	48			$	124			$	30		$	135
ComEd	122				118				25				125				4			119
PECO	11				11				13				5				20			33
BGE (b)	—				—				—				17				24			12
BSC(d)	26				91				63				20				5			24
Exelon	$	332			$	339			$	149			$	291			$	83		$	323
_________________________
(a)	The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012. Effective January 1, 2013, Exelon is no longer receiving this subsidy.
(b)	BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statements.
(c)	Exelon's and Generation's pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG.
(d)	Includes $9 million, $72 million, and $13 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2014, 2013, and 2012, respectively.
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the pension obligation and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). Additionally, for Exelon’s largest qualified pension plan, until the plan is fully funded on an ABO basis, the projected contribution reflects a funding strategy of contributing $250 million. This level funding strategy helps minimize volatility of future period required pension contributions.
Exelon plans to contribute $447 million to its qualified pension plans in 2015, of which Generation, ComEd, PECO, and BGE will contribute $230 million, $138 million, $40 million, and $1 million, respectively. Exelon's and Generation's expected qualified pension plan contributions above include $36 million related to the legacy CENG plans that will be funded by CENG as provided in an EMA between Exelon and CENG.
Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon plans to make non-qualified pension plan benefit payments of $15 million in 2015, of which Generation, ComEd, PECO, and BGE will make payments of $6 million, $1 million, $1 million and $1 million, respectively.
Unlike the qualified pension plans, other postretirement plans are not subject to statutory minimum contribution requirements. Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulatory expectations and best assure continued rate recovery). In 2015, Exelon anticipates funding its other postretirement benefit plans based on the funding considerations discussed above, with the exception of those plans which remain unfunded. Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $37 million in 2015, of which Generation, ComEd, PECO, and BGE expect to contribute $17 million, $2 million, $0 million, and $17 million, respectively.
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2014 were:
	Pension				Other
	Benefits				Postretirement
					Benefits
2015	$	1,064			$	217
2016	962				223
2017	979				230
2018	1,004				236
2019	1,032				247
2020 through 2024	5,825				1,373
Total estimated future benefit payments through 2024	$	10,866			$	2,526
Allocation to Exelon Subsidiaries
Generation, ComEd, PECO, and BGE account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer accounting. Employee-related assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. The obligation for Generation, ComEd and PECO reflects the initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated the components of pension and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee participation in each participating unit. Pension and postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon is allocating costs related to its legacy Exelon pension and postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are being allocated based on accounting cost. The impact of this allocation methodology change is not material to any Registrant. For legacy CEG and legacy CENG plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be, allocated to the subsidiaries based on employee participation (both active and retired).
The amounts below were included in capital expenditures and Operating and maintenance expense for the years ended December 31, 2014, 2013 and 2012, respectively, for Generation’s, ComEd’s, PECO’s, BSC’s and BGE’s allocated portion of the pension and postretirement benefit plan costs. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:
For the Year Ended December 31,	Generation				ComEd				PECO				BSC (a)				BGE (b)(c)			Exelon
2014	$	250			$	162			$	36			$	46			$	67		561
2013	347				309				43				71				55			825
2012	341				282				50				99				60			820
_____________________
(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge.
(b)	The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 2012.
(c)	BGE’s pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of December 31, 2012.
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for Exelon’s other postretirement plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.
Exelon used an EROA of 7.00% and 6.46% to estimate its 2015 pension and other postretirement benefit costs, respectively.
Exelon’s pension and other postretirement benefit plan target asset allocations and December 31, 2014 and 2013 asset allocations were as follows:
Pension Plans
				Percentage of Plan Assets
				at December 31,
Asset Category	Target Allocation			2014			2013
Equity securities	32	%		33	%		35	%
Fixed income securities	37	%		37			37
Alternative investments (a)	31	%		30			28
Total				100	%		100	%
Other Postretirement Benefit Plans
				Percentage of Plan Assets
				at December 31,
Asset Category	Target Allocation			2014			2013
Equity securities	41	%		42	%		45	%
Fixed income securities	34	%		34			37
Alternative investments (a)	25	%		24			18
Total				100	%		100	%
___________________
(a)	Alternative investments include private equity, hedge funds and real estate.
Concentrations of Credit Risk. Exelon evaluated its pension and other postretirement benefit plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2014. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2014, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in Exelon’s pension and other postretirement benefit plan assets.
Fair Value Measurements
The following table presents Exelon’s pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2014 and 2013:
At December 31, 2014 (a)	Level 1				Level 2				Level 3				Total
Pension plan assets
Cash equivalents	$	1			$	—			$	—			$	1
Equities:
Domestic	1,556				1,133				2				2,691
Foreign	1,705				316				—				2,021
Equities subtotal	3,261				1,449				2				4,712
Fixed income:
Debt securities issued by the U.S. Treasury	1,051				88				—				1,139
and other U.S. government corporations and agencies
Debt securities issued by states of the	—				80				—				80
United States and by political subdivisions of the states
Corporate debt securities	—				3,125				120				3,245
Other	—				942				152				1,094
Derivative instruments (b):
Assets	—				4				—				4
Liabilities	—				(16		)		—				(16		)
Fixed income subtotal	1,051				4,223				272				5,546
Private equity	—				—				904				904
Hedge funds	—				1,355				1,329				2,684
Real estate	243				—				744				987
Pension plan assets subtotal	4,556				7,027				3,251				14,834
At December 31, 2014 (a)	Level 1				Level 2				Level 3				Total
Other postretirement benefit plan assets
Cash equivalents	11				—				—				11
Equities:
Domestic	296				378				—				674
Foreign	184				147				—				331
Equities subtotal	480				525				—				1,005
Fixed income:
Debt securities issued by the U.S. Treasury	15				59				—				74
and other U.S. government corporations and agencies
Debt securities issued by states of the	—				197				—				197
United States and by political subdivisions of the states
Corporate debt securities	—				42				—				42
Other	253				272				—				525
Fixed income subtotal	268				570				—				838
Hedge funds	—				339				110				449
Real estate	8				—				116				124
Other postretirement benefit plan assets subtotal	767				1,434				226				2,427
Total pension and other postretirement benefit plan assets (c)	$	5,323			$	8,461			$	3,477			$	17,261
At December 31, 2013 (a)	Level 1				Level 2				Level 3				Total
Pension plan assets
Equities:
Domestic	$	1,587			$	865			$	2			$	2,454
Foreign	1,773				302				—				2,075
Equities subtotal	3,360				1,167				2				4,529
Fixed income:
Debt securities issued by the U.S. Treasury	908				99				—				1,007
and other U.S. government corporations and agencies
Debt securities issued by states of the	—				88				—				88
United States and by political subdivisions of the states
Foreign debt securities	—				205				—				205
Corporate debt securities	—				2,927				41				2,968
Other	5				899				—				904
Derivative instruments (b):
Assets	—				7				—				7
Liabilities	—				(134		)		—				(134		)
Fixed income subtotal	913				4,091				41				5,045
Private equity	—				—				806				806
Hedge funds	—				1,266				1,039				2,305
Real estate	264				2				582				848
Pension plan assets subtotal	4,537				6,526				2,470				13,533
At December 31, 2013 (a)	Level 1				Level 2				Level 3				Total
Other postretirement benefit plan assets
Cash equivalents	51				—				—				51
Equities:
Domestic	296				345				—				641
Foreign	154				170				—				324
Equities subtotal	450				515				—				965
Fixed income:
Debt securities issued by the U.S. Treasury	17				46				—				63
and other U.S. government corporations and agencies
Debt securities issued by states of the	—				149				—				149
United States and by political subdivisions of the states
Foreign debt securities	—				2				—				2
Corporate debt securities	—				50				—				50
Other	305				225				—				530
Fixed income subtotal	322				472				—				794
Private equity	—				—				2				2
Hedge funds	—				295				4				299
Real estate	8				5				109				122
Other postretirement benefit plan assets subtotal	831				1,287				115				2,233
Total pension and other postretirement benefit	$	5,368			$	7,813			$	2,585			$	15,766
plan assets (c)
__________________________
(a)	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)	Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c)	Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.
The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2014 and 2013:
	Hedge				Private				Real				Fixed				Equities			Total
	funds				equity				estate				income
Pension Assets
Balance as of January 1, 2014	$	1,039			$	806			$	582			$	41			$	2		$	2,470
Actual return on plan assets:
Relating to assets still held at the	77				112				83				7				—			279
reporting date
Relating to assets sold during the	3				—				—				—				—			3
period
Purchases, sales and settlements:
Purchases	311				173				136				227				—			847
Sales	(38		)		—				(19		)		(3		)		—			(60		)
Settlements (a)	(33		)		(203		)		(65		)		—				—			(301		)
Transfers into (out of) Level 3 (b)(c)	(30		)		16				27				—				—			13
Balance as of December 31, 2014	$	1,329			$	904			$	744			$	272			$	2		$	3,251
Other Postretirement Benefits
Balance as of January 1, 2014	$	4			$	2			$	109			$	—			$	—		$	115
Actual return on plan assets:
Relating to assets still held at the	1				—				13				—				—			14
reporting date
Purchases, sales and settlements:
Purchases	109				1				1				—				—			111
Sales	(4		)		(2		)		(7		)		—				—			(13		)
Settlements (a)	—				(1		)		—				—				—			(1		)
Balance as of December 31, 2014	$	110			$	—			$	116			$	—			$	—		$	226
	Hedge				Private				Real				Fixed				Equities			Total
	funds				equity				estate				income
Pension Assets
Balance as of January 1, 2013	$	1,235			$	754			$	426			$	—			$	—		$	2,415
Actual return on plan assets:
Relating to assets still held at the	143				86				63				—				—			292
reporting date
Relating to assets sold during the	3				—				(4		)		—				—			(1		)
period
Purchases, sales and settlements:
Purchases	360				123				226				41				2			752
Sales	(76		)		—				(91		)		—				—			(167		)
Settlements (a)	(3		)		(157		)		(38		)		—				—			(198		)
Transfers into (out of) Level 3 (c)	(623		)		—				—				—				—			(623		)
Balance as of December 31, 2013	$	1,039			$	806			$	582			$	41			$	2		$	2,470
Other Postretirement Benefits
Balance as of January 1, 2013	$	12			$	1			$	95			$	—			$	—		$	108
Actual return on plan assets:
Relating to assets still held at the	1				—				11				—				—			12
reporting date
Purchases, sales and settlements:
Purchases	—				1				3				—				—			4
Sales	(1		)		—				—				—				—			(1		)
Settlements (a)	(4		)		—				—				—				—			(4		)
Transfers into (out of) Level 3 (c)	(4		)		—				—				—				—			(4		)
Balance as of December 31, 2013	$	4			$	2			$	109			$	—			$	—		$	115
________________________
(a)	Represents cash settlements only.
(b)	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.
(c)	As of January 1, 2014 and January 1, 2013, hedge fund investments that contained redemption restrictions limiting Exelon’s ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2014 and December 31, 2013, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $43 million and $627 million in 2014 and 2013 respectively.
There were no transfers between Level 1 and Level 2 during the twelve months ended December 31, 2014 for the pension and other postretirement benefit plan assets.
Valuation Techniques Used to Determine Fair Value
Cash equivalents. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.
Equities. Equities consist of individually held equity securities, equity mutual funds and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are obtained from direct feeds from market exchanges, which Exelon is able to independently corroborate. Equity securities held individually, including rights and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. Equity securities are valued based on quoted prices in active markets and are categorized as Level 1. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies that hold certain investments in accordance with a stated set of fund objectives, which are consistent with the plans’ overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2.
Fixed income. For fixed income securities, which consist primarily of corporate debt securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class or issue for each security. The trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon has obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2
Other fixed income investments primarily consist of fixed income commingled funds, mutual funds, and short-term investment funds, which are maintained by investment companies and hold certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Certain fixed income commingled funds are valued using the NAV per fund share, which is based on the valuation of the underlying investments and include significant unobservable inputs. These funds have been categorized as Level 3.
Derivative instruments consisting primarily of interest rate swaps to manage risk are recorded at fair value. Derivative instruments are valued based on external price data of comparable securities and have been categorized as Level 2.
Private equity. Private equity investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments and investments in natural resources. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows and market based comparable data. Since these valuation inputs are not highly observable, private equity investments have been categorized as Level 3.
Hedge funds. Hedge fund investments include those seeking to maximize absolute returns using a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or ownership interest of the investments. Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate. For Exelon’s investments that have terms that allow redemption within a reasonable period of time from the measurement date, the hedge fund investments are categorized as Level 2. For investments that have restrictions that may limit Exelon’s ability to redeem the investments at the measurement date or within a reasonable period of time, the hedge fund investments are categorized as Level 3.
Real estate. Real estate investment trusts valued daily based on quoted prices in active markets are categorized as Level 1. Real estate commingled 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. Since these funds are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities. These funds have been categorized as Level 2. Other real estate funds are funds with a direct investment in a pool of real estate properties. These funds are valued by investment managers on a periodic basis using pricing models that use independent appraisals from sources with professional qualifications. Since these valuation inputs are not highly observable, these real estate funds have been categorized as Level 3.
As of December 31, 2014, Exelon has outstanding commitments to invest in private equity and real estate investments of approximately $825 million. These commitments will be funded by Exelon’s existing pension and other postretirement benefit trusts.
Defined Contribution Savings Plan (Exelon, Generation, ComEd, PECO and BGE)
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents matching contributions to the savings plan for the years ended December 31, 2014, 2013 and 2012:
For the Year Ended December 31,	Exelon				Generation				ComEd				PECO				BGE (a)			BSC (b)
2014	$	103			$	51			$	26			$	8			$	8		$	10
2013	85				40				22				8				8			7
2012	67				30				19				7				7			5
_________________________
(a)	BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012.
(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)	12 Months Ended
	Dec. 31, 2014
Restructuring and Related Activities [Abstract]
Severance (Exelon, Generation, ComEd and PECO)	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.
	CENG Integration-Related Severance
	In connection with the Master Agreement, Generation and CENG recorded a severance accrual in the fourth quarter of 2013 for the anticipated employee position reductions as a result of the integration of $2 million and $16 million, respectively. The majority of these positions are corporate and support positions at CENG. On April 1, 2014, the date the NOSA was executed, Generation consolidated the $19 million CENG severance liability pursuant to the Master Agreement. For the years ended December 31, 2014 and 2013, respectively, Exelon and Generation recorded severance benefit costs associated with the employee reductions of $3 million and $2 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The estimated amount of severance payments associated with this plan is expected to be approximately $24 million. As of December 31, 2014, management recorded its best estimate of severance benefits, which could be adjusted through the completion of the integration process if additional employee position reductions are identified or if employees resign prior to their agreed upon service termination date. Estimated costs to be incurred after December 31, 2014 are not material.
	Amounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration:
	Year Ended December 31, 2014		Exelon and Generation
	Severance Liability
	Balance at December 31, 2013		$	2
	Integration of CENG (a)		19
	Severance charges		3
	Payments		(11		)
	Balance at December 31, 2014		$	13
	______________________
	(a)	Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.
	Cash payments under the severance plan began in 2014. Substantially all cash payments under the plan are expected to be made by the end of 2015.
	Constellation Merger-Related Severance
	Upon closing the merger with Constellation, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration. The majority of these positions are corporate and Generation support positions. Since then, Exelon has identified specific employees to be severed pursuant to the merger-related staffing and selection process as well as employees that were previously identified for severance but have since accepted another position within Exelon and are no longer receiving a severance benefit. Exelon adjusts its accrual each quarter to reflect its best estimate of remaining severance costs.
	The amount of severance expense associated with the post-merger integration recognized for the twelve months ended December 31, 2014 and 2013 is not material. Estimated costs to be incurred after December 31, 2014 are not immaterial.
	For the year ended December 31, 2012, the Registrants recorded the following severance benefit costs associated with identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, except for those costs that were capitalized as regulatory assets related to ComEd and BGE:
	Year Ended December 31, 2012
	Severance Benefits (a)		Exelon (b)				Generation			ComEd (b)			PECO			BGE (b)
	Severance charges		$	124			$	80		$	14		$	7		$	17
	Stock compensation		7				4			1			—			1
	Other charges		7				4			1			—			1
	Total severance benefits		$	138			$	88		$	16		$	7		$	19
	________________________
	(a)	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
	(b)	Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period.
	Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations:
	Severance liability	Exelon				Generation			ComEd			PECO			BGE
	Balance at December 31, 2012	$	111			$	33		$	1		$	—		$	11
	Severance charges (a)	5				1			—			—			—
	Stock compensation	1				—			—			—			—
	Payments	(64		)		(24		)	(1		)	—			(5		)
	Balance at December 31, 2013	$	53			$	10		$	—		$	—		$	6
	Payments	(41		)		(7		)	—			—			(4		)
	Balance at December 31, 2014	$	12			$	3		$	—		$	—		$	2
	________________________
	(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon’s ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2014 and December 31, 2013.
	Substantially all cash payments under the plan are expected to be made by the end of 2016.
	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 years ended December 31, 2014, 2013, and 2012, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
	Severance Benefits (a)	Exelon				Generation			ComEd			PECO			BGE
	Severance Charges-2014	$	7			$	5		$	1		$	—		$	1
	Severance Charges-2013	18				16			2			—			—
	Severance Charges-2012	19				14			2			1			3
	________________________
	(a)	The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material.
	(b)	The amount of ongoing severance for Generation for the year ended December 31, 2014 includes a $3 million severance reserve as a result of anticipated employee position reductions due to recent acquisitions.
	The severance liability balances associated with these ongoing severance benefits as of December 31, 2014 and 2013 are not material.

Preferred_and_Preference_Secur

Preferred and Preference Securities (Exelon, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Preferred and Preference Securities (Exelon, ComEd, PECO and BGE)	Preferred and Preference Securities (Exelon, ComEd, PECO and BGE)
	At December 31, 2014 and 2013, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.
	Preferred and Preference Securities of Subsidiaries
	At December 31, 2014 and 2013, ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451 shares authorized, respectively, none of which were outstanding.
	On May 1, 2013, PECO redeemed all of its outstanding preferred securities. PECO had $87 million of cumulative preferred securities that were redeemable at its option at any time for the redemption price established when each series was issued. The redemption premium was treated as a reduction to Net income to arrive at Net income attributable to common shareholders utilized in the calculation of the earnings per share for Exelon.
	At December 31, 2014 and 2013, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and the outstanding amounts set forth below. Shares of BGE preference stock have no voting power except for the following:
	•	The preference stock has one vote per share on any charter amendment which would create or authorize any shares of stock ranking prior to or on a parity with the preference stock as to either dividends or distribution of assets, or which would substantially adversely affect the contract rights, as expressly set forth in BGE’s charter, of the preference stock, each of which requires the affirmative vote of two-thirds of all the shares of preference stock outstanding; and
	•	Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have one vote per share on all matters, until and unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.
				December 31,
		Redemption		2014	2013	2014		2013
		Price (a)		Shares Outstanding		Dollar Amount
	Series (without mandatory redemption)
	7.125%, 1993 Series	$	100	400,000	400,000	$	40	$	40
	6.97%, 1993 Series	100		500,000	500,000	50		50
	6.70%, 1993 Series	100		400,000	400,000	40		40
	6.99%, 1995 Series	100.35		600,000	600,000	60		60
	Total preference stock			1,900,000	1,900,000	$	190	$	190
	______________________
	(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

Common_Stock_Exelon_Generation

Common Stock (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Common Stock [Abstract]
Common Stock (Exelon, Generation, ComEd, PECO and BGE)	Common Stock (Exelon, Generation, ComEd, PECO and BGE)
	The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013:
									December 31,
									2014			2013
		Par Value				Shares Authorized			Shares Outstanding
	Common Stock
	Exelon	no par value				2,000,000,000			859,833,343			857,290,484
	ComEd	$	12.5			250,000,000			127,016,947			127,016,896
	PECO	no par value				500,000,000			170,478,507			170,478,507
	BGE	no par value				175,000,000			1,000			1,000
	ComEd had 73,533 and 73,709 warrants outstanding to purchase ComEd common stock at December 31, 2014 and 2013, respectively. The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three warrants. At December 31, 2014 and 2013, 24,511 and 24,570 shares of common stock, respectively, were reserved for the conversion of warrants.
	Equity Securities Offering
	In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements requiring Exelon to, at its election, prior to October 29, 2015; i) physically settle the transaction through the issuance of 57.5 million shares of its common stock in exchange for net proceeds at the forward price specified in the agreements of between approximately $1.8 billion and $1.9 billion, after consideration of underwriters discount of approximately $60 million and subject to certain adjustments as provided in the forward sales agreement, or ii) net settle the transaction either through the payment of cash or shares of its common stock based on the then current market value of the shares minus the value of the shares at the forward price, net of the underwriters discount and the daily accretion rate. 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. If Exelon elected to net share settle the contract as of December 31, 2014, Exelon would have been required to issue 4 million shares. 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 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.
	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 13 — Debt and Credit Agreements for further information on the equity units.
	Share Repurchases
	Share Repurchase Programs. In April 2004, Exelon’s Board of Directors approved a discretionary share repurchase program that allowed Exelon to repurchase shares of its common stock on a periodic basis in the open market. The share repurchase program was intended to mitigate, in part, the dilutive effect of shares issued under Exelon’s employee stock option plan and Exelon’s ESPP. The aggregate value of the shares of common stock repurchased pursuant to the program cannot exceed the economic benefit received after January 1, 2004 due to stock option exercises and share purchases pursuant to Exelon’s ESPP. The economic benefit consists of the direct cash proceeds from purchases of stock and the tax benefits associated with exercises of stock options. The 2004 share repurchase program had no specified limit on the number of shares that could be repurchased and no specified termination date. In 2008, Exelon management decided to defer indefinitely any share repurchases. Any shares repurchased are held as treasury shares, at cost, unless cancelled or reissued at the discretion of Exelon’s management. Under the share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2014. During 2014, 2013 and 2012, Exelon had no common stock repurchases.
	Stock-Based Compensation Plans
	Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At December 31, 2014, there were approximately 16 million shares authorized for issuance under the LTIP. For the years ended December 31, 2014, 2013 and 2012, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
	The Compensation Committee of Exelon’s Board of Directors changed the mix of awards granted under the LTIP in 2013 by eliminating stock options in favor of the use of full value shares, consisting of 67% performance shares and 33% restricted stock units. The performance share awards granted in 2013 will cliff vest at the end of a three-year performance period. The performance share awards granted in 2012 and earlier had a one-year performance period and vested ratably over three years. To address the reduction in annual award opportunity resulting from the transition to a three-year cliff vesting performance period, the Compensation Committee also approved a one-time grant of performance share transition awards in 2013, which vested one-third after one year, with the remaining balance vesting over a two-year performance period. These one-time 2013 performance share transition awards will be settled 50% in common stock and 50% in cash, except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain Exelon stock ownership requirements are satisfied. In addition to this change, in 2013 ComEd and in 2014 PECO and BGE transitioned from Exelon stock-based awards to cash award programs with payouts based on the performance of each respective utility. The following tables do not include expense related to these plans as they are not considered stock-based compensation plans under the applicable accounting guidance.
	The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
	Components of Stock-Based Compensation Expense	2014				2013				2012
	Performance share awards	$	59			$	48			$	46
	Restricted stock units	61				61				50
	Stock options	2				3				15
	Other stock-based awards	5				6				4
	Total stock-based compensation expense included in operating and	127				118				115
	maintenance expense
	Income tax benefit	(47		)		(44		)		(44		)
	Total after-tax stock-based compensation expense	$	80			$	74			$	71
	The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
	Subsidiaries	2014				2013				2012 (a)
	Generation	$	52			$	48			$	42
	ComEd	7				9				11
	PECO	3				5				5
	BGE	5				6				5
	BSC (b)	60				50				52
	Total	$	127			$	118			$	115
	________________________
	(a)	BGE’s stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. This amount is not included in Exelon’s stock-based compensation expense for the year ended December 31, 2012 shown in the table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary above.
	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.
	There were no significant stock-based compensation costs capitalized during the years ended December 31, 2014, 2013 and 2012.
	Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation costs. The tax deductions in excess of the benefits recorded throughout the requisite service period are recorded to common stock and are included in other financing activities within Exelon’s Consolidated Statements of Cash Flows. The following table presents information regarding Exelon’s tax benefits for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
		2014				2013				2012
	Realized tax benefit when exercised/distributed:
	Stock options	$	—			$	—			$	3
	Restricted stock units	17				11				11
	Performance share awards	11				11				7
	Stock deferral plan	—				1				—
	Excess tax benefits included in other financing activities of Exelon’s
	Consolidated Statements of Cash Flows:
	Stock options	$	—			$	—			$	2
	Stock Options
	Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were no stock options granted in 2013 or 2014. For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years. All stock options expire ten years from the date of grant.
	The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock options is generally four years. However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock options granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility.
	The fair value of each option is estimated on the date of grant using the Black-Scholes-Merton option-pricing model. The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the year ended 2012:
		Year ended December 31, 2012
	Dividend yield	5.28	%
	Expected volatility	23.2	%
Risk-free interest rate	1.3	%
Expected life (years)	6.25
Weighted average grant date fair value (per share)	4.18
The assumptions above relate to Exelon stock options granted in 2012 and therefore do not include stock options that were converted in connection with the merger with Constellation during the year ended 2012.
The dividend yield is based on several factors, including Exelon’s most recent dividend payment at the grant date and the average stock price over the previous year. Expected volatility is based on implied volatilities of traded stock options in Exelon’s common stock and historical volatility over the estimated expected life of the stock options. The risk-free interest rate for a security with a term equal to the expected life is based on a yield curve constructed from U.S. Treasury strips at the time of grant. For each year presented, the expected life represents the period of time the stock options are expected to be outstanding and is based on the simplified method. Exelon believes that the simplified method is appropriate due to several factors that result in historical exercise data not being sufficient to determine a reasonable estimate of expected term. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.
The following table presents information with respect to stock option activity for the year ended December 31, 2014:
	Shares			Weighted				Weighted		Aggregate
				Average				Average		Intrinsic
				Exercise				Remaining		Value
				Price				Contractual
				(per				Life
				share)				(years)
Balance of shares outstanding at December 31, 2013	21,035,445			$	46.07
Options exercised	(291,805	)		25.27
Options forfeited	(8,886	)		55.78
Options expired	(1,903,787	)		41.47
Balance of shares outstanding at December 31, 2014	18,830,967			$	46.85			4.11		$	29
Exercisable at December 31, 2014 (a)	18,398,932			$	47.01			4.04		$	29
____________________
(a)	Includes stock options issued to retirement eligible employees.
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2014, 2013 and 2012:
	Year Ended
	December 31,
	2014				2013				2012
Intrinsic value(a)	$	3			$	4			$	19
Cash received for exercise price	7				19				47
______________________
(a)	The difference between the market value on the date of exercise and the option exercise price.
The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2014:
	Shares			Weighted Average
				Exercise Price
				(per share)
Nonvested at December 31, 2013 (a)	847,118			$	40.22
Vested	(406,197	)		40.21
Forfeited	(8,886	)		55.78
Nonvested at December 31, 2014 (a)	432,035			$	39.91
_____________________
(a)	Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
At December 31, 2014, $1 million of total unrecognized compensation costs related to nonvested stock options are expected to be recognized over the remaining weighted-average period of 1.0 year.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized immediately upon the date of grant or through the date at which the employee reaches retirement eligibility. Exelon uses historical data to estimate employee forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.
The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2014:
	Shares			Weighted Average
				Grant Date Fair
				Value (per share)
Nonvested at December 31, 2013 (a)	3,386,697			$	34.1
Granted	2,252,574			28.71
Vested	(1,216,016	)		35.36
Forfeited	(86,094	)		31.99
Undistributed vested awards (b)	(578,943	)		29.17
Nonvested at December 31, 2014 (a)	3,758,218			$	31.27
_______________________
(a)	Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014.
The weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2014, 2013 and 2012 was $28.71, $31.06 and $39.94, respectively. At December 31, 2014 and 2013, Exelon had obligations related to outstanding restricted stock units not yet settled of $85 million and $77 million, respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2014, 2013 and 2012, Exelon settled restricted stock units with fair value totaling $43 million, $28 million and $25 million, respectively. At December 31, 2014, $59 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-average period of 2.1 years.
Performance Share Awards
Performance share awards are granted under the LTIP. The 2014 and 2013 performance share awards are being settled 50% in common stock and 50% in cash at the end of the three-year performance period except for awards granted to executive vice presidents and higher officers that may be settled 100% in cash if certain ownership requirements are satisfied. The performance shares granted prior to 2012 generally vest and settle over a three-year period with the holders receiving shares of common stock and/or cash annually during the vesting period.
The common stock portion of the performance share and one-time 2013 performance share transition awards is considered an equity award and is valued based on Exelon's stock price on the grant date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is established.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the graded-vesting method. For performance share and one-time performance share transition awards granted to retirement-eligible employees, the value of the performance shares in recognized ratably over the vesting period, which is the year of grant.
The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2014:
	Shares			Weighted Average
				Grant Date Fair
				Value (per share)
Nonvested at December 31, 2013 (a)	2,014,190			$	32.74
Granted	1,712,085			28.75
Change in performance	98,227			31.85
Vested	(497,714	)		35.05
Forfeited	(29,476	)		30.16
Undistributed vested awards (b)	(601,215	)		28.96
Nonvested at December 31, 2014 (a)	2,696,097			$	30.62
_______________________
(a)	Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014.
The weighted average grant date fair value (per share) of performance share awards granted during the years ended December 31, 2014, 2013 and 2012 was $28.75, $31.55, and $39.71, respectively. During the years ended December 31, 2014, 2013 and 2012, Exelon settled performance shares with a fair value totaling $27 million, $26 million and $23 million, respectively, of which $13 million, $12 million and $3 million was paid in cash, respectively. As of December 31, 2014, $54 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the remaining weighted-average period of 1.6 years.
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:
	December 31,
	2014				2013
Current liabilities(a)	$	28			$	13
Deferred credits and other liabilities (b)	36				24
Common stock	33				32
Total	$	97			$	69
__________________________
(a)	Represents the current liability related to performance share awards expected to be settled in cash.
(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings_Per_Share_and_Equity_

Earnings Per Share and Equity (Exelon)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Earnings Per Share and Equity (Exelon)	Earnings Per Share and Equity (Exelon)
	Earnings per Share
	Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted earnings per share and shows the effect of the stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:
		Year Ended December 31,
		2014		2013		2012
	Net income attributable to common shareholders	$	1,623	$	1,719	$	1,160
	Weighted average common shares outstanding—basic	860		856		816
	Assumed exercise and/or distributions of stock-based awards	4		4		3
	Weighted average common shares outstanding—diluted	864		860		819
	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 17 million in 2014, 20 million in 2013, and 14 million in 2012. 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 year ended December 31, 2014 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 year ended December 31, 2014 since issuance. Refer to Note 19 — 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 December 31, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases.

Changes_in_Accumulated_Other_C

Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO)	Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO)
	The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014 and 2013:
	For the Year Ended December 31, 2014	Gains and			Unrealized			Pension and			Foreign			AOCI of			Total
		(Losses) on			Gains and			Non-Pension			Currency			Equity
		Cash Flow			(Losses) on			Postretirement			Items			Investments
		Hedges			Marketable			Benefit Plan
					Securities			items
	Exelon (a)
	Beginning balance	$	120		$	2		$	(2,260	)	$	(10	)	$	108		$	(2,040	)
	OCI before reclassifications	(31		)	(1		)	(498		)	(9		)	11			(528		)
	Amounts reclassified from AOCI (b)	(117		)	2			118			—			(119		)	(116		)
	Net current-period OCI	(148		)	1			(380		)	(9		)	(108		)	(644		)
	Ending balance	$	(28	)	$	3		$	(2,640	)	$	(19	)	$	—		$	(2,684	)
	Generation (a)
	Beginning balance	$	114		$	2		$	—		$	(10	)	$	108		$	214
	OCI before reclassifications	(15		)	(1		)	—			(9		)	11			(14		)
	Amounts reclassified from AOCI (b)	(117		)	—			—			—			(119		)	(236		)
	Net current-period OCI	(132		)	(1		)	—			(9		)	(108		)	(250		)
	Ending balance	$	(18	)	$	1		$	—		$	(19	)	$	—		$	(36	)
	PECO (a)
	Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1
	OCI before reclassifications	—			—			—			—			—			—
	Amounts reclassified from AOCI (b)	—			—			—			—			—			—
	Net current-period OCI	—			—			—			—			—			—
	Ending balance	$	—		$	1		$	—		$	—		$	—		$	1
	For the Year Ended December 31, 2013	Gains and			Unrealized			Pension and			Foreign			AOCI of			Total
		(Losses) on			Gains and			Non-Pension			Currency			Equity
		Cash Flow			(Losses) on			Postretirement			Items			Investments
		Hedges			Marketable			Benefit Plan
					Securities			items
	Exelon (a)
	Beginning balance	$	368		$	—		$	(3,137	)	$	—		$	2		$	(2,767	)
	OCI before reclassifications	29			2			669			(10		)	101			791
	Amounts reclassified from AOCI (b)	(277		)	—			208			—			5			(64		)
	Net current-period OCI	(248		)	2			877			(10		)	106			727
	Ending balance	$	120		$	2		$	(2,260	)	$	(10	)	$	108		$	(2,040	)
	Generation (a)
	Beginning balance	$	512		$	—		$	—		$	—		$	1		513
	OCI before reclassifications	15			2			—			(10		)	102			109
	Amounts reclassified from AOCI (b)	(413		)	—			—			—			5			(408		)
	Net current-period OCI	(398		)	2			—			(10		)	107			(299		)
	Ending balance	$	114		$	2		$	—		$	(10	)	$	108		$	214
	PECO (a)
	Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1
	OCI before reclassifications	—			—			—			—			—			—
	Amounts reclassified from AOCI (b)	—			—			—			—			—			—
	Net current-period OCI	—			—			—			—			—			—
	Ending balance	$	—		$	1		$	—		$	—		$	—		$	1
	_______________________
	(a)	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
	(b)	See next tables for details about these reclassifications.
	ComEd, PECO, and BGE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2014 and 2013. The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2014 and 2013:
	For the Year Ended December 31, 2014
	Details about AOCI components	Items reclassified out of AOCI (a)						Affected line item in the Statements of Operations and Comprehensive Income
		Exelon			Generation
	Gains and (losses) on cash flow hedges
	Energy related hedges	$	195		$	195		Operating revenues
		195			195			Total before tax
		(78		)	(78		)	Tax expense
		$	117		$	117		Net of tax
	Gains and (losses) on available
	for sale securities
	Other available securities for sale	$	(2	)	$	—		Other Income and Deductions
		$	(2	)	$	—		Net of tax
Amortization of pension and other
postretirement benefit plan items
Prior service costs (b)	$	46		$	—
Actuarial losses (b)	(239		)	—
	(193		)	—			Total before tax
	75			—			Tax benefit
	$	(118	)	$	—		Net of tax
Equity investments
Sale of equity method investment	$	5		$	5
Reversal of CENG equity method AOCI	193			193			Equity in losses of unconsolidated affiliates
	198			198			Total before tax
	(79		)	(79		)	Tax expense
	$	119		$	119		Net of tax
Total Reclassifications	$	116		$	236		Net of tax
For the Year Ended December 31, 2013
Details about AOCI components	Items reclassified out of AOCI (a)						Affected line item in the Statements of Operations and Comprehensive Income
	Exelon			Generation
Gains and (losses) on cash flow hedges
Energy related hedges	$	464		$	683		Operating revenues
Other cash flow hedges	(3		)	—			Interest expense
	461			683			Total before tax
	(184		)	(270		)	Tax expense
	$	277		$	413		Net of tax
Amortization of pension and other
postretirement benefit plan items
Prior service costs (b)	$	(2	)	$	—
Actuarial losses (b)	(339		)	—
Deferred compensation unit plan (c)	(1		)	—
	(342		)	—			Total before tax
	134			—			Tax benefit
	$	(208	)	$	—		Net of tax
Equity investments
Capital activity	$	(8	)	$	(8	)	Equity in losses of unconsolidated affiliates
	(8		)	(8		)	Total before tax
	3			3			Tax benefit
	$	(5	)	$	(5	)	Net of tax
Total Reclassifications	$	64		$	408		Net of tax
_____________________
(a)	Amounts in parenthesis represent a decrease in net income.
(b)	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 16 — Retirement Benefits for additional details).
(c)	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.
The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2014 and 2013:
	For the Years Ended December 31,
	2014			2013			2012
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	19		$	—		$	(1	)
Actuarial loss reclassified to periodic cost	(93		)	(133		)	(110		)
Transition obligation reclassified to periodic cost	—			—			(2		)
Pension and non-pension postretirement benefit plans valuation adjustment	317			(430		)	237
Change in unrealized loss on cash flow hedges	96			166			68
Change in marketable securities	—			—			1
Change in unrealized income on equity investments	73			(71		)	(1		)
Total	$	412		$	(468	)	$	192
Generation
Change in unrealized loss on cash flow hedges	$	84		$	262		$	262
Change in unrealized income on equity investments	73			(72		)	1
Total	$	157		$	190		$	263

Commitments_and_Contingencies_

Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)	Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)
	Nuclear Insurance
	Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has mitigated its financial exposure to these risks through insurance and other industry risk-sharing provisions.
	The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2014, 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 January 1, 2013, 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 NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG.
	Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a member.
	NEIL may declare distributions to its members as a result of favorable operating experience. In recent years NEIL has made distributions to its members, but Generation cannot predict the level of future distributions or if they will continue at all. NEIL declared a distribution for 2014 and 2013, of which Generation’s portion was $18.3 million and $18.5 million respectively. No distributions were declared in 2012. The distributions were recorded as a reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). NEIL has never exercised this assessment since its formation in 1973, and while Generation cannot predict the level of future assessments, or if they will be imposed at all, as of December 31, 2014, the current maximum aggregate annual retrospective premium obligation for Generation is approximately $319 million. NEIL requires its members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.
	NEIL provides “all risk” property damage, decontamination and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery for all losses by all insureds will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.
	For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such losses could have a material adverse effect on Exelon’s and Generation’s financial condition, results of operations and liquidity.
	Spent Nuclear Fuel Obligation
	Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained in effect through May 15, 2014, after which time the fee was set to zero. For the year ended December 31, 2014, and for the year ended December 31, 2013, Generation incurred expense of $49 million and $136 million, respectively, in SNF disposal fees, recorded in Purchased power and fuel expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, including Exelon’s share of Salem and net of co-owner reimbursements (not including such fees incurred by CENG). Until such time as a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively in order to ensure full cost recovery. The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to be, delayed significantly.
	The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the Obama administration devised a new strategy for long-term SNF management. A Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for managing and disposing of the nation’s spent nuclear fuel and high-level radioactive waste.
	In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to the BRC recommendations. This strategy included a consolidated interim storage facility that is planned to be operational in 2025.
	Generation uses the 2025 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear decommissioning asset retirement obligations. The extended delay in SNF acceptance by the DOE has led to Generation’s adoption of dry cask storage at its Dresden, Clinton, Limerick, Oyster Creek, Peach Bottom, Byron, Braidwood, LaSalle, Quad Cities, Ginna, Nine Mile Point, and Calvert Cliffs stations.
	In August 2004, Generation and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s fulfillment of its obligations. Settlement agreements pertaining to Calvert Cliffs and Ginna were executed during 2011, and Nine Mile Point during 2012, (the “DOE Settlement Agreements”), as amended in 2014 for Calvert Cliffs and Nine Mile Point, under which the government has agreed to reimburse the costs associated with SNF storage expended or to be expended through 2016 as a result of the DOE delays.  The DOE Settlement Agreement is expected to be amended for Ginna in a similar manner as needed. Generation, including CENG, submits annual reimbursement requests to the DOE for costs associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE delays in accepting the SNF.
	Under the settlement agreement, Generation has received cumulative cash reimbursements for costs incurred as follows:
		Total			Net (a)
	Cumulative cash reimbursements (b)	$	836		$	702
	_____________________________
	(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.
	(b)	Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.
	As of December 31, 2014, and 2013, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:
		31-Dec-14			31-Dec-13
	DOE receivable - current (a)	$	82		$	71
	DOE receivable - noncurrent (b)	7			—
	Amounts owed to co-owners (a)(c)	(5		)	(18		)
	_____________________________
	(a)	Recorded in Accounts receivable, other.
	(b)	Recorded in Deferred debits and other assets, other
	(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other.  CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.
	The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The fee related to the former PECO units has been paid. Pursuant to the Standard Contracts, ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. As of December 31, 2014, the unfunded SNF liability for the one-time fee with interest was $1,021 million. Interest accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2014, was 0.020%. The liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information.
	Energy Commitments
	Generation’s customer facing activities include the physical delivery and marketing of power obtained through its generation capacity, and long-, intermediate- and short-term contracts. Generation maintains an effective supply strategy through ownership of generation assets and power purchase and lease agreements. Generation has also contracted for access to additional generation through bilateral long-term PPAs. These agreements are firm commitments related to power generation of specific generation plants and/or are dispatchable in nature. Several of Generation’s long-term PPAs, which have been determined to be operating leases, have significant contingent rental payments that are dependent on the future operating characteristics of the associated plants, such as plant availability. Generation recognizes contingent rental expense when it becomes probable of payment. Generation enters into PPAs with the objective of obtaining low-cost energy supply sources to meet its physical delivery obligations to its customers. Generation has also purchased firm transmission rights to ensure that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs. The primary intent and business objective for the use of its capital assets and contracts is to provide Generation with physical power supply to enable it to deliver energy to meet customer needs. In addition to physical contracts, Generation uses financial contracts for economic hedging purposes and, to a lesser extent, as part of proprietary trading activities.
	Generation has entered into bilateral long-term contractual obligations for sales of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators. Generation also enters into contractual obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. Generation provides for delivery of its energy to these customers through firm transmission.
	At December 31, 2014, Generation’s short- and long-term commitments, relating to the purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following tables:
		Net Capacity				REC			Transmission Rights		Total
		Purchases  (a)				Purchases (b)			Purchases (c)
	2015	$	418			$	152		$	20	$	590
	2016	283				228			15		526
	2017	222				121			15		358
	2018	112				29			16		157
	2019	117				5			16		138
	Thereafter	279				1			35		315
	Total	$	1,431			$	536		$	117	$	2,084
	_____________________________
	(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 December 31, 2014, 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 December 31, 2014, capacity offsets were $132 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 purchases its expected energy requirements through an ICC approved competitive bidding process administered by the IPA and spot market purchases. See Note 3 — Regulatory Matters for further information.
	PECO has entered into contracts through a competitive procurement process in order to meet a portion of its default service customers’ electric supply requirements through 2016. See Note 3 — Regulatory Matters for further information regarding the DSP Programs.
	ComEd is subject to requirements established by the Illinois legislation and the Energy Infrastructure Modernization Act related to the use of alternative energy resources. PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. BGE is subject to requirements established by the Public Utilities Article in Maryland related to the use of alternative energy resources; however, the wholesale suppliers that supply power to BGE through SOS procurement auctions have the obligation, by contract with BGE, to meet the RPS requirement. See Note 3 — Regulatory Matters for additional information relating to electric generation procurement, alternative energy resources and energy efficiency programs.
	ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments as of December 31, 2014 are as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	ComEd
	Electric supply procurement (a)	$	620			$	329		$	151	$	140	$	—	$	—	$	—
	Renewable energy and RECs (b)	1,517				75			76		77		78		84		1,127
	PECO
	Electric supply procurement (c)	609				527			82		—		—		—		—
	AECs (d)	13				2			2		2		2		2		3
	BGE
	Electric supply procurement (e)	1,315				779			448		88		—		—		—
Curtailment services (f)	115				40			34		29		12		—		—
_______________________
(a)	ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, 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)	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.
(c)	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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 3 — Regulatory Matters for additional information.
(d)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 — Regulatory Matters for additional information.
(e)	BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters for additional information.
(f)	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. See Note 3 — Regulatory Matters 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. Beginning with 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 December 31, 2014, these commitments were as follows:
					Expiration within
	Total				2015			2016		2017		2018		2019		2020
																and beyond
Generation	$	8,981			$	1,404		$	1,119	$	1,124	$	1,001	$	888	$	3,445
PECO	428				146			103		60		34		14		71
BGE	611				111			82		67		57		54		240
Other Purchase Obligations
The Registrants’ other purchase obligations as of December 31, 2014, 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	$	894			$	336		$	258	$	150	$	36	$	30	$	84
Generation (a)(b)	396				163			67		42		30		24		70
ComEd (c)	148				63			77		1		1		1		5
PECO (c)	7				3			4		—		—		—		—
BGE (c)	343				107			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 assets-held-for-sale. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information.
(c)	Purchase obligations include commitments related to smart meter installation. See Note 3 — Regulatory Matters for additional information.
Commercial Commitments
Exelon’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
					Expiration within
	Total				2015			2016		2017		2018		2019		2020
																and beyond
Letters of credit (non-debt) (a)	$	1,233			$	1,151		$	77	$	5	$	—	$	—	$	—
Surety bonds(b)	596				545			10		4		1		2		34
Performance guarantees (c)	1,239				472			20		20		20		20		687
Energy marketing contract	3,220				3,220			—		—		—		—		—
guarantees (d)
Lease guarantees(e)	40				—			—		—		—		—		40
Nuclear insurance premiums (f)	3,014				—			—		—		—		—		3,014
Underwriters discount (g)	60				60			—		—		—		—		—
Total commercial commitments	$	9,402			$	5,448		$	107	$	29	$	21	$	22	$	3,775
___________________________
(a)	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c)	Performance guarantees—Guarantees issued to ensure performance under specific contracts. Additionally includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.
(d)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.2 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 market prices.
(e)	Lease guarantees—Guarantees issued to ensure payments on building leases.
(f)	Nuclear insurance premiums—Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
(g)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19 - Common Stock for further details of the equity securities offering.
Generation’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
					Expiration within
	Total				2015			2016		2017		2018		2019		2020
																and beyond
Letters of credit (non-debt) (a)	$	1,187			$	1,106		$	76	$	5	$	—	$	—	$	—
Surety bonds	481				468			3		—		—		—		10
Performance guarantees (b)	458				319			20		20		20		20		59
Energy marketing contract	1,244				1,244			—		—		—		—		—
guarantees (c)
Nuclear insurance premiums (d)	3,014				—			—		—		—		—		3,014
Total commercial commitments	$	6,384			$	3,137		$	99	$	25	$	20	$	20	$	3,083
________________________
(a)	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
(b)	Performance guarantees—Guarantees issued to ensure performance under specific contracts.
(c)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 market prices.
(d)	Nuclear insurance premiums — Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
ComEd’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
					Expiration within
	Total				2015			2016		2017		2018		2019		2020
																and beyond
Letters of credit (non-debt) (a)	$	17			$	17		$	—	$	—	$	—	$	—	$	—
Surety bonds(b)	5				3			—		—		—		—		2
Performance guarantees (c)	200				—			—		—		—		—		200
Total commercial commitments	$	222			$	20		$	—	$	—	$	—	$	—	$	202
_________________________
(a)	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.
PECO’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
					Expiration within
	Total				2015			2016		2017		2018		2019		2020
																and beyond
Letters of credit (non-debt) (a)	$	22			$	22		$	—	$	—	$	—	$	—	$	—
Surety bonds(b)	18				18			—		—		—		—		—
Performance guarantees(c)	178				—			—		—		—		—		178
Total commercial commitments	$	218			$	40		$	—	$	—	$	—	$	—	$	178
________________________
(a)	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
BGE’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
					Expiration within
	Total				2015			2016		2017		2018		2019		2020
																and beyond
Letters of credit (non-debt) (a)	$	1			$	1		$	—	$	—	$	—	$	—	$	—
Surety bonds (b)	11				11			—		—		—		—		—
Performance guarantees (c)	253				3			—		—		—		—		250
Total commercial commitments	$	265			$	15		$	—	$	—	$	—	$	—	$	250
________________________
(a)	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b)	Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c)	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.
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.
Generation completed the construction of the Antelope Valley solar PV facility in Los Angeles County, California, which became fully operational in the first half of 2014. Generation has no further remaining construction commitments for the project.
On July 3, 2013, Generation executed a turbine supply agreement to expand its Beebe wind project in Michigan. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained 2014.
On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with at least 120MW of new natural gas-fired generation. The remaining commitment is approximately $39 million under the contract and achievement of commercial operation is expected in 2015. This project will satisfy a portion of Exelon's commitment to Maryland. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information on commitments to develop or assist in development of new generation in Maryland resulting from the Constellation merger.
On December 27, 2013, Generated executed a turbine supply agreement for construction of the 40MW Fourmile Wind project in western Maryland. The remaining commitment is approximately $2 million under the contract and achievement of commercial operations was attained in 2014. 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 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 $1.0 billion 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 $19 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 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 $56 million under these contracts and achievement of commercial operations is expected in 2015.
Refer to Note 3 — Regulatory Matters 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.
Equity Investment Commitments
As part of Generation's recent investments in technology development, Generation has entered into equity purchase agreements which 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 December 31, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:
	Total
2015	$	98
2016	38
2017	20
2018	11
Total	$	167
Leases
Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2014 were:
	Exelon				Generation (b)			ComEd (c)		PECO (c)		BGE (c)(d)
2015	$	99			$	51		$	14	$	3	$	13
2016	102				57			13		3		11
2017	102				63			8		3		10
2018	86				57			4		3		9
2019	70				43			4		2		7
Remaining years	699				628			2		—		27
Total minimum future lease payments	$	1,158		(a)	$	899	(a)	$	45	$	14	$	77
______________________
(a)	Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment.
(b)	The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million .
(c)	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, and BGE’s annual obligation for these arrangements, included in each of the years 2015—2019, was $2 million, $3 million, and $2 million respectively.
(d)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.
The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2014, 2013 and 2012:
For the Year Ended December 31,	Exelon				Generation (a)			ComEd		PECO		BGE
2014	$	865			$	806		$	15	$	14	$	12
2013	806				744			15		21		11
2012	930				872			18		27		12
__________________________
(a)	Includes Generation’s PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the Energy Commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation’s PPAs and other capacity contracts totaled $755 million, $694 million and $801 million during 2014, 2013 and 2012, respectively.
For information regarding capital lease obligations, see Note 13—Debt and Credit Agreements.
Indemnifications Related to Sale of Sithe (Exelon and Generation)
On January 31, 2005, subsidiaries of Generation completed a series of transactions that resulted in Generation’s sale of its investment in Sithe. Specifically, subsidiaries of Generation consummated the acquisition of Reservoir Capital Group’s 50% interest in Sithe and subsequently sold 100% of Sithe to Dynegy Inc. (Dynegy).
The estimated maximum possible exposure to Exelon related to the guarantees provided as part of the sales transaction to Dynegy was approximately $200 million at December 31, 2013. The guarantee expired January 31, 2014. Generation was not required to make payments under the guarantee, and, therefore, has no further obligation related to this guarantee.
Environmental Matters
General. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.
ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•	ComEd has identified 42 sites, 17 of which 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. One gas purification site is in the initial stages of investigation at the direction of the MDE. At this time, BGE is unable to estimate the results of this investigation.
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. BGE is authorized to recover, and is currently recovering, environmental costs for the remediation of former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically received recovery of actual clean-up costs in distribution rates. ComEd, PECO and BGE have recorded regulatory assets for the recovery of these costs. See Note 3—Regulatory Matters for additional information regarding the associated regulatory assets.
As of December 31, 2014 and 2013, the Registrants have accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
December 31, 2014	Total environmental				Portion of total related to MGP
	investigation				investigation and remediation
	and remediation reserve
Exelon	$	347			$	277
Generation	63				—
ComEd	238				235
PECO	45				42
BGE	1				—
31-Dec-13	Total environmental				Portion of total related to MGP
	investigation				investigation and remediation
	and remediation reserve
Exelon	$	338			$	273
Generation	56				—
ComEd	234				229
PECO	47				44
BGE	1				—
The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs based on probabilistic and deterministic modeling using all available information at the time of each study and the remediation standards currently required by the applicable state environmental agency.  Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
During the third quarter of 2014, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The results of these studies indicated that additional remediation would be required at certain sites. Accordingly, ComEd and PECO increased their environmental liabilities and related regulatory assets by $26 million and $4 million, respectively, primarily reflecting refined assumptions regarding clean-up techniques and scopes based on additional experience and analysis as site clean-up and investigation activities progress.
BGE has established a reserve for the active sites that is not material. Given that the former gas purification site is in the early stages of investigation and the extent of contamination is not currently known, BGE is unable to estimate actual remediation costs, which may be material to BGE’s results of operations, cash flows, and financial position.
The Registrants cannot reasonably estimate whether they will incur other significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers.
Water Quality
Groundwater Contamination. In October 2007, a subsidiary of Constellation entered into a consent decree with the MDE relating to groundwater contamination at a third-party facility that was licensed to accept fly ash, a byproduct generated by coal-fired plants. The consent decree required the payment of a $1 million penalty, remediation of groundwater contamination resulting from the ash placement operations at the site, replacement of drinking water supplies in the vicinity of the site, and monitoring of groundwater conditions. As of December 31, 2014 and 2013, Generation’s remaining groundwater contamination reserve was $13 million and $14 million. respectively.
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. In January 2013, Generation made the final $10 million payment due under the lease agreement which had been accrued at December 31, 2012.
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. Creditors were provided 30 days from the Effective Date to file rejection damages claims associated with contracts rejected under the Plan.
During the second quarter of 2013, Exelon filed proofs of claim for approximately $21 million with the Bankruptcy Court for amounts owed by EME and Midwest Generation related to the coal rail car lease. Further, Exelon filed an environmental claim with an unspecified amount that listed the indemnifications that were in place pre-Petition Date and other factors associated with the remediation and a claim under the asbestos cost-sharing agreement with an unspecified amount. A settlement was approved on January 22, 2015, to resolve the claims related to the coal rail car lease for $14 million.  Exelon received the funds and recorded the corresponding gain January 2015.
Certain environmental laws and regulations subject current and prior owners of properties or generators of hazardous substances at such properties to liability for remediation costs of environmental contamination. 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 have reviewed available public information as to potential environmental exposures regarding the Midwest Generation station sites. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q, its last public filing prior to its deregistration, that (i) it has accrued a probable amount of approximately $9 million for estimated environmental investigation and remediation costs under CERCLA, or similar laws, for the investigation and remediation of contaminated property at two Midwest Generation plant sites, (ii) it has identified stations for which a reasonable estimate for investigation and/ or remediation cannot be made and (iii) it and the Illinois EPA entered into Compliance Commitment Agreements outlining specified environmental remediation measures and groundwater monitoring activities to be undertaken at its Crawford, Powerton, Joliet, Will County and Waukegan generating stations. At this time, however, ComEd and Generation do not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted. For these reasons, ComEd and Generation are unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to the generating stations and as a result no liability has been recorded as of December 31, 2014. 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.
Generation increased its reserve for asbestos-related bodily injury claims at December 31, 2013 by $25 million, as a result of Midwest Generation listing such agreement in the January 2014 plan supplement as an agreement to be rejected in connection with the Plan. As discussed above, the rejection became effective as part of the Plan. Subsequently, Generation increased its reserve by $15 million pursuant to the second quarter 2014 actuarial study of such claims, of which an estimated $6 million pertains to Midwest Generation’s share. Midwest Generation publicly disclosed in its March 31, 2014 Form 10-Q, its last public filing prior to its deregistration, that it had $53 million recorded related to asbestos bodily injury claims under the contractual indemnity with ComEd. Exelon and Generation may be entitled to damages associated with the rejection of the agreement. These amounts are considered to be contingent gains and would not be recognized until realized.
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 April 11, 2014, a class action complaint was filed in the U.S. District Court for the Eastern District of Missouri against Cotter and six additional defendants. The complaint alleges that individuals living in the North St. Louis area within a three-mile radius of the West Lake Landfill suffered damage to property or loss of use of property due to the defendants’ negligent handling of radioactive materials. On August 22, 2014, the plaintiffs voluntarily dismissed the case without prejudice.
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 December 31, 2014.
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.
Coal Combustion Residuals. On December 19, 2014, the U.S. EPA issued the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants, including the classification of CCR as non-hazardous waste under RCRA. The EPA ruling is effective 180 days after publication in the Federal Register, which is anticipated in early 2015. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations. Generation has previously recorded reserves consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact Exelon’s and Generation’s financial results. Generation is evaluating what, if any, incremental costs will be incurred for coal ash disposal sites formerly owned by Generation that have not yet been closed by their current owners. At this time, however, Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any remediation requirements that may be asserted for these former sites under the new federal regulations. For these reasons, Generation is unable to predict whether and to what extent they may ultimately be held responsible for remediation and other costs relating to formerly owned coal ash disposal sites under the new regulations, and as a result no new liability has been recorded as of December 31, 2014.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon, Generation, PECO and BGE).
Exelon and Generation. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and excludes the estimated legal costs associated with handling these matters, which could be material.
At December 31, 2014 and 2013, Generation had reserved approximately $100 million and $90 million, respectively, in total for asbestos-related bodily injury claims. As of December 31, 2014, approximately $22 million of this amount related to 255 open claims presented to Generation, while the remaining $78 million of the reserve is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether an adjustment to the reserve is necessary. During the second quarter of 2014, Generation increased its reserve by approximately $15 million, primarily due to increased actual and projected number and severity of claims.
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 apply to 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 December 31, 2014. Increased claims activity resulting from this ruling could have a material adverse impact on Exelon, Generation’s and PECO’s future results of operations and cash flows.
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 486 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.
Federal Energy Regulatory Commission Investigation (Exelon and Generation).
On January 30, 2012, FERC published a notice on its website regarding a non-public investigation of certain of Constellation’s power trading activities in and around the ISO-NY from September 2007 through December 2008. Prior to the Constellation merger, Constellation announced on March 9, 2012, that it had resolved the FERC investigation. Under the settlement, Constellation agreed to pay, and has paid, a $135 million civil penalty and $110 million in disgorgement.
During the year ended December 31, 2012, Generation recorded expense of $195 million in Operating and maintenance expense within its Statement of Operations and Comprehensive Income with the remaining $50 million recorded as a Constellation pre-acquisition contingency within its Consolidated Balance Sheets. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information on the Constellation merger.
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. In addition, the ICC found that ComEd did not systematically fail in its duty to provide adequate, reliable and safe service. As a result, the ICC rejected the Illinois Attorney General’s request for the ICC to open an investigation into ComEd’s infrastructure and storm hardening investments.
Following the ICC’s June 26, 2013 denial of ComEd’s request for rehearing, on June 27, 2013 ComEd filed an appeal of both the summer and winter storm dockets with the Illinois Appellate Court regarding the ICC’s interpretation of Section 16-125 of the Illinois Public Utilities Act. On July 31, 2014, the Illinois Appellate Court reaffirmed the ICC’s decision in the appeal of the Summer 2011 Storm Docket and dismissed the appeal of the February 2011 Blizzard Docket. The Illinois Appellate Court’s opinion has no accounting impact as ComEd previously established a liability in connection with the June 5, 2013 ICC ruling discussed below. ComEd has asked the Illinois Supreme Court to hear the matter.  There is no set time in which the Court must decide whether it will take the case.
As a result of the ICC’s June 5, 2013 ruling, ComEd established a liability, which was 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 as well as the outcome of the appeal. 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. ComEd intends to contest the allegations of this suit.  In February 2014, ComEd filed a motion to dismiss this class action complaint, which was denied in June 2014. As of December 31, 2014, ComEd has a reserve, which is not material, representing its best estimate of probable loss associated with this class action complaint. 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.
Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO and BGE)
Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s actual cash needs.
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has also agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under which the subordinated debt securities are issued.
PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary liquidating value of its then outstanding preferred securities. On May 1, 2013, PECO redeemed all outstanding preferred securities. As a result, the above ratio calculation is no longer applicable. Additionally, PECO may not declare dividends on any shares of its capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P. or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued.
BGE pays dividends on its common stock after its board of directors declares them. However, BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE is prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated by two of the three major credit rating agencies below investment grade. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless: (1) BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid; or (2) any dividends (and any redemption payments) due on BGE’s preference stock have not been paid.
Baltimore City Franchise Taxes (BGE)
The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE is currently reviewing the merits of this claim. 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
See Note 14 — 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)	12 Months Ended
	Dec. 31, 2014
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 years ended December 31, 2014, 2013 and 2012.
	For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
	Taxes other than income
	Utility (a)	$	456			$	89			$	238			$	128		$	86
	Property	396				240				25				15			114
	Payroll	200				118				28				14			18
	Other	102				18				2				2			3
	Total taxes other than income	$	1,154			$	465			293				$	159		$	221
	For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
	Taxes other than income
	Utility (a)	$	449			$	79			$	241			$	129		$	82
	Property	302				205				24				14			112
	Payroll	159				89				27				13			15
	Other	185				16				7				2			4
	Total taxes other than income	$	1,095			$	389			$	299			$	158		$	213
	For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
	Taxes other than income
	Utility (a)	$	463			$	82			$	239			$	141		$	75
	Property	227				189				22				13			111
	Payroll	131				78				26				12			18
	Other	198				20				8				(4		)	4
	Total taxes other than income	$	1,019			$	369			$	295			$	162		$	208
	_____________________
	(a)	Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
	For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning
	trust funds (a)—
	Regulatory agreement units	$	216			$	216			$	—			$	—		$	—
	Non-regulatory agreement units	159				159				—				—			—
	Net unrealized gains on decommissioning
	trust funds—
	Regulatory agreement units	180				180				—				—			—
	Non-regulatory agreement units	134				134				—				—			—
	Net unrealized gains on pledged assets—
	Zion Station decommissioning	29				29				—				—			—
	Regulatory offset to decommissioning trust	(358		)		(358		)		—				—			—
	fund-related activities (b)
	Total decommissioning-related activities	360				360				—				—			—
	Investment income	1				1				—				(1		)	7			(c)
	Long-term lease income	24				—				—				—			—
	Interest income related to uncertain income tax	40				54				—				—			—
	positions
	AFUDC—Equity	21				—				3				6			12
	Other	9				(9		)		14				2			(1		)
	Other, net	$	455			$	406			$	17			$	7		$	18
	For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust
	funds (a)—
	Regulatory agreement units	$	256			$	256			$	—			$	—		$	—
	Non-regulatory agreement units	77				77				—				—			—
	Net unrealized gains on decommissioning trust
	funds—
	Regulatory agreement units	406				406				—				—			—
	Non-regulatory agreement units	146				146				—				—			—
	Net unrealized gains on pledged assets—
	Zion Station decommissioning	7				7				—				—			—
	Regulatory offset to decommissioning trust	(546		)		(546		)		—				—			—
	fund-related activities (b)
Total decommissioning-related activities	346				346				—				—			—
Investment income	8				(1		)		—				(1		)	9			(c)
Long-term lease income	28				—				—				—			—
Interest income related to uncertain income tax	24				4				—				—			—
positions
AFUDC—Equity	22				—				11				4			7
Other	32				6				15				3			1
Other, net	$	460			$	355			$	26			$	6		$	17
For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning
trust funds (a)—
Regulatory agreement units	$	189			$	189			$	—			$	—		$	—
Non-regulatory agreement units	102				102				—				—			—
Net unrealized losses on decommissioning
trust funds—
Regulatory agreement units	386				386				—				—			—
Non-regulatory agreement units	105				105				—				—			—
Net unrealized gains on pledged assets—
Zion Station decommissioning	73				73				—				—			—
Regulatory offset to decommissioning trust	(530		)		(530		)		—				—			—
fund-related activities (b)
Total decommissioning-related activities	325				325				—				—			—
Investment income	20				3				1				2			11			(c)
Long-term lease income	29				—				—				—			—
Interest income related to uncertain income tax	15				2				20				—			—
positions
AFUDC—Equity	17				—				6				4			10
Credit Facility termination fees	(85		)		(85		)		—				—			—
Other	32				1				12				2			2
Other, net	$	353			$	246			$	39			$	8		$	23
_________________________
(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 for additional information regarding the accounting for nuclear decommissioning.
(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012.
For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
Depreciation, amortization, accretion and
depletion
Property, plant and equipment	$	2,080			$	922			$	588			$	227		$	288
Regulatory assets	191				—				99				9			83
Amortization of intangible assets, net	44				44				—				—			—
Amortization of energy contract assets and	135				135				—				—			—
liabilities (a)
Nuclear fuel (b)	1,073				1,073				—				—			—
ARO accretion (c)	345				345				—				—			—
Total depreciation, amortization, accretion and	$	3,868			$	2,519			$	687			$	236		$	371
depletion
For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
Depreciation, amortization, accretion and
depletion
Property, plant and equipment	$	1,893			$	813			$	545			$	219		$	264
Regulatory assets	212				—				119				9			84
Amortization of intangible assets, net	48				43				5				—			—
Amortization of energy contract assets and	430				507				—				—			—
liabilities (a)
Nuclear fuel (b)	921				921				—				—			—
ARO accretion (c)	275				275				—				—			—
Total depreciation, amortization, accretion and	$	3,779			$	2,559			$	669			$	228		$	348
depletion
For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
Depreciation, amortization, accretion and
depletion
Property, plant and equipment	$	1,712			$	733			$	525			$	207		$	245
Regulatory assets	129				—				80				10			53
Amortization of intangible assets, net	40				35				5				—			—
Amortization of energy contract assets and	1,110				1,110				—				—			—
liabilities (a)
Nuclear fuel (b)	848				848				—				—			—
ARO accretion (c)	240				240				—				—			—
Total depreciation, amortization and accretion	$	4,079			$	2,966			$	610			$	217		$	298
________________________
(a)	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(b)	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	940			$	322			$	292			$	94		$	111
Income taxes (net of refunds)	$	314			227				(6		)		85			(21		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit	$	560			$	249			162				$	36		$	64
costs
Loss from equity method investments	22				20				—				—			—
Provision for uncollectible accounts	156				14				26				52			64
Provision for excess and obsolete inventory	5				5				—				—			—
Stock-based compensation costs	91				—				—				—			—
Other decommissioning-related activity (a)	(132		)		(132		)		—				—			—
Energy-related options (b)	122				122				—				—			—
Amortization of regulatory asset related to debt	11				—				8				3			—
costs
Amortization of rate stabilization deferral	65				—				—				—			65
Amortization of debt fair value adjustment	(23		)		(23		)		—				—			—
Merger-related commitments	44				44				—				—			—
Amortization of debt costs	53				12				4				2			2
Discrete impacts from EIMA (c)	53				—				53				—			—
Lower of cost or market inventory adjustment	29				29				—				—			—
Other	(2		)		6				2				(1		)	(15		)
Total other non-cash operating activities	$	1,054			$	346			$	255			$	92		$	180
Changes in other assets and liabilities:
Under/over-recovered energy and transmission	$	47			$	—			$	36			$	—		$	11
costs
Other regulatory assets and liabilities	(167		)		—				(13		)		(16		)	(121		)
Cash deposits (d)	(241		)		(241		)		—				—			—
Other current assets	7				81				(10		)		(2		)	(44		)
Other noncurrent assets and liabilities	(204		)		(89		)		32				1			(9		)
Total changes in other assets and liabilities	$	(558	)		$	(249	)		$	45			$	(17	)	$	(163	)
Non-cash investing and financing activities:
Change in ARC	$	72			$	72			$	—			$	—		$	—
Change in capital expenditures not paid	220				(61		)	(e)	78				—			25
Fair value of net assets recorded upon CENG	(3,400		)		(3,400		)		—				—			—
consolidation (f)
Issuance of equity units (g)	131				—				—				—			—
Nuclear fuel procurement (h)	70				70				—				—			—
Indemnification of like-kind exchange position (i)	—				—				5				—			—
____________________________
(a)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters for more information.
(d)	Relates primarily to cash deposits made to ISO's/RTO's.
(e)	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.
(f)	See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
(g)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19 — Common Stock for additional information.
(h)	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.
(i)	See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.
For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	866			$	291			$	283			$	95		$	130
Income taxes (net of refunds)	112				(18		)		33				70			42
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	825			$	345			$	308			$	43		$	56
Gain from equity method investments	(10		)		(10		)		—				—			—
Provision for uncollectible accounts	101				10				(15		)		61			44
Provision for excess and obsolete inventory	9				9				—				—			—
Stock-based compensation costs	120				—				—				—			—
Other decommissioning-related activity (a)	(169		)		(169		)		—				—			—
Energy-related options (b)	104				104				—				—			—
Amortization of regulatory asset related to debt	12				—				9				3			—
costs
Amortization of rate stabilization deferral	66				—				—				—			66
Amortization of debt fair value adjustment	(34		)		(34		)		—				—			—
Discrete impacts from EIMA (c)	(271		)		—				(271		)		—			—
Amortization of debt costs	18				10				1				2			2
Other	(53		)		5				(4		)		(1		)	(15		)
Total other non-cash operating activities	$	718			$	270			$	28			$	108		$	153
Changes in other assets and liabilities:
Under/over-recovered energy and transmission	$	12			$	—			$	(35	)		$	9		$	38
costs
Other regulatory assets and liabilities	(64		)		—				(43		)		(16		)	(71		)
Other current assets	(165		)		(151		)		51				13			(8		)
Other noncurrent assets and liabilities	322				15				268			(d)	(12		)	(23		)
Total changes in other assets and liabilities	$	105			$	(136	)		$	241			$	(6	)	$	(64	)
Non-cash investing and financing activities:
Change in ARC	$	(128	)		$	(128	)		$	—			$	—		$	4
Change in capital expenditures not paid	(38		)		(107		)	(e)	(8		)		13			(48		)
Consolidated VIE dividend to noncontrolling interest	63				63				—				—			—
Indemnification of like-kind exchange position (f)	—				—				176				—			—
______________________
(a)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters for more information.
(d)	Relates primarily to interest payable related to like-kind exchange tax position. See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.
(e)	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.
(f)	See Note 14 — Income Taxes for discussion of the like-kind exchanged tax position.
For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	761			$	286			$	288			$	113		$	136
Income taxes (net of refunds)	(171		)		175				(42		)		(64		)	(112		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	820			$	341			$	282			$	50		$	57
Earnings from equity method investments	91				91				—				—			—
Provision for uncollectible accounts	164				22				42				60			44
Provision for excess and obsolete inventory	6				6				1				—			—
Stock-based compensation costs	94				—				—				—			—
Other decommissioning-related activity (a)	(145		)		(145		)		—				—			—
Energy-related options (b)	160				160				—				—			—
Amortization of regulatory asset related to debt costs	18				—				13				3			2
Amortization of rate stabilization deferral	57				—				—				—			67
Amortization of debt fair value adjustment	(34		)		(34		)		—				—			—
Merger-related commitments (c)	141				32				—				—			27
Severance costs	99				34				—				—			—
Discrete impacts from EIMA (d)	(96		)		—				(96		)		—			—
Amortization of debt costs	19				11				5				3			2
Other	(30		)		—				5				9			(6		)
Total other non-cash operating activities	$	1,364			$	518			$	252			$	125		$	193
Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	71			$	—			$	28			$	20		$	26
Other regulatory assets and liabilities	(404		)		$	—			(68		)		18			(112		)
Other current assets	213				(30		)		33				(12		)	(7		)
Other noncurrent assets and liabilities	(248		)		(98		)		(95		)		(10		)	8
Total changes in other assets and liabilities	$	(368	)		$	(128	)		$	(102	)		$	16		$	(85	)
Non-cash investing and financing activities:
Change in ARC	$	781			$	781			$	2			$	—		$	—
Change in capital expenditures not paid	160				103			(e)	15				26			(4		)
Consolidated VIE dividend to noncontrolling interest	7,365				5,264				—				—			—
_________________________
(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 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)	Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments.
(d)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters.
(e)	Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley.
DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2014, PECO has included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $5 million related to PECO’s DOE SGIG programs. For the year ended December 31, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $74 million, $27 million and $47 million, and reimbursements of $95 million, $37 million and $58 million, related to PECO’s and BGE’s DOE SGIG programs. See Note 3 — Regulatory Matters for additional information regarding the DOE SGIG.
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2014 and 2013.
31-Dec-14	Exelon				Generation				ComEd				PECO			BGE
Investments
Equity method investments:
Financing trusts (a)	$	22			$	—			$	6			$	8		$	8
Bloom Energy	13				13				—				—			—
Net Power	9				9				—				—			—
Sunnyside	5				5				—				—			—
Other equity method investments	1				1				—				—			—
Total equity method investments	50				28				6				8			8
Other investments:
Net investment in leases	367				7				—				—			—
Employee benefit trusts and investments (b)	85				27				—				23			4
Other investments (c)	42				42				—				—			—
Total investments	$	544			$	104			$	6			$	31		$	12
31-Dec-13	Exelon				Generation				ComEd				PECO			BGE
Investments
Equity method investments:
Financing trusts (a)	$	22			$	—			$	6			$	8		$	8
Keystone Fuels, LLC	32				32				—				—			—
Conemaugh Fuels, LLC	21				21				—				—			—
CENG	1,925				1,925				—				—			—
Safe Harbor	285				285				—				—			—
Malacha	8				8				—				—			—
Other equity method investments	2				2				—				—			—
Total equity method investments	2,295				2,273				6				8			8
Other investments:
Net investment in leases	705				7				—				—			—
Employee benefit trusts and investments (b)	90				23				5				23			5
Other investments (c)	22				22				—				—			—
Total investments	$	3,112			$	2,325			$	11			$	31		$	13
_________________________
(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.
(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.
(c)	Includes cost method and available-for-sale investments.
The following tables provide additional information about liabilities of the Registrants at December 31, 2014 and 2013.
31-Dec-14	Exelon				Generation				ComEd				PECO			BGE
Accrued expenses
Compensation-related accruals (a)	$	832			$	447			$	153			$	50		$	58
Taxes accrued	305				248				59				3			42
Interest accrued	240				66				102				33			29
Severance accrued	49				33				2				1			2
Other accrued expenses	113			(b)	92			(b)	15				4			—
Total accrued expenses	$	1,539			$	886			$	331			$	91		$	131
31-Dec-13	Exelon				Generation				ComEd				PECO			BGE
Accrued expenses
Compensation-related accruals (a)	$	683			$	337			$	135			$	47		$	55
Taxes accrued	315				212				62				24			16
Interest accrued	234				72				95				32			29
Severance accrued	66				31				3				1			4
Other accrued expenses	335			(b)	324			(b)	12				2			7
Total accrued expenses	$	1,633			$	976			$	307			$	106		$	111
_______________________
(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
(b)	Includes $19 million and $228 million for amounts accrued related to Antelope Valley as of December 31, 2014 and December 31, 2013, respectively.

Segment_Information_Exelon_Gen

Segment Information (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
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 regions not considered individually significant referred to collectively as “Other Regions”; including 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 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 own 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, distributed generation, heating, cooling, and cogeneration facilities, and home improvements, sales of electric and gas appliances, servicing of heating, air conditioning, plumbing, electrical, and indoor quality systems, and investments in energy-related proprietary technology are not allocated to regions. Further, Generation’s compensation under the reliability-must-run rate schedule, results of operations from the Brandon Shores, Wagner, and C.P. Crane Maryland generating stations, and 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 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 years ended December 31, 2014, 2013, and 2012 is as follows:
		Generation (a)			ComEd			PECO			BGE (b)			Other (c)			Intersegment			Exelon
																	Eliminations
	Operating revenues(d):
	2014	$	17,393		$	4,564		3,094			$	3,165		$	1,285		$	(2,072	)	$	27,429
	2013	15,630			4,464			3,100			3,065			1,241			(2,612		)	24,888
	2012	14,437			5,443			3,186			2,091			1,396			(3,064		)	23,489
	Intersegment revenues(e):
	2014	$	762		$	4		$	2		$	25		$	1,280		$	(2,067	)	$	6
	2013	1,367			3			1			13			1,237			(2,607		)	14
	2012	1,660			2			3			9			1,381			(3,049		)	6
	Depreciation and amortization
	2014	$	967		$	687		$	236		$	371		$	53		$	—		$	2,314
	2013	856			669			228			348			52			—			2,153
	2012	768			610			217			238			48			—			1,881
	Operating expenses (d):
	2014	$	16,923		$	3,586		$	2,522		$	2,726		$	1,353		$	(2,071	)	$	25,039
	2013	13,976			3,510			2,434			2,616			1,324			(2,618		)	21,242
	2012	13,226			4,557			2,563			2,053			1,662			(3,043		)	21,018
	Equity in earnings (losses) of
	unconsolidated affiliates
	2014	$	(20	)	$	—		$	—		$	—		$	—		$	—		$	(20	)
	2013	10			—			—			—			—			—			10
	2012	(91		)	—			—			—			—			—			(91		)
	Interest expense, net:
	2014	$	356		$	321		$	113		$	106		$	169		$	—		$	1,065
	2013	357			579			115			122			183			—			1,356
	2012	301			307			123			111			86			—			928
	Income (loss) before income
	taxes:
	2014	$	1,226		$	676		$	466		$	351		$	(227	)	$	(6	)	$	2,486
	2013	1,675			401			557			344			(191		)	(13		)	2,773
	2012	1,058			618			508			(54		)	(325		)	(7		)	1,798
	Income taxes:
	2014	$	207		$	268		$	114		$	140		$	(63	)	$	—		$	666
	2013	615			152			162			134			(20		)	1			1,044
	2012	500			239			127			(23		)	(215		)	(1		)	627
	Net income (loss):
	2014	$	1,019		$	408		$	352		$	211		$	(164	)	$	(6	)	$	1,820
	2013	1,060			249			395			210			(171		)	(14		)	1,729
	2012	558			379			381			(31		)	(110		)	(6		)	1,171
	Capital expenditures:
	2014	$	3,012		$	1,689		$	661		$	620		$	95		$	—		6,077
	2013	2,752			1,433			537			587			86			—			5,395
	2012	3,554			1,246			422			500			67			—			5,789
	Total assets:
	2014	$	45,348		$	25,392		$	9,943		$	8,078		$	9,794		$	(11,741	)	$	86,814
	2013	41,232			24,118			9,617			7,861			8,317			(11,221		)	79,924
	__________________________
(a)	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012, intersegment revenues for Generation include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.
(b)	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014.
(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(d)	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
(e)	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Generation total revenues:
As of April 1, 2014, Generation total revenues and Generation total revenues net of purchased power and fuel expense includes 100% of the activity from CENG.
	2014									2013									2012
	Revenues			Intersegment			Total			Revenues			Intersegment			Total			Revenues			Intersegment			Total
	from			revenues			Revenues			from			revenues			Revenues			from			revenues			Revenues
	external									external									external
	customers (a)									customers (a)									customers (a)
Mid-Atlantic	$	5,265		$	(6	)	$	5,259		$	5,182		$	22		$	5,204		$	5,082		$	(44	)	$	5,038
Midwest	4,467			8			4,475			4,280			(10		)	4,270			4,824			24			4,848
New England	1,417			5			1,422			1,245			(8		)	1,237			1,048			45			1,093
New York	843			—			843			735			(21		)	714			582			(25		)	557
ERCOT	938			(3		)	935			1,222			(6		)	1,216			1,365			2			1,367
Other Regions (b)	1,319			(10		)	1,309			946			22			968			755			78			833
Total Revenues	$	14,249		$	(6	)	$	14,243		$	13,610		$	(1	)	$	13,609		$	13,656		$	80		$	13,736
for Reportable Segments
Other (c)	3,144			6			3,150			2,020			1			2,021			781			(80		)	701
Total	$	17,393		$	—		$	17,393		$	15,630		$	—		$	15,630		$	14,437		$	—		$	14,437
Generation Consolidated Operating Revenues
_______________________
(a)	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
(b)	Other regions include the South, West and Canada, which are not considered individually significant.
(c)	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 $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues.
Generation total revenues net of purchased power and fuel expense:
	2014									2013									2012
	RNF from			Intersegment			Total			RNF from			Intersegment			Total			RNF from			Intersegment			Total
	external			RNF			RNF			external			RNF			RNF			external			RNF			RNF
	customers (a)									customers (a)									customers (a)
Mid-Atlantic	$	3,466		$	(49	)	$	3,417		$	3,273		$	(3	)	$	3,270		$	3,477		$	(44	)	$	3,433
Midwest	2,580			14			2,594			2,585			1			2,586			2,974			24			2,998
New England	432			(81		)	351			217			(32		)	185			151			45			196
New York	457			26			483			14			(18		)	(4		)	101			(25		)	76
ERCOT	573			(256		)	317			604			(168		)	436			403			2			405
Other Regions (b)	611			(284		)	327			334			(133		)	201			53			78			131
Total Revenues net of	$	8,119		$	(630	)	$	7,489		$	7,027		$	(353	)	$	6,674		$	7,159		$	80		$	7,239
purchased power and fuel expense for Reportable Segments
Other (c)	(651		)	630			(21		)	406			353			759			217			(80		)	137
Total Generation	$	7,468		$	—		$	7,468		$	7,433		$	—		$	7,433		$	7,376		$	—		$	7,376
Revenues net of purchased power and fuel expense
____________________________
(a)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
(b)	Other regions include the South, West and Canada, which are not considered individually significant.
(c)	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 $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

Related_Party_Transactions_Exe

Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related-Party Transactions (Exelon, Generation, ComEd, PECO and BGE)	Related Party Transactions (Exelon, Generation, ComEd, PECO and BGE)
	Exelon
	The financial statements of Exelon include related party transactions as presented in the tables below:
		For the Years Ended
		December 31,
		2014			2013		2012
	Operating revenues from affiliates:
	PECO (a)	$	1		$	10	$	6
	CENG (b)	17			56		42
	BGE (a)	5			4		—
	Total operating revenues from affiliates	$	23		$	70	$	48
	Purchase power and fuel from affiliates:
	CENG (c)	$	282		$	992	$	793
	Keystone Fuels, LLC (d)	138			144		119
	Conemaugh Fuels, LLC (d)	99			98		101
	Safe Harbor Water Power Corp (d)	12			22		23
	Total purchase power and fuel from affiliates	$	531		$	1,256	$	1,036
	Interest expense to affiliates, net:
	ComEd Financing III	$	13		$	13	$	13
	PECO Trust III	6			6		6
	PECO Trust IV	6			6		6
	BGE Capital Trust II (f)	16			16		12
	Total interest expense to affiliates, net	$	41		$	41	$	37
	Earnings (losses) in equity method investments:
	CENG (e)	$	(19	)	$	9	$	(99	)
	Qualifying facilities and domestic power projects	(1		)	1		8
	Total earnings (losses) in equity method investments	$	(20	)	$	10	$	(91	)
		December 31,
		2014			2013
	Receivables from affiliates (current):
	CENG (b)	$	—		$	3
	Payables to affiliates (current):
	CENG (c)	$	—		$	85
	ComEd Financing III	4			4
	PECO Trust III	1			1
	BGE Capital Trust II	3			4
	Keystone Fuels, LLC (d)	—			12
	Conemaugh Fuels, LLC (d)	—			9
	Other	—			1
	Total payables to affiliates (current)	$	8		$	116
	Long-term debt due to financing trusts:
	ComEd Financing III	$	206		$	206
	PECO Trust III	81			81
	PECO Trust IV	103			103
	BGE Capital Trust II	258			258
	Total long-term debt due to financing trusts	$	648		$	648
	____________________________
	(a)	The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.
	(b)	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
	(c)	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
	(d)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
	(e)	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
	(f)	The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012.
	Transactions involving Generation, ComEd, PECO and BGE are further described in the tables below.
	Generation
	The financial statements of Generation include related party transactions as presented in the tables below:
		For the Years Ended
		December 31,
		2014			2013		2012
	Operating revenues from affiliates:
	ComEd (a)	$	176		$	506	$	795
	PECO (b)	198			405		543
	BGE (c)	387			455		322
	CENG (d)	17			56		42
BSC	1			1		—
Total operating revenues from affiliates	$	779		$	1,423	$	1,702
Purchase power and fuel from affiliates:
ComEd	$	1		$	1	$	—
BGE	25			13		8
CENG (e)	282			992		793
Keystone Fuels, LLC (i)	138			144		119
Conemaugh Fuels, LLC (i)	99			98		101
Safe Harbor Water Power Corporation (i)	12			22		23
Total purchase power and fuel from affiliates	$	557		$	1,270	$	1,044
Operating and maintenance from affiliates:
ComEd (f)	$	3		$	2	$	2
PECO (f)	2			1		3
BSC (g)	618			571		625
Total operating and maintenance from affiliates	$	623		$	574	$	630
Interest expense to affiliates, net:
Exelon Corporate	$	53		$	59	$	75
Earnings (losses) in equity method investments
CENG (h)	$	(19	)	$	9	$	(99	)
Qualifying facilities and domestic power projects	(1		)	1		8
Total earnings (losses) in equity method investments	$	(20	)	$	10	$	(91	)
Capitalized costs
BSC (g)	$	91		$	93	$	80
Cash distribution paid to member	$	645		$	625	$	1,626
Contribution from member	$	53		$	26	$	48
	December 31,
	2014			2013
Receivables from affiliates (current):
CENG (d)	$	—		$	3
ComEd (a)	43			38
PECO (b)	29			38
BGE (c)	40			27
Other	1			2
Total receivables from affiliates (current)	$	113		$	108
Long-term debt due to affiliates (current):
Exelon Corporate (l)	556			—
Payables to affiliates (current):
CENG (e)	$	—		$	85
Exelon Corporate (j)	12			7
BSC (g)	83			66
ComEd	12			—
Keystone Fuels, LLC (i)	—			12
Conemaugh Fuels, LLC (i)	—			9
Other	—			2
Total payables to affiliates (current)	$	107		$	181
Long-term debt due to affiliates (noncurrent):
Exelon Corporate (l)	943			1,523
Payables to affiliates (noncurrent):
BSC (g)	$	1		$	—
ComEd (k)	2,389			2,293
PECO (k)	490			447
Total payables to affiliates (noncurrent)	$	2,880		$	2,740
_______________________
(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
(d)	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(e)	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(f)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
(g)	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(h)	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(i)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
(j)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.
(k)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations.
(l)	In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.
ComEd
The financial statements of ComEd include related party transactions as presented in the tables below:
	For the Years Ended
	December 31,
	2014			2013		2012
Operating revenues from affiliates
Generation	$	4		$	3	$	2
Purchased power from affiliate
Generation (a)	$	176		$	512	$	789
Operating and maintenance from affiliate
BSC (b)	$	166		$	157	$	163
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13	$	13
Capitalized costs
BSC (b)	$	77		$	69	$	92
Cash dividends paid to parent	$	307		$	220	$	105
Contribution from parent	$	273		$	—	$	11
	December 31,
	2014			2013
Prepaid voluntary employee beneficiary association trust (c)	$	13		$	13
Receivable from affiliates (current):
Voluntary employee beneficiary association trust	$	2		$	3
Generation	12			—
Total receivable from affiliates (current)	$	14		$	3
Receivable from affiliates (noncurrent):
Generation (d)	$	2,389		$	2,293
Exelon Corporate (e)	182			176
Total receivable from affiliates (noncurrent)	$	2,571		$	2,469
Payables to affiliates (current):
Generation (a)	$	43		$	38
BSC (b)	32			30
ComEd Financing III	4			4
PECO	2			—
Exelon Corporate	3			9
Other	—			2
Total payables to affiliates (current)	$	84		$	83
Long-term debt to ComEd financing trust
ComEd Financing III	$	206		$	206
_______________________
(a)	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information.
(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(c)	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
(d)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.
(e)	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.
PECO
The financial statements of PECO include related party transactions as presented in the tables below:
	For the Years Ended
	December 31,
	2014			2013		2012
Operating revenues from affiliates:
Generation (a)	$	2		$	1	$	3
Purchased power from affiliate
Generation (b)	$	194		$	392	$	533
Operating and maintenance from affiliates:
BSC (c)	$	96		$	98	$	107
Generation	3			3		4
Total operating and maintenance from affiliates	$	99		$	101	$	111
Interest expense to affiliates, net:
PECO Trust III	$	6		$	6	$	6
PECO Trust IV	6			6		6
Total interest expense to affiliates, net	$	12		$	12	$	12
Capitalized costs
BSC (c)	$	39		$	46	$	54
Cash dividends paid to parent	$	320		$	332	$	343
Contribution from parent	$	24		$	27	$	9
	December 31,
	2014			2013
Prepaid voluntary employee beneficiary association trust (d)	$	3		$	3
Receivable from affiliate (current):
ComEd	$	2		$	—
BGE	1			3
Total receivable from affiliates (current)	$	3		$	3
Receivable from affiliate (noncurrent):
Generation (e)	$	490		$	447
Payables to affiliates (current):
Generation (b)	$	29		$	38
BSC (c)	20			17
Exelon Corporate	2			2
PECO Trust III	1			1
Total payables to affiliates (current)	$	52		$	58
Long-term debt to financing trusts:
PECO Trust III	$	81		$	81
PECO Trust IV	103			103
Total long-term debt to financing trusts	$	184		$	184
________________________
(a)	PECO provides energy to Generation for Generation’s own use.
(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.
(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.
(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.
BGE
The financial statements of BGE include related party transactions as presented in the tables below:
	For the Years Ended
	December 31,
	2014			2013		2012
Operating revenues from affiliates:
Generation (a)	$	25		$	13	$	10
Purchased power from affiliate
Generation (b)	$	382		$	452	$	396
Operating and maintenance from affiliates:
BSC (c)	$	103		$	83	$	106
Interest expense to affiliates, net:
BGE Capital Trust II	$	16		$	16	$	16
Capitalized costs
BSC (c)	$	19		$	15	$	21
Contribution from parent	$	—		$	—	$	66
	December 31,
	2014			2013
Prepaid voluntary employee beneficiary association trust (d)	$	1		$	1
Payables to affiliates (current):
Generation (b)	$	40		$	27
BSC (c)	17			20
Exelon Corporate	5			1
PECO	1			3
BGE Capital Trust II	3			4
Total payables to affiliates (current)	$	66		$	55
Long-term debt to BGE financing trust
BGE Capital Trust II	$	258		$	258
______________________
(a)	BGE provides energy to Generation for Generation’s own use.
(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(d)	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.

Quarterly_Data_Unaudited_Exelo

Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Abstract]
Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE)	Quarterly Data (Unaudited) (Exelon, Generation, ComEd, PECO and BGE)
	Exelon
	The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating Income								Net (Loss) Income
																	on Common
																	Stock
		2014			2013				2014				2013				2014				2013
	Quarter ended:
	31-Mar	$	7,237		$	6,082			$	168		(a)	$	513		(b)	$	90			$	(4	)	(c)
	30-Jun	6,024			6,141				842			(a)	1,005				522				490
	30-Sep	6,912			6,502				1,739			(a)	1,262			(b)	993				738
	31-Dec	7,255			6,163				348				889				18			(d)	495
	____________________________
	(a)	In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.
	(b)	In the first and third quarter of 2013, Exelon reclassified $5 million and $8 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.
	(c)	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
	(d)	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
		Average Basic Shares					Net (Loss) Income
		Outstanding					per Basic Share
		(in millions)
		2014		2013			2014				2013
	Quarter ended:
	31-Mar	858		855			$	0.1			$	(0.01	)
	30-Jun	860		856			0.61				0.57
	30-Sep	861		857			1.15				0.86
	31-Dec	861		856			0.02				0.6
		Average Diluted Shares					Net (Loss) Income
		Outstanding					per Diluted Share
		(in millions)
		2014		2013			2014				2013
	Quarter ended:
	31-Mar	861		855			$	0.1			$	(0.01	)
	30-Jun	864		860			0.6				0.57
	30-Sep	863		860			1.15				0.86
	31-Dec	868		860			0.02				0.59
	The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
		2014															2013
		Fourth			Third				Second				First				Fourth				Third				Second		First
		Quarter			Quarter				Quarter				Quarter				Quarter				Quarter				Quarter		Quarter
	High price	$	38.93		$	36.26			$	37.73			$	33.94			$	30.59			$	32.42			$	37.8	$	34.56
	Low price	33.07			30.66				33.11				26.45				26.64				29.42				29.84		29.1
	Close	37.08			34.09				36.48				33.56				27.39				29.64				30.88		34.48
	Dividends	0.31			0.31				0.31				0.31				0.31				0.31				0.31		0.525
	Generation
	The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating (Loss) Income								Net (Loss) Income
																	on Membership
																	Interest
		2014			2013				2014 (a)				2013				2014				2013
	Quarter ended:
	31-Mar	$	4,390		$	3,533			$	(384	)	(a)	$	(59	)	(b)	$	(185	)		$	(18	)
	30-Jun	3,789			4,070				441			(a)	603				340				330
	30-Sep	4,412			4,255				1,225			(a)	729			(b)	771				490
	31-Dec	4,802			3,772				(105		)		405				(91		)		269
	____________________________
	(a)	In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.
	(b)	In the first and third quarter of 2013, Generation reclassified $5 million and $8 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.
	ComEd
	The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating Income								Net (Loss) Income
		2014			2013				2014				2013				2014				2013
	Quarter ended:
	31-Mar	$	1,134		$	1,160			$	238			$	209			$	98			$	(81	)
	30-Jun	1,128			1,080				259			(a)	232				111				96
30-Sep	1,222			1,156				288			(a)	278				126				126
31-Dec	1,079			1,068				196				236				73				109
____________________________
(a)	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income.
PECO
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
	Operating Revenues							Operating Income								Net Income
																on Common
																Stock
	2014			2013				2014				2013				2014				2013
Quarter ended:
31-Mar	$	993		$	895			$	149			$	203			$	89			$	121
30-Jun	656			672				134				138				84				72
30-Sep	693			728				133				155				81				92
31-Dec	750			805				156				168				98				102
BGE
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
	Operating Revenues							Operating								Net Income
								Income								attributable to
																Common Shareholders
	2014			2013				2014				2013				2014				2013
Quarter ended:
31-Mar	$	1,054		$	880			$	169			$	163			$	85			$	77
30-Jun	653			653				55				69				16				22
30-Sep	697			737				102				114				46				50
31-Dec	761			794				113				101				52				47

Schedule_I_Condensed_Financial

Schedule I - Condensed Financial Information of Parent (Exelon Corporate)	12 Months Ended
	Dec. 31, 2014
Condensed Financial Information of Parent Company Only Disclosure [Abstract]
Schedule I - Condensed Financial Information of Parent (Exelon Corporate)	Exelon Corporation and Subsidiary Companies
	Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
	Condensed Statements of Operations and Other Comprehensive Income
		For the Years Ended
		December 31,
	(In millions)	2014				2013			2012
	Operating expenses
	Operating and maintenance	$	9			$	9		$	201
	Operating and maintenance from affiliates	38				34			72
	Other	3				12			6
	Total operating expenses	50				55			279
	Operating loss	(50		)		(55		)	(279		)
	Other income and (deductions)
	Interest expense, net	(237		)		(116		)	(153		)
	Equity in earnings of investments	1,779				1,903			1,278
	Interest income from affiliates, net	53				36			75
	Other, net	(2		)		(78		)	7
	Total other income	1,593				1,745			1,207
	Income before income taxes	1,543				1,690			928
	Income taxes (benefit)	(80		)		(29		)	(232		)
	Net income	$	1,623			$	1,719		$	1,160
	Other comprehensive income (loss)
	Pension and non-pension postretirement benefit plans:
	Prior service cost (benefit) reclassified to periodic costs	$	(30	)		$	—		$	1
	Actuarial loss reclassified to periodic cost	147				208			168
	Transition obligation reclassified to periodic cost	—				—			2
	Pension and non-pension postretirement benefit plan valuation	(497		)		669			(371		)
	adjustment
	Unrealized loss on cash flow hedges	(148		)		(248		)	(120		)
	Unrealized gain on marketable securities	1				2			2
	Unrealized gain on equity investments	8				106			1
	Unrealized loss on foreign currency translation	(9		)		(10		)	—
	Reversal of CENG equity method AOCI	(116		)		—			—
	Other comprehensive income (loss)	(644		)		727			(317		)
	Comprehensive income	$	979			$	2,446		$	843
	See Notes to Financial Statements
	Exelon Corporation and Subsidiary Companies
	Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
	Condensed Statements of Cash Flows
		For the Years Ended
		December 31,
	(In millions)	2014				2013			2012
	Net cash flows provided by operating activities	$	806			$	1,053		$	2,131
	Cash flows from investing activities
	Return on investment of direct financing lease termination	335				—			—
	Changes in Exelon intercompany money pool	(83		)		(60		)	—
	Note receivable from affiliates	—				484			—
	Capital expenditures	1				—			(30		)
	Cash and restricted cash acquired from Constellation	—				—			679
	Change in restricted cash	—				38			(38		)
	Investment in affiliates	(70		)		(38		)	(67		)
	Other investing activities	(126		)		15			—
	Net cash flows provided by (used in) investing activities	57				439			544
	Cash flows from financing activities
	Cash receipts from intercompany money pool	—				—			(703		)
	Changes in short-term borrowings	—				10			(161		)
	Issuance of long-term debt	1,150				—			—
	Retirement of long-term debt	(23		)		(450		)	(77		)
	Dividends paid on common stock	(1,065		)		(1,249		)	(1,716		)
	Proceeds from employee stock plans	35				47			73
	Other financing activities	(84		)		(6		)	30
	Net cash flows provided by (used in) financing activities	13				(1,648		)	(2,554		)
	Increase (decrease) in cash and cash equivalents	876				(156		)	121
	Cash and cash equivalents at beginning of period	3				159			38
Cash and cash equivalents at end of period	$	879			$	3		$	159
See Notes to Financial Statements
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
	December 31,
(In millions)	2014				2013
ASSETS
Current assets
Cash and cash equivalents	$	879			$	3
Accounts receivable, net
Other accounts receivable	209				72
Accounts receivable from affiliates	24				22
Deferred income taxes	20				27
Notes receivable from affiliates	818				179
Regulatory assets	254				233
Other	22				1
Total current assets	2,226				537
Property, plant and equipment, net	54				57
Deferred debits and other assets
Regulatory assets	3,186				3,005
Investments in affiliates	26,670				26,390
Deferred income taxes	2,187				1,890
Notes receivable from affiliates	943				1,522
Other	172				17
Total deferred debits and other assets	33,158				32,824
Total assets	$	35,438			$	33,418
See Notes to Financial Statements
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
	December 31,
(In millions)	2014				2013
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Long-term debt due within one year	$	1,409			$	10
Accounts payable	2				43
Unamortized energy contract liabilities	—				12
Accrued expenses	25				106
Deferred income taxes	60				26
Regulatory liabilities	51				2
Other	75				54
Total current liabilities	1,622				253
Long-term debt	2,841				3,033
Long-term debt to affiliate	182				176
Deferred credits and other liabilities
Regulatory liabilities	37				43
Pension obligations	7,638				6,444
Non-pension postretirement benefit obligations	16				393
Deferred income taxes	93				70
Other	398				271
Total deferred credits and other liabilities	8,182				7,221
Total liabilities	12,827				10,683
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 860 and 857 shares	16,709				16,741
outstanding at December 31, 2014 and 2013, respectively)
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013,	(2,327		)		(2,327		)
respectively)
Retained earnings	10,910				10,358
Accumulated other comprehensive loss, net	(2,684		)		(2,040		)
Total shareholders’ equity	22,608				22,732
BGE preference stock not subject to mandatory redemption	3				3
Total liabilities and shareholders’ equity	$	35,438			$	33,418
See Notes to Financial Statements
Basis of Presentation
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.
Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which Exelon Corporate owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. Exelon owned none of PECO’s preference securities, which PECO redeemed in 2013.
Mergers
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. Exelon and PHI continue to expect to complete the merger in the second or third quarter of 2015. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the Merger Agreement with PHI.
On March 12, 2012, Exelon Corporation completed the merger contemplated by the Merger Agreement, among Exelon, Bolt Acquisition Corporation, a wholly owned subsidiary of Exelon (Merger Sub), and Constellation. As a result of that merger, Merger Sub was merged into Constellation (the Initial Merger) and Constellation became a wholly owned subsidiary of Exelon. Following the completion of the Initial Merger, Exelon and Constellation completed a series of internal corporate organizational restructuring transactions. Constellation merged with and into Exelon, with Exelon continuing as the surviving corporation (the Upstream Merger). Simultaneously with the Upstream Merger, Constellation’s interest in RF HoldCo LLC, which holds Constellation’s interest in BGE, was transferred to Exelon Energy Delivery Company, LLC, a wholly owned subsidiary of Exelon that also owns Exelon’s interests in ComEd and PECO. Following the Upstream Merger and the transfer of RF HoldCo LLC, Exelon contributed to Generation certain subsidiaries, including the customer supply and generation businesses that were acquired from Constellation as a result of the Initial Merger and the Upstream Merger.
For BGE’s debt, fuel supply contracts and regulatory assets not earning a return, the difference between fair value and book value of BGE’s assets acquired and liabilities assumed is recorded as a regulatory asset at Exelon Corporate as Exelon did not apply push-down accounting to BGE. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the merger with Constellation. Also see Note 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information on BGE’s push-down accounting treatment.
Debt and Credit Agreements
Short-Term Borrowings
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper borrowings at both December 31, 2014 and December 31, 2013.
Credit Agreements
On May 30, 2014, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank commitments of $500 million through May 2019. As of December 31, 2014, Exelon Corporation had available capacity under those commitments of $494 million. See Note 13—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further information regarding Exelon Corporation’s credit agreement.
Long-Term Debt
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2014 and December 31, 2013:
							Maturity	December 31,
	Rates						Date	2014			2013
Long-term debt
Junior subordinated notes				6.5	%		2017	$	1,150		$	—
Senior unsecured notes (a)	4.9	%	-	7.6	%		2015-2035	2,658			2,658
Total long-term debt								3,808			2,658
Unamortized debt discount and premium, net								1			2
Fair value adjustment								441			383
Long-term debt due within one year								(1,409		)	(10		)
Long-term debt								$	2,841		$	3,033
___________
(a)	Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.
The debt maturities for Exelon Corporate for the periods 2015, 2016, 2017, 2018, 2019 and thereafter are as follows:
2015	$	1,350
2016	—
2017	1,150
2018	—
2019	—
Remaining years	1,308
Total long-term debt	$	3,808
Commitments and Contingencies
See Note 22—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and contingencies related to environmental matters and fund transfer restrictions.
Related Party Transactions
The financial statements of Exelon Corporate include related party transactions as presented in the tables below:
	For the Years Ended
	December 31,
(In millions)	2014				2013			2012
Operating and maintenance from affiliates:
Business Services Company, LLC (a)	$	38			$	34		$	72
Interest income from affiliates, net:
Exelon Generation Consolidated	$	53			$	36		$	75
Equity in earnings of investments:
Exelon Energy Delivery Company, LLC (b)	$	958			$	834		$	713
Exelon Ventures Company, LLC (c)	926				1,076			564
UII, LLC	(6		)		(2		)	25
Exelon Transmission Company, LLC	(7		)		(5		)	(3		)
Exelon Enterprise	(1		)		—			—
Exelon Generation Consolidated	(91		)		—			—
Exelon Consolidations (d)	—				—			(21		)
Total equity in earnings of investments	$	1,779			$	1,903		$	1,278
Cash contributions received from affiliates	$	1,370			$	1,175		$	2,074
	December 31,
(in millions)	2014				2013
Accounts receivable from affiliates (current):
Business Services Company, LLC (a)	$	2			$	3
Generation	12				7
ComEd	3				9
PECO	2				2
BGE	5				1
Total accounts receivable from affiliates (current)	$	24			$	22
Notes receivable from affiliates (current):
Business Services Company, LLC (a)	$	262			$	179
Exelon Generation Consolidated (e)	$	556			$	—
Total receivable from affiliates (current):	$	818			$	179
Investments in affiliates:
Business Services Company, LLC (a)	$	193			$	201
Exelon Energy Delivery Company, LLC (b)	13,590				12,956
Exelon Ventures Company, LLC (c)	—				12,750
UII, LLC	130				470
Exelon Transmission Company, LLC	1				3
VEBA	9				10
Exelon Enterprises	23				—
Exelon Generation Consolidated	12,720				—
Exelon Consolidations	4				—
Total investments in affiliates	$	26,670			$	26,390
Notes receivable from affiliates (non-current):
Generation (e)	$	943			$	1,522
Long-term debt to affiliates (non-current):
ComEd	$	182			$	176
_____________________
(a)	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.
(b)	Exelon Energy Delivery Company, LLC consists of ComEd, PECO and BGE.
(c)	Exelon Ventures Company, LLC primarily consisted of Generation and was fully dissolved as of December 31, 2014. Exelon Enterprises, Exelon Generation Consolidated, and Exelon Consolidations are now directly owned Exelon Corporate investments as of December 31, 2014.
(d)	Equity in earnings of investments for Exelon Consolidations represents the intercompany income component that offsets the corresponding intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.
(e)	In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-Term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts	12 Months Ended
	Dec. 31, 2014
Valuation and Qualifying Accounts [Abstract]
Schedule II - Valuation and Qualifying Accounts	Exelon Corporation and Subsidiary Companies
	Schedule II – Valuation and Qualifying Accounts
	Column A	Column B		Column C						Column D				Column E
				Additions and adjustments
	Description	Balance at		Charged to			Charged			Deductions				Balance at
		Beginning		Costs and			to Other							End
		of Period		Expenses			Accounts							of Period
		(in millions)
	For the year ended December 31, 2014
	Allowance for uncollectible accounts (a)	$	272	$	175		$	69	(c)	$	205		(d)	$	311
	Deferred tax valuation allowance	13		—			37			—				50
	Reserve for obsolete materials	58		5			34			2				95
	For the year ended December 31, 2013
	Allowance for uncollectible accounts (a)	$	293	$	121		$	37	(c)	$	179		(d)	$	272
	Deferred tax valuation allowance	36		1			—			24				13
	Reserve for obsolete materials	53		17			—			12				58
	For the year ended December 31, 2012
	Allowance for uncollectible accounts (a)	$	199	$	144		$	136	(b)(c)	$	186		(d)	$	293
	Deferred tax valuation allowance	10		18			18		(b)	10				36
	Reserve for obsolete materials	60		2			2		(b)	11				53
	___________________
	(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively.
	(b)	Primarily represents the addition of Constellation’s and BGE’s results as of March 12, 2012, the date of the merger.
	(c)	Includes charges for late payments and non-service receivables.
	(d)	Write-off of individual accounts receivable.
	Exelon Generation Company, LLC and Subsidiary Companies
	Schedule II – Valuation and Qualifying Accounts
	Generation
	1		Financial Statements:
			Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP
			Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012
			Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
			Consolidated Balance Sheets at December 31, 2014 and 2013
			Consolidated Statements of Changes in Member’s Equity for the Years Ended December 31, 2014, 2013 and 2012
			Notes to Consolidated Financial Statements
	2		Financial Statement Schedules:
			Schedule II – Valuation and Qualifying Accounts
			Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
	Exelon Generation Company, LLC and Subsidiary Companies
	Schedule II – Valuation and Qualifying Accounts
	Column A	Column B		Column C						Column D				Column E
				Additions and adjustments
	Description	Balance at		Charged to			Charged			Deductions				Balance at
		Beginning		Costs and			to Other							End
		of Period		Expenses			Accounts							of Period
		(in millions)
	For the year ended December 31, 2014
	Allowance for uncollectible accounts	$	57	$	14		$	8		$	19			$	60
	Deferred tax valuation allowance	11		—			37			—				48
	Reserve for obsolete materials	55		5			32			(1		)		93
	For the year ended December 31, 2013
	Allowance for uncollectible accounts	$	84	$	(16	)	$	—		$	11			$	57
	Deferred tax valuation allowance	35		1			—			25				11
	Reserve for obsolete materials	50		16			—			11				55
	For the year ended December 31, 2012
	Allowance for uncollectible accounts	$	29	$	—		$	66	(a)	$	11			$	84
	Deferred tax valuation allowance	—		17			18		(a)	—				35
	Reserve for obsolete materials	59		—			2		(a)	11				50
	____________________
	(a)	Represents the addition of Constellation’s results as of March 12, 2012, the date of the merger.
	Commonwealth Edison Company and Subsidiary Companies
	Schedule II – Valuation and Qualifying Accounts
	ComEd
	1		Financial Statements:
		Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Balance Sheets at December 31, 2014 and 2013
		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012
		Notes to Consolidated Financial Statements
2		Financial Statement Schedules:
		Schedule II – Valuation and Qualifying Accounts
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A	Column B		Column C						Column D				Column E
			Additions and adjustments
Description	Balance at		Charged to			Charged			Deductions				Balance at
	Beginning		Costs and			to Other							End
	of Period		Expenses			Accounts							of Period
	(in millions)
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	62	$	45		$	33	(a)	$	56		(b)	$	84
Reserve for obsolete materials	2		—			2			2				2
For the year ended December 31, 2013
Allowance for uncollectible accounts	$	70	$	33		$	29	(a)	$	70		(b)	$	62
Reserve for obsolete materials	2		1			—			1				2
For the year ended December 31, 2012
Allowance for uncollectible accounts	$	78	$	42		$	26	(a)	$	76		(b)	$	70
Reserve for obsolete materials	1		1			—			—				2
_____________________
(a)	Primarily charges for late payments and non-service receivables.
(b)	Write-off of individual accounts receivable.
PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
PECO
1		Financial Statements:
		Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Balance Sheets at December 31, 2014 and 2013
		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012
		Notes to Consolidated Financial Statements
2		Financial Statement Schedules:
		Schedule II – Valuation and Qualifying Accounts
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A	Column B		Column C						Column D				Column E
			Additions and adjustments
Description	Balance at		Charged to			Charged			Deductions				Balance at
	Beginning		Costs and			to Other							End
	of Period		Expenses			Accounts							of Period
	(in millions)
For the year ended December 31, 2014
Allowance for uncollectible accounts (a)	$	107	$	52		$	11	(b)	$	70		(c)	$	100
Reserve for obsolete materials	1		—			—			—				1
For the year ended December 31, 2013
Allowance for uncollectible accounts (a)	$	99	$	61		$	7	(b)	$	60		(c)	$	107
Reserve for obsolete materials	1		—			—			—				1
For the year ended December 31, 2012
Allowance for uncollectible accounts (a)	$	92	$	60		$	8	(b)	$	61		(c)	$	99
Reserve for obsolete materials	1		—			—			—				1
_____________________
(a)	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively.
(b)	Primarily charges for late payments.
(c)	Write-off of individual accounts receivable.
Baltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
BGE
1		Financial Statements:
		Report of Independent Registered Public Accounting Firm dated February 13, 2015 of PricewaterhouseCoopers LLP
		Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
		Consolidated Balance Sheets at December 31, 2014 and 2013
		Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012
		Notes to Consolidated Financial Statements
2		Financial Statement Schedules:
		Schedule II – Valuation and Qualifying Accounts
		Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements, including the notes thereto
Baltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A	Column B		Column C						Column D				Column E
			Additions and adjustments
Description	Balance at		Charged to			Charged			Deductions				Balance at
	Beginning		Costs and			to Other							End
	of Period		Expenses			Accounts							of Period
	(in millions)
For the year ended December 31, 2014
Allowance for uncollectible accounts	$	46	$	64		$	17	(b)	$	60		(a)	$	67
Deferred tax valuation allowance	1		—			—			—				1
Reserve for obsolete materials	1		—			—			1				—
For the year ended December 31, 2013
Allowance for uncollectible accounts	$	40	$	43		$	1		$	38		(a)	$	46
Deferred tax valuation allowance	1		—			—			—				1
Reserve for obsolete materials	1		—			—			—				1
For the year ended December 31, 2012
Allowance for uncollectible accounts	$	38	$	45		$	—		$	43		(a)	$	40
Deferred tax valuation allowance	—		1			—			—				1
Reserve for obsolete materials	—		1			—			—				1
_____________________
(a)	Write-off of individual accounts receivable.
(b)	Primarily charges for late payments.

Significant_Accounting_Policie1

Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Description of Business (Exelon, Generation, ComEd, PECO and BGE)	Description of Business (Exelon, Generation, ComEd, PECO and BGE)
	Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. Prior to March 12, 2012, Exelon’s principal subsidiaries included ComEd, PECO and Generation. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger (“Merger Agreement”). As a result of the merger transaction, Generation now includes the former Constellation generation and customer supply operations. BGE, formerly Constellation’s regulated utility subsidiary, is now a subsidiary of Exelon. Refer to Note 4 — Mergers, Acquisitions, and Dispositions for further information regarding the merger transaction.
	On April 1, 2014, Generation assumed the operating licenses and corresponding operational control of CENG’s nuclear fleet. As a result, Exelon and Generation consolidated CENG’s financial position and results of operations into their businesses. Prior to April 1, 2014, Exelon and Generation accounted for CENG as an equity method investment. Refer to Note 5 — Investment in Constellation Energy Nuclear Group, LLC for further information regarding the integration transaction.
	The energy generation business includes:
	•	Generation: Physical delivery and marketing of owned and contracted electric generation capacity and provision of renewable and other energy-related products and services, and natural gas exploration and production activities. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other regions.
	The energy delivery businesses include:
	•	ComEd: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in northern Illinois, including the City of Chicago.
	•	PECO: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in southeastern Pennsylvania, including the City of Philadelphia, and the purchase and regulated retail sale of natural gas and the provision of distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
	•	BGE: Purchase and regulated retail sale of electricity and the provision of distribution and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of distribution services in central Maryland, including the City of Baltimore.
	Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)
	This is a combined annual report of Exelon, Generation, ComEd, PECO and BGE. The Notes to the Consolidated Financial Statements apply to Exelon, Generation, ComEd, PECO and BGE as indicated parenthetically next to each corresponding disclosure. When appropriate, Exelon, Generation, ComEd, PECO and BGE are named specifically for their related activities and disclosures.
	Exelon did not apply push-down accounting to BGE and BGE continued to be subject to reporting requirements as an SEC registrant. The information disclosed for BGE represents the activity of the standalone entity for the twelve months ended December 31, 2014, 2013 and 2012 and the financial position as of December 31, 2014 and December 31, 2013. However, for Exelon’s consolidated financial reporting, Exelon is reporting BGE activity from the acquisition date of March 12, 2012 through December 31, 2014.
	Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
	Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology and supply management services. The costs of BSC, including support services, are directly charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total assets and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
	Exelon owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for ComEd, of which Exelon owns more than 99%, and BGE, of which Exelon owns 100% of the common stock but none of BGE’s preference stock. Exelon owned none of PECO’s preferred securities, which PECO redeemed in 2013. Exelon has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2014 and December 31, 2013, as equity, PECO’s preferred securities as preferred securities of subsidiary through their redemption in 2013, and BGE’s preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco LLC with limited voting rights on specified matters.
	Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain Exelon Wind projects, of which Generation holds a majority interest of 99% for certain periods of time, and CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interest on Exelon’s and Generation’s Consolidated Balance Sheets. See Note 2 — Variable Interest Entities for further discussion of Exelon’s and Generation’s VIEs and the reversionary interests of the noncontrolling members for these certain subsidiaries.
	ComEd owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for RITELine Illinois, LLC, of which ComEd owns 75% and an additional12.5% is indirectly owned by Exelon. Exelon and ComEd have reflected the third-party interests of 12.5% and 25%, respectively, in RITELine Illinois, LLC, which both totaled less than $1 million at December 31, 2014 and December 31, 2013, as equity.
	Exelon consolidates the accounts of entities in which Exelon has a controlling financial interest, after the elimination of intercompany transactions. A controlling financial interest is evidenced by either a voting interest greater than 50% in which Exelon can exercise control over the operations and policies of the investee, or the results of a model that identifies Exelon or one of its subsidiaries as the primary beneficiary of a VIE. Where Exelon does not have a controlling financial interest in an entity, it applies proportional consolidation, equity method accounting or cost method accounting. Exelon applies proportionate consolidation when it has an undivided interest in an asset and is proportionately liable for its share of each liability associated with the asset. Exelon proportionately consolidates its undivided ownership interests in jointly owned electric plants and transmission facilities, as well as its undivided ownership interests in Upstream natural gas exploration and production activities. Under proportionate consolidation, Exelon separately records its proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. Exelon applies equity method accounting when it has significant influence over an investee through an ownership in common stock, which generally approximates a 20% to 50% voting interest. Exelon applies equity method accounting to certain investments and joint ventures, including certain financing trusts of ComEd, PECO, and BGE. Under the equity method, Exelon reports its interest in the entity as an investment and Exelon’s percentage share of the earnings from the entity as single line items in its financial statements. Exelon uses the cost method if it holds less than 20% of the common stock of an entity. Under the cost method, Exelon reports its investment at cost and recognizes income only to the extent Exelon receives dividends or distributions.
	The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
Use Of Estimates (Exelon, Generation, ComEd, PECO and BGE)	Use of Estimates (Exelon, Generation, ComEd, PECO and BGE)
	The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and other postretirement benefits, the application of purchase accounting, inventory reserves, allowance for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.
Reclassifications (Exelon, ComEd, and BGE)	Reclassifications (Exelon, Generation, ComEd, PECO and BGE)
	Certain prior year amounts in the registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants’ net income, financial positions, or cash flows from operating activities.
Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE)	Accounting for the Effects of Regulation (Exelon, ComEd, PECO and BGE)
	Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation, which requires ComEd, PECO and BGE to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator; (2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates are set at levels that will recover the entities’ costs from customers. Exelon, ComEd, PECO and BGE account for their regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, the PAPUC, and the MDPSC, in the cases of ComEd, PECO and BGE, respectively, under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon believes that it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. However, Exelon, ComEd, PECO and BGE continue to evaluate their respective abilities to apply the authoritative guidance for accounting for certain types of regulation, including consideration of current events in their respective regulatory and political environments. If a separable portion of ComEd’s, PECO’s or BGE’s business was no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the effects of regulation for that portion, which could have a material impact on their results of operations and financial positions. See Note 3 — Regulatory Matters for additional information.
	The Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties affected by the order.
Revenues (Exelon, Generation, ComEd, PECO and BGE)	Revenues (Exelon, Generation, ComEd, PECO and BGE)
	Operating Revenues. Operating revenues are recorded as service is rendered or energy is delivered to customers. At the end of each month, the Registrants accrue an estimate for the unbilled amount of energy delivered or services provided to customers. ComEd records its best estimates of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE records its best estimate of the transmission revenue impact resulting from changes in rates that BGE believes are probable of approval by FERC in accordance with its formula rate mechanism. See Note 3 — Regulatory Matters and Note 6 — Accounts Receivable for further information.
	RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is based on the net sale or purchase position of the Company in the different RTOs and ISOs.
	Option Contracts, Swaps and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the intent of the transaction. For example, gas transactions may be used to hedge the sale of power. This will result in the change in fair value recorded through revenue. As of the Constellation merger date, Exelon and Generation have currently elected to de-designate all of their commodity cash flow hedge positions. As ComEd receives full cost recovery for energy procurement and related costs from retail customers, ComEd records the fair value of its energy swap contracts with unaffiliated suppliers as well as an offsetting regulatory asset or liability on its Consolidated Balance Sheets. Refer to Note 3 — Regulatory Matters and Note 12 — Derivative Financial Instruments for further information.
	Proprietary Trading Activities. Exelon and Generation account for Generation’s trading activities under the provisions of the authoritative guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to energy trading contracts to be presented on a net basis in the income statement. Commodity derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating revenues. Refer to Note 12 — Derivative Financial Instruments for further information.
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
	Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred on the Registrants’ Consolidated Balance Sheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, the Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense or Other income and deductions (interest income) on their Consolidated Statements of Operations and Comprehensive Income.
	Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain state jurisdictions where allowed or required. See Note 14 — Income Taxes for further information.
	Taxes Directly Imposed on Revenue-Producing Transactions (Exelon, Generation, ComEd, PECO and BGE)
	Exelon, Generation, ComEd, PECO and BGE collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges, and fees that are levied by state or local governments on the sale or distribution of gas and electricity. Some of these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income. However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis. Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 23 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s and BGE’s utility taxes that are presented on a gross basis.
Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)	Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.
	Restricted Cash and Cash Equivalents (Exelon, Generation, ComEd, PECO and BGE)
	Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2014 and 2013, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-term disability benefits. Additionally, as of December 31, 2014 and 2013, Generation’s restricted cash and cash equivalents primarily included cash at Antelope Valley required for debt service and construction and cash at Continental Wind and ExGen Texas Power, which is required for debt service and financing of operation and maintenance of the underlying entities. As of December 31, 2014 and 2013, ComEd’s restricted cash primarily represented cash collateral held from suppliers associated with ComEd’s energy and REC procurement contracts. As of December 31, 2014, PECO’s restricted cash primarily represented funds from the sales of assets that were subject to PECO’s mortgage indenture. As of December 31, 2014 and 2013, BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for repayment of rate stabilization bonds and cash collateral held from suppliers.
	Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2014 and 2013, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent assets. As of December 31, 2014, Exelon, Generation, ComEd, PECO and BGE had investments in Rabbi trusts classified as noncurrent assets.
Allowance for Uncollectible Accounts (Exelon, Generation, ComEd, PECO and BGE)	Allowance for Uncollectible Accounts (Exelon, Generation, ComEd, PECO and BGE)
	The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For Generation, the allowance is based on accounts receivable aging, historical experience and other currently available information. ComEd and PECO estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. At December 31, 2013, BGE estimated the allowance for uncollectible accounts on customer receivables by assigning a reserve factor for each aging bucket. These percentages were derived from a study of billing progression which determined the reserve factors by aging bucket. At December 31, 2014, BGE changed to a methodology for estimating the allowance for uncollectible accounts, which was consistent with ComEd and PECO, as described above. For additional information regarding the change in estimate, refer to Note 6 — Accounts Receivable.
	Risk segments represent a group of customers with similar credit quality indicators that are computed based on various attributes, including delinquency of their balances and payment history. Loss rates applied to the accounts receivable balances are based on historical average charge-offs as a percentage of accounts receivable in each risk segment. ComEd, PECO and BGE customers’ accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a monthly basis. ComEd, PECO and BGE customer accounts are written off consistent with approved regulatory requirements. ComEd’s, PECO’s and BGE’s provisions for uncollectible accounts will continue to be affected by changes in volume, prices and economic conditions as well as changes in ICC, PAPUC and MDPSC regulations, respectively. See Note 3 — Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.
Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)	Variable Interest Entities (Exelon, Generation, ComEd, PECO and BGE)
	Exelon accounts for its investments in and arrangements with VIEs based on the authoritative guidance which includes the following specific requirements:
	•	requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
	•	requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and
	•	requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.
	Based on the above accounting guidance, Exelon has adopted the following policies related to variable interest entities:
	•	Exelon has disclosed, to the extent material, the assets of its consolidated VIEs that can only be used to settle specific obligations of the consolidated VIE, and the liabilities of Exelon’s consolidated VIEs for which creditors do not have recourse to Exelon’s general credit.
	•	Exelon has qualitatively assessed whether the equity holders of the entity have the power to direct matters that most significantly impact the entity.
	See Note 2 — Variable Interest Entities for additional information.
Inventories (Exelon, Generation, ComEd, PECO and BGE)	Inventories (Exelon, Generation, ComEd, PECO and BGE)
	Inventory is recorded at the lower of weighted average cost or market. Provisions are recorded for excess and obsolete inventory.
	Fossil Fuel. Fossil fuel inventory includes the weighted average costs of stored natural gas, propane, coal and oil. The costs of natural gas, propane, coal and oil are generally included in inventory when purchased and charged to fuel expense when used or sold.
	Materials and Supplies. Materials and supplies inventory generally includes the weighted average costs of transmission, distribution and generating plant materials. Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant and equipment, as appropriate, when installed or used.
	Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other deferred debits (for emission allowances that are exercisable beyond one year) and are carried at the lower of weighted average cost or market and charged to fuel expense as they are used in operations.
Marketable Securities (Exelon, Generation, ComEd, PECO and BGE)	Marketable Securities (Exelon, Generation, ComEd, PECO and BGE)
	All marketable securities are reported at fair value. Marketable securities held in the NDT funds, certain Generation Rabbi trust investments and BGE’s Rabbi trust investments are classified as trading securities and all other securities are classified as available-for-sale securities. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement Units are included in regulatory liabilities at Exelon, ComEd and PECO and in noncurrent payables to affiliates at Generation and in noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Realized and unrealized gains and losses, net of tax, on certain Generation Rabbi trust investments and BGE’s Rabbi trust investments are included in earnings at Exelon, Generation and BGE. Unrealized gains and losses, net of tax, for Generation’s, ComEd’s and PECO’s available-for-sale securities are reported in OCI. Any decline in the fair value of ComEd’s and PECO’s available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-down is included in earnings. See Note 15 — Asset Retirement Obligations for information regarding marketable securities held by NDT funds and Note 23 — Supplemental Financial Information for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities.
Property Plant And Equipment (Exelon, Generation, ComEd, PECO and BGE)	Property, Plant and Equipment (Exelon, Generation, ComEd, PECO and BGE)
	Property, plant and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. ComEd, PECO and BGE also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate, original cost also includes capitalized interest for Generation and Exelon Corporate and AFUDC for regulated property at ComEd, PECO and BGE. The cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to maintenance expense as incurred.
	Third parties reimburse ComEd, PECO and BGE for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs (CIAC) are recorded as a reduction to Property, Plant and Equipment. DOE SGIG funds reimbursed to PECO and BGE are accounted for as CIAC.
	For Generation, upon retirement, the cost of property is charged to accumulated depreciation in accordance with the composite method of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to operating and maintenance expense as incurred.
	For ComEd, PECO and BGE, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation in accordance with the composite method of depreciation. ComEd’s and BGE’s depreciation expense includes the estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility’s regulatory recovery method. ComEd’s and BGE’s actual incurred removal costs are applied against a related regulatory liability. PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed consistent with PECO’s regulatory recovery method.
	Generation’s oil and gas exploration and production activities consist of working interests in gas producing fields. Generation accounts for these activities under the successful efforts method of accounting. Acquisition, development and exploration costs are capitalized. Costs of drilling exploratory wells are initially capitalized and later charged to expense if reserves are not discovered or deemed not to be commercially viable. Other exploratory costs are charged to expense when incurred.
	See Note 7 — Property, Plant and Equipment, Note 9 — Jointly Owned Electric and Note 23 — Supplemental Financial Information for additional information regarding property, plant and equipment.
Nuclear Fuel (Exelon and Generation)	Nuclear Fuel (Exelon and Generation)
	The cost of nuclear fuel is capitalized within property, plant and equipment and charged to fuel expense using the unit-of-production method. Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. On-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 22 — Commitments and Contingencies for additional information regarding the SNF disposal fee.
Nuclear Outage Costs (Exelon and Generation)	Nuclear Outage Costs (Exelon and Generation)
	Costs associated with nuclear outages, including planned major maintenance activities, are expensed to operating and maintenance expense or capitalized to property, plant and equipment (based on the nature of the activities) in the period incurred.
New Site Development Costs (Exelon and Generation)	New Site Development Costs (Exelon and Generation)
	New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are capitalized when management considers project completion to be probable, primarily based on management’s determination that the project is economically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a plan to develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory approvals is probable. Capitalized development costs are charged to Operating and maintenance expense when project completion is no longer probable. At December 31, 2014 and 2013, there were not material capitalized development costs for projects not yet under construction included in Property, plant and equipment, net on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $13 million, $10 million and $4 million of costs were expensed by Exelon and Generation for the years ended December 31, 2014, 2013, and 2012, respectively. These costs primarily related to the possible development of new renewable energy projects.
Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE)	Capitalized Software Costs (Exelon, Generation, ComEd, PECO and BGE)
	Costs incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.
Depreciation, Depletion, and Amortization (Exelon, Generation, ComEd, PECO and BGE)	Depreciation, Depletion and Amortization (Exelon, Generation, ComEd, PECO and BGE)
	Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant and equipment on a straight-line basis using the composite method. ComEd’s and BGE’s depreciation includes a provision for estimated removal costs as authorized by the respective regulators. The estimated service lives for ComEd, PECO and BGE are primarily based on the average service lives from the most recent depreciation study for each respective company. The estimated service lives of the nuclear-fuel generating facilities are based on the remaining useful lives of the stations, which assume a 20-year license renewal extension of the operating licenses (to the extent that such renewal has not yet been granted) for all of Generation’s operating nuclear generating stations except for Oyster Creek. The estimated service lives of the hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of the operating licenses. The estimated service lives of the fossil fuel and other renewable generating facilities are based on the remaining useful lives of the stations, which Generation periodically evaluates based on feasibility assessments taking into account economic and capital requirement considerations.
	See Note 7 — Property, Plant and Equipment for further information regarding depreciation.
	Depletion of oil and gas exploration and production activities is recorded using the units-of-production method over the remaining life of the estimated proved reserves at the field level for acquisition costs and over the remaining life of proved developed reserves at the field level for development costs. The estimates for oil and gas reserves are based on internal calculations.
	Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have originally been recorded in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. With exception of income tax-related regulatory assets, generally, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s and BGE’s transmission formula rate regulatory assets is recorded to Operating revenues. Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is recorded to Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
	See Note 3 — Regulatory Matters and Note 23 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel, Generation’s ARC and the amortization of ComEd’s, PECO’s and BGE’s regulatory assets.
Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)	Asset Retirement Obligations (Exelon, Generation, ComEd, PECO and BGE)
	The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related to its nuclear generating stations, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational basis, at least once every five years. Changes to the recorded value of an ARO result from the passage of new laws and regulations, revisions to either the timing or amount of estimates of undiscounted cash flows, and estimates of cost escalation factors. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income or, in the case of the majority of ComEd’s, PECO’s, and BGE’s accretion, through an increase to regulatory assets. See Note 15 — Asset Retirement Obligations for additional information.
Capitalized Interest (Exelon, Generation, ComEd, PECO and BGE)	Capitalized Interest and AFUDC (Exelon, Generation, ComEd, PECO and BGE)
	During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
Allowance For Funds Used During Construction (Exelon, Generation, ComEd, PECO and BGE)	Exelon, ComEd, PECO and BGE apply the authoritative guidance for accounting for certain types of regulation to calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC that is included in interest expense for debt-related funds and other income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
Guarantees (Exelon, Generation, ComEd, PECO and BGE)	Guarantees (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken in issuing the guarantee, including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
	The liability that is initially recognized at the inception of the guarantee is reduced as the Registrants are released from risk under the guarantee. Depending on the nature of the guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational amortization method over the term of the guarantee. See Note 22 — Commitments and Contingencies for additional information.
Long-lived Assets (Exelon, Generation, ComEd, PECO and BGE)	Long-Lived Assets. The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when circumstances indicate the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, current energy prices and market conditions, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets and asset groups are impaired by comparing their undiscounted expected future cash flows to their carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value less costs to sell.
	Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent of the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level along with cash flows generated from the customer supply and risk management activities, including cash flows from contracts that are accounted for as intangible contract assets and liabilities recorded on the balance sheet. In certain cases, generation assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generation assets (typically contracted renewables). See Note 8 — Impairment of Long-Lived Assets for additional information.
Goodwill (Exelon, Generation, ComEd, PECO and BGE)	Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 10 — Intangible Assets for additional information regarding Exelon’s, Generation's and ComEd’s goodwill.
Equity Method Investments (Exelon, Generation, ComEd, PECO and BGE)	Equity Method Investments. Exelon and Generation regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other than temporary in nature. Additionally, if the project in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share of that impairment loss and evaluate the investment for an other than temporary decline in value.
	Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation)
	Exelon and Generation include equity in earnings from equity method investments in qualifying facilities, power projects and joint ventures, in equity in earnings (losses) of unconsolidated affiliates. Equity in earnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land, between their cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment.
	Exelon and Generation continuously monitor for issues that potentially could impact future profitability of these equity method investments and which could result in the recognition of an impairment loss if such investment experiences an other than temporary decline in value.
Direct Financing Lease Investments (Exelon, Generation, ComEd, PECO and BGE)	Direct Financing Lease Investments. Direct financing lease investments represent the estimated residual values of leased coal-fired plants in Georgia. Exelon reviews the estimated residual values of its direct financing lease investments and records an impairment charge if the review indicates an other than temporary decline in the fair value of the residual values below their carrying values. See Note 8 — Impairment of Long-Lived Assets for additional information.
Derivatives Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)	Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)
	All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the normal purchases and normal sales exception. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. For derivative contracts intended to serve as economic hedges and that are not designated or do not qualify for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives are recognized in earnings each period. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the Consolidated Statement of Operations based on the activity the transaction is economically hedging. For energy-related derivatives entered into for proprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on the Consolidated Statement of Operations. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction.
	For commodity derivative contracts Generation no longer utilizes the election provided for by the cash flow hedge designation and de-designated all of its existing cash flow hedges prior to the Constellation merger. Because the underlying forecasted transactions remained probable, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and was reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurred. The effect of this decision is that all derivatives executed to hedge economic risk related to commodities are recorded at fair value with changes in fair value recognized through earnings for the combined company.
	As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. Normal purchases and normal sales are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as normal purchases and normal sales are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See Note 12 — Derivative Financial Instruments for additional information.
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. Effective July 14, 2014, Exelon became the sponsor of all of CENG's pension and other postretirement benefit plans.
	The measurement of the plan obligations and costs of providing benefits under these plans involve various factors, including numerous assumptions and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations. The impact of assumption changes or experience different from that assumed on pension and other postretirement benefit obligations is recognized over time rather than immediately recognized in the income statement. Gains or losses in excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. See Note 16 — Retirement Benefits for additional discussion of Exelon’s accounting for retirement benefits.
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)	New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)
	Exelon has identified the following new accounting pronouncements that have been recently adopted or issued that management believes may significantly affect the Registrants.
	Presentation of Unrecognized Tax Benefits When Net Operating Loss Carryforwards, Similar Tax Losses or Tax Credit Carryforwards Exist
	In July 2013, the FASB issued authoritative guidance requiring entities to present unrecognized tax benefits as a reduction to deferred tax assets for losses or other tax carryforwards that would be available to offset the uncertain tax positions at the reporting date. This guidance was effective for the Registrants for periods beginning after December 15, 2013 and was required to be applied prospectively. The adoption of this standard had an immaterial effect on the presentation of deferred tax assets at Exelon and Generation and no effect on ComEd, PECO and BGE. There was no effect on the Registrants’ results of operations or cash flows.
	Pushdown Accounting (a consensus of the FASB Emerging Issues Task Force)
	In November 2014, the FASB issued authoritative guidance that allows acquired entities to apply pushdown accounting (i.e., reflecting the acquirer’s basis of accounting for the acquired entity’s assets and liabilities) when an acquirer obtains control of them. At the same time, the SEC rescinded its guidance on pushdown accounting. The SEC’s guidance had required pushdown accounting in certain circumstances, made it optional in others and prevented it in still other circumstances. The new guidance is effective immediately for any future transaction or to the most recent event in which an acquirer obtains or obtained control of the acquired entity. The adoption of the guidance had no impact to the financial statements of the Registrants; however, the Registrants will assess the potential impact of the guidance on future acquisitions.
	The following recently issued accounting standard is not yet required to be reflected in the combined financial statements of the Registrants.
	Revenue from Contracts with Customers
	In May 2014, the FASB issued authoritative guidance that changes the criteria for recognizing revenue from a contract with a customer. The new 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 is effective for the Registrants for the first interim period within annual reporting periods beginning on or after December 15, 2016. Early adoption is not 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 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.

Significant_Accounting_Policie2

Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Accounting Policies [Abstract]
Schedule Of Capitalized Software	The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:
	Net unamortized software costs	Exelon (a)			Generation (a)			ComEd			PECO			BGE
	December 31, 2014	$	596		$	193		$	133		$	84		$	163
	December 31, 2013	479			129			101			71			155
	Amortization of capitalized software costs	Exelon (a) (b)			Generation (a) (b)			ComEd			PECO			BGE (b)
	2014	$	186		$	59		$	45		$	28		$	43
	2013	198			67			52			33			36
	2012	208			81			56			30			32
	_______________________
	(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.
	(b)	Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.
Schedule Of Capitalized Interest And AFUDC	The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:
			Exelon(a)(b)			Generation(a)(b)			ComEd			PECO			BGE (b)
	2014	Total incurred interest (c)	$	1,144		$	419		$	323		$	115		$	118
		Capitalized interest	63			63			—			—			—
		Credits to AFUDC debt and equity	37			—			5			8			24
	2013	Total incurred interest (c)	$	1,423		$	411		$	584		$	117		$	129
		Capitalized interest	54			54			—			—			—
		Credits to AFUDC debt and equity	35			—			16			6			13
	2012	Total incurred interest (c)	$	1,003		$	368		$	310		$	125		$	149
		Capitalized interest	67			67			—			—			—
		Credits to AFUDC debt and equity	25			—			9			6			15
	_______________________
	(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.
	(b)	Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.
	(c)	Includes interest expense to affiliates.

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2014
Variable Interest Entity [Abstract]
Schedule of Variable Interest Entities	The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial statements at December 31, 2014 and 2013 are as follows:
		31-Dec-14												31-Dec-13
		Exelon (a) (b)				Generation (b)				BGE				Exelon (a)				Generation				BGE
	Current assets	$	1,271			$	1,242			$	21			$	484			$	446			$	28
	Noncurrent assets	7,580				7,566				3				1,905				1,884				3
	Total assets	$	8,851			$	8,808			$	24			$	2,389			$	2,330			$	31
	Current liabilities	$	611			$	526			$	77			$	566			$	481			$	74
	Noncurrent liabilities	2,730				2,600				120				774				562				195
	Total liabilities	$	3,341			$	3,126			$	197			$	1,340			$	1,043			$	269
	_______________________
	(a)	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
	(b)	Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information.
	31-Dec-13	Commercial				Equity				Total
		Agreement				Investment
		VIEs				VIEs
	Total assets(a)	$	128			$	332			$	460
	Total liabilities(a)	17				123				140
	Exelon's ownership interest in VIE(a)	—				86				86
	Other ownership interests in VIE(a)	111				123				234
	Registrants’ maximum exposure to loss:
	Carrying amount of equity method investments	7				67				74
	Contract intangible asset	9				—				9
	Debt and payment guarantees	—				5				5
	Net assets pledged for Zion Station decommissioning(b)	44				—				44
	___________________
	(a)	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
	(b)	These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.
	The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
	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
	As of December 31, 2014 and 2013, these assets and liabilities primarily consisted of the following:
			December 31, 2014												December 31, 2013
			Exelon				Generation				BGE					Exelon				Generation				BGE
	Cash and cash equivalents			$	392			$	392			$	—			$	62			$	62			$	—
	Restricted cash			117				96				21				80				52				28
	Accounts receivable, net
		Customer		297				297				—				260				260				—
		Other		57				57				—				—				—				—
	Mark-to-market derivatives assets			171				171				—				21				21				—
	Inventory
		Materials and supplies		172				172				—				—				—				—
	Other current assets			33				26				—				34				23				—
		Total current assets		1,239				1,211				21				457				418				28
	Property, plant and equipment, net			4,638				4,638				—				1,171				1,171				—
	Nuclear decommissioning trust funds			2,097				2,097				—				—				—				—
	Goodwill			47				47				—				—				—				—
	Mark-to-market derivatives assets			44				44				—				—				—				—
	Other noncurrent assets			95				82				3				127				106				3
		Total noncurrent assets		6,921				6,908				3				1,298				1,277				3
		Total assets		$	8,160			$	8,119			$	24			$	1,755			$	1,695			$	31
	Long-term debt due within one year			$	87			$	5			$	75			$	85			$	5			$	70
	Accounts payable			292				292				—				170				170				—
	Accrued expenses			111				108				2				26				22				4
	Mark-to-market derivative liabilities			24				24				—				29				29				—
Unamortized energy contract liabilities			22				22				—				5				5				—
Other current liabilities			25				25				—				5				5				—
	Total current liabilities		561				476				77				320				236				74
	Long-term debt		212				81				120				298				86				195
	Asset retirement obligations		1,763				1,763				—				—				—				—
	Pension obligation(a)		9				9				—				—				—				—
	Unamortized energy contract liabilities		51				51				—				28				28				—
	Other noncurrent liabilities		127				127				—				12				12				—
	Noncurrent liabilities		2,162				2,031				120				338				126				195
	Total liabilities		$	2,723			$	2,507			$	197			$	658			$	362			$	269
___________
(a)	Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—Retirement Benefits for additional details.

Regulatory_Matters_Tables

Regulatory Matters (Tables)	12 Months Ended
	Dec. 31, 2014
Regulated Operations [Abstract]
Regulatory Construction Commitment	ComEd, PECO and BGE will work with PJM to continue to evaluate the scope and timing of any required construction projects. ComEd, PECO and BGE’s estimated commitments are as follows:
		Total			2015			2016			2017			2018		2019
	ComEd	$	335		$	150		$	172		$	5		$	4	$	4
	PECO	100			32			31			25			8		4
	BGE	351			77			104			77			57		36
Schedule of Regulatory Assets	The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of December 31, 2014 and 2013.
	December 31, 2014	Exelon						ComEd						PECO				BGE
		Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
	Regulatory assets
	Pension and other postretirement benefits	$	247		$	3,009		$	—		$	—		$	—	$	—	$	—	$	—
	Deferred income taxes	6			1,536			—			64			—		1,400		6		72
	AMI programs	25			271			10			81			15		62		—		128
	Under-recovered distribution service costs	251			120			251			120			—		—		—		—
	Debt costs	8			49			6			47			2		2		1		8
	Fair value of BGE long-term debt	7			183			—			—			—		—		—		—
	Severance	4			8			—			—			—		—		4		8
	Asset retirement obligations	1			115			1			73			—		26		—		16
	MGP remediation costs	36			221			30			189			6		31		—		1
	Under-recovered uncollectible accounts	—			67			—			67			—		—		—		—
	Renewable energy	20			187			20			187			—		—		—		—
	Energy and transmission programs	37			11			26			7			—		—		11		4
	Deferred storm costs	1			2			—			—			—		—		1		2
	Electric generation-related regulatory asset	10			20			—			—			—		—		10		20
	Rate stabilization deferral	75			85			—			—			—		—		75		85
	Energy efficiency and demand response programs	89			159			—			—			—		—		89		159
	Merger integration costs	2			6			—			—			—		—		2		6
	Conservation voltage reduction	1			1			—			—			—		—		1		1
	Under-recovered electric revenue decoupling	7			—									—		—		7		—
	Other (a)	20			26			5			17			6		8		7		—
	Total regulatory assets	$	847		$	6,076		$	349		$	852		$	29	$	1,529	$	214	$	510
	December 31, 2013	Exelon						ComEd						PECO				BGE
		Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
	Regulatory assets
	Pension and other postretirement benefits	$	221		$	2,794		$	—		$	—		$	—	$	—	$	—	$	—
	Deferred income taxes	10			1,459			2			65			—		1,317		8		77
	AMI programs	5			159			5			35			—		58		—		66
	AMI meter events	—			5			—			—			—		5		—		—
	Under-recovered distribution service costs	178			285			178			285			—		—		—		—
	Debt costs	12			56			9			53			3		3		1		8
	Fair value of BGE long-term debt	—			219			—			—			—		—		—		—
	Fair value of BGE supply contracts	12			—			—			—			—		—		—		—
	Severance	16			12			12			—			—		—		4		12
	Asset retirement obligations	1			102			1			67			—		25		—		10
	MGP remediation costs	40			212			33			178			6		33		1		1
	RTO start-up costs	2			—			2			—			—		—		—		—
	Under-recovered uncollectible accounts	—			48			—			48			—		—		—		—
	Renewable energy	17			176			17			176			—		—		—		—
	Energy and transmission programs	53			9			52			6			—		—		1		3
	Deferred storm costs	3			3			—			—			—		—		3		3
	Electric generation-related regulatory asset	13			30			—			—			—		—		13		30
	Rate stabilization deferral	71			154			—			—			—		—		71		154
	Energy efficiency and demand response programs	73			148			—			—			—		—		73		148
	Merger integration costs	2			9			—			—			—		—		2		9
	Other (a)	31			30			18			20			8		7		4		3
	Total regulatory assets	$	760		$	5,910		$	329		$	933		$	17	$	1,448	$	181	$	524
Schedule of Regulatory Liabilities
	December 31, 2014	Exelon						ComEd						PECO				BGE
		Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
	Regulatory liabilities
	Other postretirement benefits	$	51		$	37		$	—		$	—		$	—	$	—	$	—	$	—
	Nuclear decommissioning	—			2,879			—			2,389			—		490		—		—
	Removal costs	118			1,448			94			1,249			—		—		24		199
	Energy efficiency and demand response programs	25			2			25			—			—		2		—		—
	DLC program costs	—			10			—			—			—		10		—		—
	Energy efficiency phase II	—			32			—			—			—		32		—		—
	Electric distribution tax repairs	8			94			—			—			8		94		—		—
	Gas distribution tax repairs	20			29			—			—			20		29		—		—
	Energy and transmission programs	68			16			3			16			58		—		7		—
	Over-recovered electric universal service fund costs	2			—			—			—			2		—		—		—
	Revenue subject to refund	3			—			3			—			—		—		—		—
	Over-recovered gas revenue decoupling	12			—			—			—			—		—		12		—
	Other	3			3			—			1			2		—		1		1
	Total regulatory liabilities	$	310		$	4,550		$	125		$	3,655		$	90	$	657	$	44	$	200
	December 31, 2013	Exelon						ComEd						PECO				BGE
		Current			Noncurrent			Current			Noncurrent			Current		Noncurrent		Current		Noncurrent
	Regulatory liabilities
	Other postretirement benefits	$	2		$	43		$	—		$	—		$	—	$	—	$	—	$	—
	Nuclear decommissioning	—			2,740			—			2,293			—		447		—		—
	Removal costs	99			1,423			78			1,219			—		—		21		204
	Energy efficiency and demand response programs	53			—			45			—			8		—		—		—
	DLC Program Costs	1			10			—			—			1		10		—		—
	Energy efficiency phase II	—			21			—			—			—		21		—		—
	Electric distribution tax repairs	20			114			—			—			20		114		—		—
	Gas distribution tax repairs	8			37			—			—			8		37
	Energy and transmission programs	78			—			9			—			58		—		11		—
	Over-recovered gas universal service fund costs	8			—			—			—			8		—		—		—
	Revenue subject to refund	38			—			38			—			—		—		—		—
	Over-recovered electric and gas revenue decoupling	16			—			—			—			—		—		16		—
	Other	4			—			—			—			3		—		—		—
	Total regulatory liabilities	$	327		$	4,388		$	170		$	3,512		$	106	$	629	$	48	$	204
	__________________________
	(a)	For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively.
Purchase Of Receivables	The following tables provide information about the purchased receivables of the Registrants as of December 31, 2014 and 2013.
	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
	As of December 31, 2013	Exelon			ComEd			PECO			BGE
	Purchased receivables (a)	$	263		$	105		$	72		$	86
	Allowance for uncollectible accounts (b)	(30		)	(16		)	(7		)	(7		)
	Purchased receivables, net	$	233		$	89		$	65		$	79
	_________________________
	(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.

Mergers_Acquisitions_and_Dispo1

Mergers, Acquisitions and Dispositions (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of Business Acquisitions, by Acquisition	The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the Integrys acquisition by Generation:
	Total consideration transferred		$	332
	Identifiable assets acquired and liabilities assumed
	Working capital assets		$	389
	Mark-to-market derivative assets		185
	Unamortized energy contract assets		115
	Customer relationships		48
	Working capital liabilities		(195		)
	Mark-to-market derivative liabilities		(57		)
	Unamortized energy contract liabilities		(109		)
	Deferred tax liability		(16		)
	Total net identifiable assets, at fair value		$	360
	Bargain purchase gain (after-tax)		$	28
	The following costs were recognized after the closing of the merger and are included in Exelon’s, Generation’s and BGE’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2012:
	Description	Payment		BGE				Generation			Exelon			Statement of
		Period												Operations
														Location
	BGE rate credit of $100 per	Q2 2012		$	113			$	—		$	113		Revenues
	residential customer (a)
	Customer investment fund to invest	2012 to 2014		—				—			114			O&M Expense
	in energy efficiency and low-income energy assistance to BGE customers
	Contribution for renewable energy,	2012 to 2014		—				—			2			O&M Expense
	energy efficiency or related projects in Baltimore
	Charitable contributions at $7 million	2012 to 2021		28				35			70			O&M Expense
	per year for 10 years
	State funding for offshore wind	Q2 2012		—				—			32			O&M Expense
	development projects
	Miscellaneous tax benefits	Q2 2012		(2		)		—			(2		)	Taxes Other Than Income
	Total			$	139			$	35		$	329
	_______________________
	(a)	Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.
Summary of Asset Divestitures
	Station		Net Generation Capacity		Location		Operating Segment		Percent Owned
	Fore River		726		North Weymouth, MA		New England		100%
	West Valley		185		Salt Lake City, UT		Other		100%
	Keystone		714		Shelocta, PA		Mid-Atlantic		41.98%
	Conemaugh		532		New Florence, PA		Mid-Atlantic		31.28%
	Safe Harbor		278		Conestoga, PA		Mid-Atlantic		66.70%
	Quail Run		488		Odessa, TX		ERCOT		100%
	The table below presents the major classes of assets and liabilities held for sale at December 31, 2014.
			December 31, 2014
	Assets:
	Property, plant and equipment, net (a)		$	143
	Inventory		4
	Total assets held for sale		$	147
	Liabilities:
	Accrued expenses		$	1
	Asset retirement obligations		4
	Total liabilities held for sale (b)		$	5
	_____________
	(a) The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8 — Impairment of Long-Lived Assets for further information.
	(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed	The final purchase price allocation of the Merger of Exelon with Constellation and Exelon’s contribution of certain subsidiaries of Constellation to Generation was as follows:
	Preliminary Purchase Price Allocation, excluding amortization		Exelon				Generation
	Current assets		$	4,936			$	3,638
	Property, plant, and equipment		9,342				4,054
	Unamortized energy contracts		3,218				3,218
	Other intangibles, trade name and retail relationships		457				457
	Investment in affiliates		1,942				1,942
	Pension and OPEB regulatory asset		740				—
	Other assets		2,265				1,266
	Total assets		22,900				14,575
	Current liabilities		3,408				2,804
	Unamortized energy contracts		1,722				1,512
	Long-term debt, including current maturities		5,632				2,972
	Noncontrolling interest		90				90
	Deferred credits and other liabilities and preferred securities		4,683				1,933
	Total liabilities, preferred securities and noncontrolling interest		15,535				9,311
	Total purchase price		$	7,365			$	5,264
Business Acquisition, Pro Forma Information	The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that would have been achieved had the merger events taken place on the dates indicated, or the future consolidated results of operations of the combined company.
		Exelon						Generation
		Year Ended December 31,						Year Ended December 31,
	(unaudited)	2012			2011 (a)			2012		2011 (a)
	Total revenues	26,700			30,712			17,013		19,494
	Net income attributable to Exelon	2,092			974			1,205		324
	Basic earnings per share	2.56			1.15			n.a.		n.a.
	Diluted earnings per share	2.55			1.14			n.a.		n.a.
	_____________________
	(a) The amounts above include non-recurring costs directly related to the merger of $236 million for the year ended December 31, 2011.
	(b) The amounts above include non-recurring costs directly related to the merger of $203 million for the year ended December 31, 2011.

Investment_in_Constellation_En1

Investment in Constellation Energy Nuclear Group, LLC (Tables)	12 Months Ended
	Dec. 31, 2014
Business Combinations [Abstract]
Schedule of total equity in earnings of investment in CENG	The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above:
	Fair Values	Exelon and Generation
	Current assets	$	499
	Nuclear decommissioning trust fund	1,955
	Property, plant and equipment	3,017
	Nuclear fuel	482
	Other assets	10
	Total assets	5,963
	Current liabilities	237
	Asset retirement obligation	1,760
	Pension and other employee benefit obligations	281
	Unamortized energy contract liabilities	171
	Other liabilities	114
	Total liabilities	2,563
	Total net assets	$	3,400

Accounts_Receivable_Tables

Accounts Receivable (Tables)	12 Months Ended
	Dec. 31, 2014
Receivables [Abstract]
Schedule Of Accounts Notes Loans And Financing Receivable	Accounts receivable at December 31, 2014 and 2013 included estimated unbilled revenues, representing an estimate for the unbilled amount of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:
	2014	Exelon			Generation				ComEd			PECO				BGE
	Unbilled customer revenues	$	1,381		$	823		(a)	$	204		$	140			$	214
	Allowance for uncollectible	(311		)	(60		)		(84		)	(100		)	(c)	(67		)	(d)
	accounts (b)
	2013	Exelon			Generation				ComEd			PECO				BGE
	Unbilled customer revenues	$	1,151		$	584		(a)	$	201		$	161			$	205
	Allowance for uncollectible	(272		)	(57		)		(62		)	(107		)	(c)	(46		)	(d)
	accounts (b)
	_________________________
	(a)	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.
	(b)	Includes the allowance for uncollectible accounts on customer and other accounts receivable.
	(c)	Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below.
	(d)	At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income.

Property_Plant_and_Equipment_T

Property, Plant, and Equipment (Tables)	12 Months Ended
	Dec. 31, 2014
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014				2013
		Service Life
		(years)
	Asset Category
	Electric—transmission and distribution	May-80		$	18,884			$	17,334
	Construction work in progress	N/A		276				456
	Other property, plant and equipment (a)	39-50		65				60
	Total property, plant and equipment			19,225				17,850
	Less: accumulated depreciation			3,432				3,184
	Property, plant and equipment, net			$	15,793			$	14,666
	_________________________
	(a)	Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively.
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014				2013
		Service Life
		(years)
	Asset Category
	Electric—transmission and distribution	May-90		$	30,157			$	28,123
	Electric—generation	Jan-56		22,911				20,420
	Gas—transportation and distribution	May-90		3,505				3,296
	Common—electric and gas	May-50		1,169				1,101
	Nuclear fuel (a)	8-Jan		5,947				5,196
	Construction work in progress	N/A		2,167				1,890
	Other property, plant and equipment (b)	May-50		973				1,017
	Total property, plant and equipment			66,829				61,043
	Less: accumulated depreciation (c)			14,742				13,713
	Property, plant and equipment, net			$	52,087			$	47,330
	_________________________
	(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.
	(b)	Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation.
	(c)	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014					2013
		Service Life
		(years)
	Asset Category
	Electric—generation	Jan-56		$	22,911		19,004,000,000		$	20,420
	Nuclear fuel (a)	8-Jan		5,947			4,815,000,000		5,196
	Construction work in progress	N/A		1,404			1,352,000,000		1,129
	Other property, plant and equipment (b)	Jun-31		295			374,000,000		400
	Total property, plant and equipment			30,557					27,145
	Less: accumulated depreciation (c)			7,612					7,034
	Property, plant and equipment, net			$	22,945				$	20,111
	_________________________
	(a)	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.
	(b)	Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities.
	(c)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
		Average		2014				2013
		Service Life
		(years)
	Asset Category
	Electric—transmission and distribution	May-90		$	6,339			$	6,100
	Gas—distribution	May-90		1,761				1,660
	Common—electric and gas	May-40		623				578
	Construction work in progress	N/A		317				196
	Other property, plant and equipment (a)	20		32				32
	Total property, plant and equipment			9,072				8,566
	Less: accumulated depreciation			2,868				2,702
	Property, plant and equipment, net			$	6,204			$	5,864
	_______________________
	(a)	Represents land held for future use and non utility property.
	The following table presents a summary of property, plant and equipment by asset category as of December 31, 2014 and 2013:
	Average		2014				2013
	Service Life
	(years)
Asset Category
Electric—transmission and distribution	May-65		$	6,886			$	6,669
Gas—transportation and distribution	May-70		2,039				1,932
Common—electric and gas	May-50		618				600
Construction work in progress	N/A		154				101
Other property, plant and equipment (a)	50		21				17
Total property, plant and equipment			9,718				9,319
Less: accumulated depreciation			2,917				2,935
Property, plant and equipment, net			$	6,801			$	6,384
_________________________
(a)	Represents land held for future use and non utility property.
Property Plant And Equipment Average Service Life Percentage By Asset Category Table	The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
	Average Service Life Percentage by Asset Category	2014			2013			2012
	Electric—transmission and distribution	2.93	%		2.91	%		2.76	%
	Electric—generation	3.5	%		3.35	%		3.15	%
	Gas	2.13	%		2.06	%		2.03	%
	Common—electric and gas	7.32	%		7.53	%		7.61	%
	The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
	Average Service Life Percentage by Asset Category	2014			2013			2012
	Electric—transmission and distribution	2.55	%		2.73	%		2.51	%
	Gas	1.84	%		1.79	%		1.77	%
	Common—electric and gas	5.16	%		6.65	%		7.54	%
	Average Service Life Percentage by Asset Category	2014			2013			2012
	Electric—transmission and distribution	2.96	%		2.91	%		2.92	%
	Gas	2.47	%		2.36	%		2.33	%
	Common—electric and gas	9.49	%		8.45	%		7.68	%

Recovered_Sheet1

Impairment of Long-Lived assets (Tables)	12 Months Ended
	Dec. 31, 2014
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Schedule of Capital Leased Assets	At December 31, 2014 and 2013, the components of the net investment in long-term leases were as follows:
		December 31, 2014		December 31, 2013
	Estimated residual value of leased assets	$	685	$	1,465
	Less: unearned income	324		767
	Net investment in long-term leases	$	361	$	698

Jointly_Owned_Electric_Utility1

Jointly Owned Electric Utility Plant (Tables)	12 Months Ended
	Dec. 31, 2014
Public Utilities, Property, Plant and Equipment [Abstract]
Schedule of Jointly Owned Utility Plants	Exelon, Generation, PECO and BGE’s undivided ownership interests in jointly owned electric plants and transmission facilities at December 31, 2014 and 2013 were as follows:
		Nuclear generation												Fossil fuel generation							Transmission					Other
		Quad Cities			Peach			Salem (a)			Nine Mile Point Unit 2(g)			Keystone		Conemaugh		Wyman			PA (b)		DE/NJ (c)			Other (d)
					Bottom
														(f)		(f)
	Operator	Generation			Generation			PSEG			Generation			GenOn		GenOn		FP&L			First		PSEG
								Nuclear													Energy
	Ownership interest	75		%	50		%	42.59		%	82		%	—		—		5.89		%	Various		42.55		%	44.24		%
	Exelon’s share at December 31, 2014:
	Plant (e)	$	995		$	1,095		$	531		$	676		$	—	$	—	$	3		$	14	$	64		$	2
	Accumulated	266			343			150			14			—		—		3			7		34			1
	depreciation (e)
	Construction work	15			133			29			48			—		—		—			—		—			—
	in progress
	Exelon’s share at December 31, 2013:
	Plant (e)	$	941		$	883		$	501		$	—		$	725	$	399	$	3		$	14	$	64		$	2
	Accumulated depreciation (e)	226			326			134			—			268		220		3			7		34			1
	Construction work	27			174			24			—			6		121		—			—		—			—
	in progress
	________________________
	(a)	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2014 and 2013.
	(b)	PECO and BGE own a 22% and 7% share, respectively, in 127 miles of 500kV lines located in Pennsylvania; PECO and BGE also own a 20.7% and 10.56% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the 500kV lines including, but not limited to, the lines noted above.
	(c)	PECO owns a 42.55% share in 131 miles of 500kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.
	(d)	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.
	(e)	Excludes asset retirement costs.

Intangible_Assets_Tables

Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule Of Goodwill	Exelon’s and ComEd’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31, 2014 and 2013 were as follows:
		ComEd												Generation								Exelon
		Gross				Accumulated				Carrying				Gross				Carrying				Gross				Accumulated				Carrying
		Amount (a)				Impairment				Amount				Amount				Amount				Amount				Impairment				Amount
						Losses																				Losses
	Balance, January 1, 2013	$	4,608			$	1,983			$	2,625			$	—			$	—			$	4,608			$	1,983			$	2,625
	Goodwill from business combination	—				—				—				47				47				47				—				47
	Balance, December 31, 2014	$	4,608			$	1,983			$	2,625			$	47			$	47			$	4,655			$	1,983			$	2,672
	_______________________
	(a)	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.
Schedule of Finite-Lived Intangible Assets	Exelon’s, Generation’s and ComEd’s other intangible assets and liabilities, included in Unamortized energy contract assets and Other long-term assets and liabilities in their Consolidated Balance Sheets, consisted of the following as of December 31, 2014:
		Weighted													Estimated amortization expense
		Average
		Amortization
		Years (h)	Gross				Accumulated				Net				2015				2016				2017				2018				2019
							Amortization
	Exelon and Generation
	Unamortized Energy Contracts (a)
	Exelon Wind (b)	18	$	224			$	(55	)		$	169			$	14			$	14			$	14			$	14			$	14
	Antelope Valley (c)	25	190				(12		)		178				8				8				8				8				8
	Constellation (d)	1.5	1,499				(1,451		)		48				19				(31		)		(21		)		11				8
	CENG (e)	1.7	(97		)		29				(68		)		(20		)		(11		)		(15		)		(18		)		(15		)
	Integrys (d)	2.4	6				(5		)		1				(8		)		6				1				1				—
	Customer Relationships
	Constellation (d)	12.4	214				(58		)		156				18				18				18				18				17
	Integrys (d)	10	48				(1		)		47				5				5				5				5				5
	Trade Names
	Constellation (d)	10	243				(79		)		164				23				23				23				23				23
	ComEd
	Chicago settlement—1999 agreement (f)	21.8	100				(79		)		21				3				3				4				4				4
	Chicago settlement—2003 agreement (g)	17.9	62				(40		)		22				4				4				3				3				3
	Total intangible assets		$	2,489			$	(1,751	)		$	738			$	66			$	39			$	40			$	69			$	67
	_________________________
	(a)	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.
	(b)	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.
	(c)	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.
	(d)	See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions.
	(e)	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.
	(f)	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.
	(g)	In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the remaining term of the City of Chicago franchise agreement, which ends in 2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago’s behalf. Under the terms of the agreement with Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under the 1999 fossil sale agreement with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in Other deferred credits and other liabilities, and other long-term liabilities on Exelon's and ComEd's Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an offset to amortization expense over the remaining term of the franchise agreement.
	(h)	Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.
Schedule Of Finite-Lived Intangible Assets Amortization Expense	The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2014, 2013 and 2012:
	For the Year Ended December 31,	Exelon (a)				Generation (a)				ComEd
	2014	$	179			$	179			$	7
	2013	478				550				7
	2012	1,150				1,145				7

Fair_Value_of_Financial_Assets1

Fair Value of Financial Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis	The following tables present assets and liabilities measured and recorded at fair value on the Utilities' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013:
		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	—				(8		)		—				(8		)		—				(15		)		—			(15		)		—				(5		)	—		(5		)
	obligation
	Mark-to-market derivative	—				—				(207		)		(207		)		—				—				—			—				—				—			—		—
	liabilities (b)
	Total liabilities	—				(8		)		(207		)		(215		)		—				(15		)		—			(15		)		—				(5		)	—		(5		)
	Total net assets (liabilities)	$	25			$	(8	)		$	(207	)		$	(190	)		$	21			$	(15	)		$	—		$	6			$	108			$	(5	)	$	—	$	103
		ComEd																PECO															BGE
	As of December 31, 2013	Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3			Total				Level 1				Level 2			Level 3		Total
	Assets
	Cash equivalents	$	—			$	—			$	—			$	—			$	175			$	—			$	—		$	175			$	31			$	—		$	—	$	31
	Rabbi trust investments in Mutual funds (a)	5				—				—				5				9				—				—			9				6				—			—		6
	Total assets	5				—				—				5				184				—				—			184				37				—			—		37
	Liabilities
	Deferred compensation	—				(8		)		—				(8		)		—				(17		)		—			(17		)		—				(6		)	—		(6		)
	obligation
	Mark-to-market derivative	—				—				(193		)		(193		)		—				—				—			—				—				—			—		—
	liabilities (b)
	Total liabilities	—				(8		)		(193		)		(201		)		—				(17		)		—			(17		)		—				(6		)	—		(6		)
	Total net assets (liabilities)	$	5			$	(8	)		$	(193	)		$	(196	)		$	184			$	(17	)		$	—		$	167			$	37			$	(6	)	$	—	$	31
	_________________________
	(a)	At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013.
	(b)	The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
	The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2014 and 2013:
	Exelon
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	463			$	3			$	448			$	12			$	463			$	344			$	344
	Long-term debt (including amounts due within one year)	21,164				1,208				20,417				1,311				22,936				19,132				19,751
	Long-term debt to financing trusts	648				—				—				648				648				648				631
	SNF obligation	1,021				—				833				—				833				1,021				790
	Generation
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	36			$	—			$	24			$	12			$	36			$	22			$	22
	Long-term debt (including amounts due within one year)	8,266				—				7,511				1,311				8,822				7,729				7,648
	SNF obligation	1,021				—				833				—				833				1,021				790
	ComEd
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	304			$	—			$	304			$	—			$	304			$	184			$	184
	Long-term debt (including amounts due within one year)	5,958				—				6,788				—				6,788				5,675				6,255
	Long-term debt to financing trust	206				—				—				213				213				206				202
	PECO
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Long-term debt (including amounts due within one year)	$	2,246			$	—			$	2,537			$	—			$	2,537			$	2,197			$	2,358
	Long-term debt to financing trusts	184				—				—				199				199				184				180
	BGE
		31-Dec-14																				31-Dec-13
		Carrying				Fair Value																Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total				Amount
	Short-term liabilities	$	123			$	3			$	120			$	—			$	123			$	138			$	138
Long-term debt (including amounts due within one year)	1,942				—				2,178				—				2,178				2,011				2,148
Long-term debt to financing trusts	258				—				—				236				236				258				249
Fair value of financial liabilities recorded at the carrying amount	The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2014 and 2013:
		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
	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 securities	—					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 funds 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
	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
Assets and liabilities measured and recorded at fair value on recurring basis
		Generation																Exelon
	As of December 31, 2013	Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3			Total
	Assets
	Cash equivalents (a)	$	1,006			$	—			$	—			$	1,006			$	1,230			$	—			$	—		$	1,230
	Nuclear decommissioning trust fund investments
	Cash equivalents	459				—				—				459				459				—				—			459
	Equities
	Domestic	1,642				2,271				—				3,913				1,642				2,271				—			3,913
	Foreign	249				—				—				249				249				—				—			249
	Equity funds subtotal	1,891				2,271				—				4,162				1,891				2,271				—			4,162
	Fixed income
	Corporate debt securities	—				1,753				31				1,784				—				1,753				31			1,784
	U.S. Treasury and agencies	882				—				—				882				882				—				—			882
	Foreign governments	—				87				—				87				—				87				—			87
	State and municipal debt	—				294				—				294				—				294				—			294
	Other	—				75				—				75				—				75				—			75
	Fixed income subtotal	882				2,209				31				3,122				882				2,209				31			3,122
	Middle market lending	—				—				314				314				—				—				314			314
	Private equity	—				—				5				5				—				—				5			5
	Other	—				14				—				14				—				14				—			14
	Nuclear decommissioning trust funds subtotal (b)	3,232				4,494				350				8,076				3,232				4,494				350			8,076
	Pledged assets for Zion Station
	decommissioning
	Cash equivalents	—				26				—				26				—				26				—			26
	Equities	16				—				—				16				16				—				—			16
	Fixed income
	U.S. Treasury and agencies	45				4				—				49				45				4				—			49
	Corporate debt	—				227				—				227				—				227				—			227
	State and municipal debt	—				20				—				20				—				20				—			20
	Fixed income subtotal	45				251				—				296				45				251				—			296
	Middle market lending	—				—				112				112				—				—				112			112
	Other	—				1				—				1				—				1				—			1
	Pledged assets for Zion Station	61				278				112				451				61				278				112			451
	decommissioning subtotal (c)
	Rabbi trust investments (d)
	Cash equivalents	—				—				—				—				2				—				—			2
	Mutual funds (e)	13				—				—				13				54				—				—			54
	Rabbi trust investments subtotal	13				—				—				13				56				—				—			56
	Commodity derivative assets													—															—
	Economic hedges	493				2,582				885				3,960				493				2,582				885			3,960
	Proprietary trading	324				1,315				122				1,761				324				1,315				122			1,761
	Effect of netting and allocation of collateral (f)	(863		)		(3,131		)		(430		)		(4,424		)		(863		)		(3,131		)		(430		)	(4,424		)
	Commodity derivative assets subtotal	(46		)		766				577				1,297				(46		)		766				577			1,297
	Interest rate and foreign currency derivative	30				32				—				62				30				39				—			69
	assets
	Effect of netting and allocation of collateral	(30		)		(2		)		—				(32		)		(30		)		(2		)		—			(32		)
	Interest rate and foreign currency derivative	—				30				—				30				—				37				—			37
	assets subtotal
	Other investments	—				—				15				15				—				—				15			15
	Total assets	4,266				5,568				1,054				10,888				4,533				5,575				1,054			11,162
	Liabilities
	Commodity derivative liabilities
	Economic hedges	(540		)		(1,890		)		(397		)		(2,827		)		(540		)		(1,890		)		(590		)	(3,020		)
	Proprietary trading	(328		)		(1,256		)		(119		)		(1,703		)		(328		)		(1,256		)		(119		)	(1,703		)
	Effect of netting and allocation of collateral (f)	869				3,007				404				4,280				869				3,007				404			4,280
	Commodity derivative liabilities subtotal	1				(139		)		(112		)		(250		)		1				(139		)		(305		)	(443		)
	Interest rate and foreign currency derivative	(31		)		(13		)		—				(44		)		(31		)		(17		)		—			(48		)
	liabilities
	Effect of netting and allocation of collateral	31				1				—				32				31				1				—			32
	Interest rate and foreign currency derivative	—				(12		)		—				(12		)		—				(16		)		—			(16		)
	liabilities subtotal
	Deferred compensation obligation	—				(29		)		—				(29		)		—				(114		)		—			(114		)
	Total liabilities	1				(180		)		(112		)		(291		)		1				(269		)		(305		)	(573		)
Total net assets	$	4,267			$	5,388			$	942			$	10,597			$	4,534			$	5,306			$	749		$	10,589
_________________________
(a)	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
(b)	Excludes net liabilities of $5 million at both December 31, 2014 and 2013. 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 $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
(d)	Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation.
(e)	The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013.
(f)	Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/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. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis
		Generation												Exelon
		Operating				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 year ended December 31, 2013	$	(158	)		$	107			$	2			$	(152	)		$	108			$	2
	Change in the unrealized gains relating to assets and liabilities held for the year ended December 31, 2013	$	30			$	126			$	1			$	40			$	127			$	1
	_________________________
	(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.
	The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2014 and 2013:
		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 year ended December 31, 2014	$	614			$	(88	)		$	6			$	614			$	(88	)		$	6
	Change in the unrealized gains (losses) relating to assets and liabilities held for the year ended December 31, 2014	$	663			$	(23	)		$	4			$	663			$	(23	)		$	4
	The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the year ended December 31, 2014 and 2013:
		Generation																				ComEd							Exelon
	For The Year Ended December 31, 2014	Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Other- ComEd (b)				Eliminated in Consolidation			Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
	Balance as of January 1, 2014	$	350			$	112			$	465			$	15			$	942			$	(193	)		$	—		$	749
	Total realized / unrealized gains (losses)
	Included in net income	6				—				526			(a)	—				532				—				—			532
	Included in noncurrent payables to affiliates	14				—				—				—				14				—				(14		)	—
	Included in payable for Zion Station decommissioning	—				2				—				—				2				—				—			2
	Included in regulatory assets/liabilities	—				—				—				—				—				(14		)		14			—
	Change in collateral	—				—				198				—				198				—				—			198
	Purchases, sales, issuances and settlements
	Purchases	400				120				76			(c)	2				598				—				—			598
	Sales	(15		)		(50		)		(7		)		(8		)		(80		)		—				—			(80		)
	Settlements	(64		)		—				—				—				(64		)		—				—			(64		)
	Transfers into Level 3	—				—				(7		)		—				(7		)		—				—			(7		)
	Transfers out of Level 3	—				—				(201		)		(6		)		(207		)		—				—			(207		)
	Balance as of December 31, 2014	$	691			$	184			$	1,050			$	3			$	1,928			$	(207	)		$	—		$	1,721
	The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2014	$	4			$	—			$	640			$	—			$	644			$	—			$	—		$	644
		Generation																				ComEd							Exelon
	For The Year Ended December 31, 2013	Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Other- ComEd (b)(f)				Eliminated in Consolidation			Total
		Decommissioning				for Zion Station				Derivatives (d)				Investments
		Trust Fund				Decommissioning
		Investments
	Balance as of January 1, 2013	$	183			$	89			$	660			$	17			$	949			$	(293	)		$	—		$	656
	Total realized / unrealized gains (losses)																												—
	Included in net income	2				—				(51		)	(a)	—				(49		)		—				7			(42		)
	Included in other	—				—				(219		)		2				(217		)		—				219			2
	comprehensive income
	Included in noncurrent payables to affiliates	8				—				—				—				8				—				(8		)	—
	Included in payable for Zion Station decommissioning	—				—				—				—				—				—				—			—
	Included in regulatory assets/liabilities	—				—				—				—				—				100				(218		)	(118		)
	Change in collateral	—				—				7				—				7				—				—			7
	Purchases, sales, issuances and settlements
	Purchases	203				62				28				4				297				—				—			297
	Sales	(28		)		(39		)		(11		)		(8		)		(86		)		—				—			(86		)
	Settlements	(18		)		—				—				—				(18		)		—				—			(18		)
	Transfers into Level 3	—				—				86			(e)	1				87				—				—			87
	Transfers out of Level 3	—				—				(35		)		(1		)		(36		)		—				—			(36		)
	Balance as of December 31, 2013	$	350			$	112			$	465			$	15			$	942			$	(193	)		$	—		$	749
	The amount of total gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held as of December 31, 2013	$	1			$	—			$	156			$	—			$	157			$	—			$	—		$	168
	_________________________
	(a)	Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively.
	(b)	Includes $13 million and $133 million of decreases in fair value and $1 million and $(7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively.
	(c)	Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition.
	(d)	Includes $11 million of decreases in fair value and realized gains due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
(e)	Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations.
(f)	Includes $11 million of increases in fair value and realized losses due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique	The table below discloses the significant inputs to the forward curve used to value these positions.
	Type of trade	Fair Value at December 31,2014				Valuation		Unobservable		Range
						Technique		Input
	Mark-to-market derivatives—Economic hedges (Generation) (a)(c)	$	893			Discounted		Forward power price		$15	-	$120	(d)
						Cash Flow
								Forward gas price		$1.52	-	$14.02	(d)
						Option Model		Volatility percentage		8%	-	257%
	Mark-to-market derivatives—Proprietary trading (Generation) (a)(c)	$	(15	)		Discounted		Forward power price		$15	-	$117	(d)
						Cash Flow
	Mark-to-market derivatives	$	(207	)		Discounted		Forward heat rate (b)		8x	-	9x
	(ComEd)					Cash Flow
								Marketability reserve		3.50%	-	8%
								Renewable factor		86%	-	126%
	_________________________
	(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
	(b)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
	(c)	The fair values do not include cash collateral 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.
	Type of trade	Fair Value at December 31, 2013				Valuation		Unobservable		Range
						Technique		Input
	Mark-to-market derivatives—Economic hedges (Generation) (a)(c)	$	488			Discounted		Forward power price		$8	-	$176	(d)
						Cash Flow
								Forward gas price		$2.98	-	$16.63	(d)
						Option Model		Volatility percentage		15%	-	142%
	Mark-to-market derivatives—	$	3			Discounted		Forward power price		$10	-	$176	(d)
	Proprietary trading (Generation) (a)(c)					Cash Flow
	Mark-to-market derivatives	$	(193	)		Discounted		Forward heat rate (b)		8x	-	9x
	(ComEd)					Cash Flow
								Marketability reserve		3.50%	-	8%
								Renewable factor		84%	-	128%
	__________________________
	(a)	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
	(b)	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
	(c)	The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013
	(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 $100 and $5.70, respectively.

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of the derivative fair value	The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2014:
		Generation																ComEd				Exelon
	Derivatives	Economic				Proprietary				Collateral				Subtotal (b)				Economic				Total
		Hedges				Trading				and Netting (a)								Hedges  (c)				Derivatives
	Mark-to-market	$	4,992			$	456			$	(4,184	)		$	1,264			$	—			$	1,264
	derivative assets (current assets)
	Mark-to-market	1,821				56				(1,112		)		765				—				765
	derivative assets (noncurrent assets)
	Total mark-to-market	6,813				512				(5,296		)		2,029				—				2,029
	derivative assets
	Mark-to-market	(4,947		)		(468		)		5,200				(215		)		(20		)		(235		)
	derivative liabilities (current liabilities)
	Mark-to-market	(1,540		)		(64		)		1,502				(102		)		(187		)		(289		)
	derivative liabilities (noncurrent liabilities)
	Total mark-to-market	(6,487		)		(532		)		6,702				(317		)		(207		)		(524		)
	derivative liabilities
	Total mark-to-market	$	326			$	(20	)		$	1,406			$	1,712			$	(207	)		$	1,505
	derivative 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 $(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.
	The following table provides a summary of the derivative fair value balances recorded by the Registrants as of December 31, 2013:
		Generation																ComEd				Exelon
	Derivatives	Economic				Proprietary				Collateral				Subtotal (b)				Economic				Total
		Hedges				Trading				and								Hedges (c)				Derivatives
										Netting  (a)
	Mark-to-market	$	2,616			$	1,476			$	(3,364	)		$	728			$	—			$	728
	derivative assets (current assets)
	Mark-to-market	1,344				285				(1,060		)		569				—				569
	derivative assets (noncurrent assets)
	Total mark-to-market	3,960				1,761				(4,424		)		1,297				—				1,297
	derivative assets
	Mark-to-market	(2,023		)		(1,410		)		3,292				(141		)		(17		)		(158		)
	derivative liabilities (current liabilities)
	Mark-to-market	(804		)		(293		)		988				(109		)		(176		)		(285		)
	derivative liabilities (noncurrent liabilities)
	Total mark-to-market	(2,827		)		(1,703		)		4,280				(250		)		(193		)		(443		)
	derivative liabilities
	Total mark-to-market	$	1,133			$	58			$	(144	)		$	1,047			$	(193	)		$	854
	derivative 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 $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.
	(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 exchange hedges as of December 31, 2014:
		Generation																				Other													Exelon
	Description	Derivatives				Economic				Proprietary				Collateral				Subtotal				Derivatives				Economic			Collateral			Subtotal			Total
		Designated as				Hedges				Trading  (a)				and Netting (b)								Designated as				Hedges			and Netting (b)
		Hedging																				Hedging
		Instruments																				Instruments
	Mark-to-market derivative	$	7			$	7			$	20			$	(22	)		$	12			$	3			$	—		$	—		$	3		$	15
	assets (current assets)
	Mark-to-market derivative	1				5				7				(7		)		6				20				1			(19		)	2			8
	assets (noncurrent assets)
	Total mark-to-market	8				12				27				(29		)		18				23				1			(19		)	5			23
	derivative assets
	Mark-to-market derivative	(8		)		(2		)		(14		)		25				1				—				—			—			—			1
	liabilities (current liabilities)
	Mark-to-market derivative	(4		)		—				(9		)		10				(3		)		(29		)		(101		)	19			(111		)	(114		)
	liabilities (noncurrent liabilities)
	Total mark-to-market	(12		)		(2		)		(23		)		35				(2		)		(29		)		(101		)	19			(111		)	(113		)
	derivative 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 between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
(b)	Represents the netting of fair value balances with the same counterparty and any associated cash collateral.
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2013:
	Generation																				Other				Exelon
Description	Derivatives				Economic				Proprietary				Collateral				Subtotal				Derivatives				Total
	Designated as				Hedges				Trading (a)				and Netting (b)								Designated as
	Hedging																				Hedging
	Instruments																				Instruments
Mark-to-market derivative	$	—			$	3			$	15			$	(19	)		$	(1	)		$	—			$	(1	)
assets (current assets)
Mark-to-market derivative	26				3				15				(13		)		31				7				38
assets (noncurrent assets)
Total mark-to-market	26				6				30				(32		)		30				7				37
derivative assets
Mark-to-market derivative	(1		)		(1		)		(18		)		19				(1		)		—				(1		)
liabilities (current liabilities)
Mark-to-market derivative	(10		)		(1		)		(13		)		13				(11		)		(4		)		(15		)
liabilities (noncurrent liabilities)
Total mark-to-market	(11		)		(2		)		(31		)		32				(12		)		(4		)		(16		)
derivative liabilities
Total mark-to-market	$	15			$	4			$	(1	)		$	—			$	18			$	3			$	21
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 between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
(b)	Represents the netting of fair value balances with the same counterparty and any associated cash collateral.
Gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense	Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
				Year Ended December 31,
		Income Statement Location		2014				2013				2012				2014				2013				2012
				Gain (Loss) on Swaps												Gain (Loss) on Borrowings
	Generation	Interest expense  (a)		$	(16	)		$	(15	)		$	(6	)		$	2			$	(6	)		$	—
	Exelon	Interest expense		$	3			$	(24	)		$	(9	)		$	15			$	(3	)		$	(1	)
	______________________
	(a)	For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively.
The activity of accumulated OCI related to cash flow hedges	The tables below provide the activity of Accumulated OCI related to cash flow hedges for the years ended December 31, 2014 and 2013, 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.
		Income Statement		Total Cash Flow Hedge OCI  Activity,
		Location		Net of Income Tax
				Generation				Exelon
				Energy-Related				Total Cash Flow
				Hedges				Hedges
	Accumulated OCI derivative gain at January 1, 2013			$	532		(a)(d)	$	368
	Effective portion of changes in fair value			—				29			(e)
	Reclassifications from accumulated OCI to net	Operating Revenues		(413		)	(c)(b)	(277		)
	income
	Ineffective portion recognized in income	Operating Revenues		—				—
	Accumulated OCI derivative gain at December 31, 2013			119			(d)	120
	Effective portion of changes in fair value			—				(31		)	(e)
	Reclassifications from accumulated OCI to net income	Operating Revenues		(117		)	(b)	(117		)
	Accumulated OCI derivative gain at December 31, 2014			$	2		(d)	$	(28	)
	_______________________
	(a)	Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd for the years ended December 31, 2012.
	(b)	Amount is net of related income tax expense of $78 million and $270 million for the years ended December 31, 2014 and 2013, respectively.
	(c)	Includes $133 million of losses, net of taxes, reclassified from Accumulated OCI to recognize gains in net income related to settlements of the five-year financial swap contract with ComEd for the year ended December 31, 2013.
	(d)	Excludes $20 million and $5 million,of losses, net of taxes, related to interest rate swaps and treasury rate locks for the years ended December 31, 2014 and 2013, respectively.
	(e)	Includes $15 million and $15 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks at Generation for the years ended December 31, 2014 and 2013, respectively.
Change in fair value and reclassification of derivative contracts	In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.
		Generation																Intercompany				Exelon Corporate				Exelon
																		Eliminations
	Year Ended December 31, 2014	Operating				Purchased				Interest Expense				Total				Operating				Interest Expense				Total
		Revenues				Power												Revenues  (a)
						and Fuel
	Change in fair value of commodity positions	$	(413	)		$	(194	)		$	—			$	(607	)		$	—			$	—			$	(607	)
	Reclassification to realized at settlement of	231				(223		)		—				8				—				—				8
	commodity positions
	Net commodity mark-to-market gains (losses)	(182		)		(417		)		—				(599		)		—				—				(599		)
	Change in fair value of treasury positions	10				—				(2		)		8				—				(100		)		(92		)
	Reclassification to realized at settlement of	(2		)		—				—				(2		)		—				—				(2		)
	treasury positions
	Net treasury mark-to market gains	8				—				(2		)		6				—				(100		)		(94		)
	(losses)
	Net mark-to market gains (losses)	$	(174	)		$	(417	)		$	(2	)		$	(593	)		$	—			$	(100	)		$	(693	)
		Generation																Intercompany				Exelon Corporate				Exelon
																		Eliminations
	Year Ended December 31, 2013	Operating				Purchased				Interest Expense				Total				Operating				Interest Expense				Total
		Revenues				Power												Revenues  (a)
						and Fuel
	Change in fair value of commodity positions	$	286			$	180			$	—			$	466			$	(6	)		$	—			$	460
	Reclassification to realized at settlement of	(64		)		104				—				40				13				—				53
	commodity positions
	Net commodity mark-to-market gains	222				284				—				506				7				—				513
	(losses)
	Change in fair value of treasury positions	(1		)		—				(4		)		(5		)		—				—				(5		)
	Reclassification to realized at settlement of	(1		)		—				—				(1		)		—				—				(1		)
	treasury positions
	Net treasury mark-to market gains	(2		)		—				(4		)		(6		)		—				—				(6		)
	(losses)
	Net mark-to market gains (losses)	$	220			$	284			$	(4	)		$	500			$	7			$	—			$	507
		Generation																Intercompany				Exelon Corporate				Exelon
																		Eliminations
	Year Ended December 31, 2012	Operating				Purchased				Interest Expense				Total				Operating				Interest Expense				Total
		Revenues				Power												Revenues  (a)
						and Fuel
	Change in fair value of commodity positions	$	(362	)		$	215			$	—			$	(147	)		$	(94	)		$	—			$	(241	)
	Reclassification to realized at settlement of	432				238				—				670				101				—				771
	commodity positions
	Net commodity mark-to-market gains	70				453				—				523				7				—				530
	(losses)
	Change in fair value of treasury positions	—				—				6				6				—				—				6
	Reclassification to realized at settlement of	(3		)		—				—				(3		)		—				—				(3		)
	treasury positions
	Net treasury mark-to market gains	(3		)		—				6				3				—				—				3
	(losses)
	Net mark-to market gains (losses)	$	67			$	453			$	6			$	526			$	7			$	—			$	533
	________________________
	(a)	Prior to the Constellation merger, the five-year financial swap contract between Generation and ComEd was de-designated. As a result, all prospective changes in fair value were recorded to operating revenues and eliminated in consolidation.
	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		For the Years Ended
		Statement		December 31,
				2014				2013				2012
	Change in fair value of commodity positions	Operating Revenues		$	(1	)		$	(22	)		$	(13	)
	Reclassification to realized at settlement of commodity positions	Operating Revenues		(29		)		(15		)		108
	Net commodity mark-to-market gains (losses)	Operating Revenues		(30		)		(37		)		95
	Change in fair value of treasury positions	Operating Revenues		1				1				1
	Reclassification to realized at settlement of treasury positions	Operating Revenues		3				(3		)		—
	Net treasury mark-to market gains (losses)	Operating Revenues		4				(2		)		1
	Net mark-to market gains (losses)	Operating Revenues		$	(26	)		$	(39	)		$	96
Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements	The figures in the tables below exclude credit risk exposure from individual retail counterparties, Nuclear fuel procurement contracts and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 7A.—QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $43 million, $29 million and $40 million, respectively.
	Rating as of December 31, 2014	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	$	1,629			$	62			$	1,567			1			$	452
	Non-investment grade	49				19				30				—			—
	No external ratings
	Internally rated—investment grade	479				—				479				—			—
	Internally rated—non-investment	60				4				56				—			—
	grade
	Total	$	2,217			$	85			$	2,132			1			$	452
	Net Credit Exposure by Type of Counterparty	31-Dec-14
	Financial institutions	$	295
	Investor-owned utilities, marketers, power producers	958
	Energy cooperatives and municipalities	862
	Other	17
	Total	$	2,132
	______________________
	(a)	As of December 31, 2014, credit collateral held from counterparties where Generation had credit exposure included $69 million of cash and $16 million of letters of credit.
	The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
		For the Years Ended December 31,
	Credit-Risk Related Contingent Feature	2014				2013
	Gross Fair Value of Derivative Contracts Containing this Feature (a)	$	(1,433	)		$	(1,056	)
	Offsetting Fair Value of In-the-Money Contracts Under Master Netting	1,140				846
	Arrangements (b)
	Net Fair Value of Derivative Contracts Containing This Feature (c)	$	(293	)		$	(210	)
	__________________________
	(a)	Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.
	(b)	Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
	(c)	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Debt_and_Credit_Agreements_Tab

Debt and Credit Agreements (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Short-term Debt	The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, and BGE during 2014, 2013 and 2012. PECO did not have any short-term borrowings during 2014, 2013 or 2012.
	Exelon
		2014				2013			2012
	Average borrowings	$	571			$	254		$	199
	Maximum borrowings outstanding	1,164				682			505
	Average interest rates, computed on a daily basis	0.32		%		0.37		%	0.48		%
	Average interest rates, at December 31	0.53		%		0.35		%	n.a.
	Generation
		2014				2013			2012
	Average borrowings	$	93			$	42		$	4
	Maximum borrowings outstanding	552				291			165
	Average interest rates, computed on a daily basis	0.32		%		0.32		%	0.45		%
	Average interest rates, at December 31	n.a.				n.a.			n.a.
	ComEd
		2014				2013			2012
	Average borrowings	$	415			$	203		$	110
	Maximum borrowings outstanding	597				446			366
	Average interest rates, computed on a daily basis	0.33		%		0.4		%	0.5		%
	Average interest rates, at December 31	0.5		%		0.37		%	n.a.
	BGE
		2014				2013			2012
	Average borrowings	$	64			$	35		$	6
	Maximum borrowings outstanding	180				135			76
	Average interest rates, computed on a daily basis	0.29		%		0.31		%	0.43		%
	Average interest rates, computed at December 31	0.61		%		0.31		%	n.a.
	Exelon, Generation, ComEd, PECO and BGE had the following amounts of commercial paper borrowings at December 31, 2014 and 2013:
		Maximum							Outstanding								Average Interest Rate on
		Program Size at							Commercial								Commercial Paper Borrowings for
		December 31,							Paper at								the Year Ended December 31,
									December 31,
	Commercial Paper Issuer	2014 (a)(b)				2013 (a)(b)			2014				2013				2014		2013
	Exelon Corporate	$	500			$	500		$	—			$	—			—	%	0.27	%
	Generation	5,600				5,600			—				—				0.32	%	0.32	%
	ComEd	1,000				1,000			304				184				0.33	%	0.4	%
	PECO	600				600			—				—				n.a.		n.a.
	BGE	600				600			120				135				0.29	%	0.31	%
	Total	$	8,300			$	8,300		$	424			$	319
	_____________________
	(a)	Reflects aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.
	(b)	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
Schedule of Line of Credit Facilities	At December 31, 2014, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective credit agreements:
													Available Capacity at December 31, 2014
	Borrower	Aggregate Bank				Facility Draws			Outstanding				Actual				To Support
		Commitment (a)							Letters of Credit(c)								Additional
																	Commercial
																	Paper (b)
	Exelon Corporate	$	500			$	—		$	6			$	494			$	494
	Generation	5,800				—			1,181				4,619				4,504
	ComEd	1,000				—			2				998				694
	PECO	600				—			1				599				599
	BGE	600				—			—				600				480
	Total	$	8,500			$	—		$	1,190			$	7,310			$	6,771
	_______________________
	(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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
	(b)	Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program.
	(c)	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
Schedule Of Credit Agreement Covenants	The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31, 2014:
		Exelon		Generation		ComEd		PECO	BGE
	Credit facility threshold	2.50 to 1		3.00 to 1		2.00 to 1		2.00 to 1	2.00 to 1
	At December 31, 2014, the interest coverage ratios at the Registrants were as follows:
		Exelon			Generation			ComEd		PECO			BGE
	Interest coverage ratio	9.19			12.35			7.03		8.72			9.28
Schedule of Long-term Debt Instruments	The following tables present the outstanding long-term debt at Exelon, Generation, ComEd, PECO and BGE as of December 31, 2014 and 2013:
	Exelon
								Maturity	December 31,
		Rates						Date	2014				2013
	Long-term debt
	Rate stabilization bonds	5.72	%	-	5.82	%		2017	$	195			$	265
	First mortgage bonds (a)(b)	1.2	%	-	6.45	%		2015 - 2044	8,079				7,746
	Senior unsecured notes	2	%	-	7.6	%		2015 - 2042	7,071				7,571
	Unsecured bonds	2.8	%	-	6.35	%		2016 - 2036	1,750				1,750
	Pollution control note				4.1	%		2014	—				20
	Nuclear fuel procurement contracts	3.25	%	-	3.35	%		2018	70				—
	Junior subordinated notes				6.5	%		2017	1,150				—
	Nonrecourse debt:
	Fixed rates	2.33	%	-	6	%		2031 - 2037	1,166				1,077
	Variable rates	2.41	%	-	5	%		2019 - 2030	1,101				150
	Notes payable and other (c)	6.95	%	-	7.83	%		2015 - 2053	174				181
	Total long-term debt								20,756				18,760
	Unamortized debt discount and premium, net								(37		)		(19		)
	Fair value adjustment								441				384
	Fair value hedge carrying value adjustment,								4				7
	net
	Long-term debt due within one year								(1,802		)		(1,509		)
	Long-term debt								$	19,362			$	17,623
	Long-term debt to financing trusts (d)
	Subordinated debentures to ComEd Financing				6.35	%		2033	$	206			$	206
	III
	Subordinated debentures to PECO Trust III				7.38	%		2028	81				81
	Subordinated debentures to PECO Trust IV				5.75	%		2033	103				103
	Subordinated debentures to BGE Trust				6.2	%		2043	258				258
	Total long-term debt to financing trusts								$	648			$	648
	____________________
	(a)	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s assets are subject to the liens of their respective mortgage indentures.
	(b)	Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.
	(c)	Includes capital lease obligations of $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.
	(d)	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
	ComEd
								Maturity	December 31,
		Rates						Date	2014				2013
	Long-term debt
	First mortgage bonds (a)(b)	1.95	%	-	6.45	%		2015 - 2044	$	5,829			$	5,546
	Notes payable and other (c)	6.95	%	-	7.49	%		2015 - 2053	148				148
	Total long-term debt								5,977				5,694
	Unamortized debt discount and premium, net								(19		)		(19		)
	Long-term debt due within one year								(260		)		(617		)
	Long-term debt								$	5,698			$	5,058
	Long-term debt to financing trust (d)
	Subordinated debentures to ComEd Financing III				6.35	%		2033	$	206			$	206
	______________________
	(a)	Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.
	(b)	Includes first mortgage bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.
	(c)	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053.
	(d)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
	BGE
								Maturity	December 31,
		Rates						Date	2014				2013
	Long-term debt
	Rate stabilization bonds	5.72	%	-	5.82	%		2017	195				$	265
	Notes	2.8	%	-	6.35	%		2016 - 2036	$	1,750			$	1,750
	Total long-term debt								1,945				2,015
	Unamortized debt discount and premium, net								(3		)		(4		)
	Long-term debt due within one year								(75		)		(70		)
	Long-term debt								$	1,867			$	1,941
	Long-term debt to financing trusts (a)
	Subordinated debentures to BGE Capital Trust II				6.2	%		2043	$	258			$	258
___________________
(a)	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.
Generation
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
Senior unsecured notes	2	%	-	7.6	%		2015 - 2042	$	5,771			$	6,271
Social Security Administration				2.93	%		2015	—				1
Pollution control notes				4.1	%		2014	—				20
Nuclear fuel procurement contracts	3.25	%	-	3.35	%		2018	70				—
Nonrecourse debt:
Fixed rates	2.33	%	-	6	%		2031 - 2037	1,166				1,077
Variable rates	2.41	%	-	5	%		2019 - 2030	1,101				150
Notes payable and other (a)				7.83	%		2014 - 2020	26				33
Total long-term debt								8,134				7,552
Fair value adjustment								146				166
Unamortized debt discount and premium, net								(14		)		11
Long-term debt due within one year								(614		)		(561		)
Long-term debt								$	7,652			$	7,168
______________________
(a)	Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.
PECO
							Maturity	December 31,
	Rates						Date	2014				2013
Long-term debt
First mortgage bonds (a)(b)	1.2	%	-	5.95	%		2016 - 2044	$	2,250			$	2,200
Total long-term debt								2,250				2,200
Unamortized debt discount and premium, net								(4		)		(3		)
Long-term debt due within one year								—				(250		)
Long-term debt								$	2,246			$	1,947
Long-term debt to financing trusts (c)
Subordinated debentures to PECO Trust III				7.38	%		2028	$	81			$	81
Subordinated debentures to PECO Trust IV				5.75	%		2033	103				103
Long-term debt to financing trusts								$	184			$	184
_____________________
(a)	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b)	Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.
(c)	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
Schedule of Maturities of Long-term Debt	Long-term debt maturities at Exelon, Generation, ComEd, PECO and BGE in the periods 2014 through 2019 and thereafter are as follows:
	Year	Exelon				Generation			ComEd				PECO				BGE
	2015	$	1,739			$	604		$	260			$	—			$	75
	2016	1,269				4			665				300				300
	2017	2,400				705			425				—				120
	2018	1,415				75			840				500				—
	2019	982				682			300				—				—
	Thereafter	13,599			(a)	6,064			3,693			(b)	1,634			(c)	1,708		(d)
	Total	$	21,404			$	8,134		$	6,183			$	2,434			$	2,203
	____________________
	(a)	Includes $648 million due to ComEd, PECO and BGE financing trusts.
	(b)	Includes $206 million due to ComEd financing trust.
	(c)	Includes $184 million due to PECO financing trusts.
	(d)	Includes $258 million due to BGE financing trust.

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit)	The following table represents the net interest receivable (payable), including interest related to tax positions reflected in the Registrants’ Consolidated Balance Sheets.
	Net interest receivable (payable) as of	Exelon				Generation				ComEd			PECO			BGE
	December 31, 2014	$	(310	)		$	40			$	(203	)	$	3		$	(1	)
	December 31, 2013	(349		)		(37		)		(174		)	3			—
	Income tax expense (benefit) from continuing operations is comprised of the following components:
	For the Year Ended December 31, 2014	Exelon				Generation				ComEd			PECO			BGE
	Included in operations:
	Federal
	Current	$	121			$	360			$	(171	)	$	28		$	24
	Deferred	576				(35		)		395			87			90
	Investment tax credit amortization	(20		)		(16		)		(2		)	—			(1		)
	State
	Current	42				35				7			(2		)	—
	Deferred	(53		)		(137		)		39			1			27
	Total	$	666			$	207			$	268		$	114		$	140
	For the Year Ended December 31, 2013	Exelon				Generation				ComEd			PECO			BGE
	Included in operations:
	Federal
	Current	$	744			$	250			$	160		$	126		$	9
	Deferred	140				360				(27		)	23			100
	Investment tax credit amortization	(15		)		(11		)		(2		)	(1		)	(1		)
	State
	Current	181				50				50			16			—
	Deferred	(6		)		(34		)		(29		)	(2		)	26
	Total	$	1,044			$	615			$	152		$	162		$	134
	For the Year Ended December 31, 2012	Exelon				Generation				ComEd			PECO			BGE
	Included in operations:
	Federal
	Current	$	37			$	104			$	(40	)	$	88		$	(97	)
	Deferred	701				326				237			25			101
	Investment tax credit amortization	(11		)		(6		)		(2		)	(2		)	(1		)
	State
	Current	(25		)		(12		)		6			4			—
	Deferred	(75		)		88				38			12			4
	Total	$	627			$	500			$	239		$	127		$	7
Interest Income and Interest Expense Disclosure [Table Text Block]	The following table sets forth the net interest expense, including interest related to tax positions, recognized in interest expense (income) in other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. The Registrants have not accrued any material penalties with respect to uncertain tax positions.
	Net interest expense (income) for the years ended	Exelon				Generation				ComEd			PECO			BGE
	December 31, 2014	$	(36	)		$	(50	)		$	6		$	—		$	1
	December 31, 2013	391				17				281			(1		)	—
	December 31, 2012	(1		)		11				(20		)	(1		)	9
Effective Income Tax Rate Reconciliation	The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
	For the Year Ended December 31, 2014	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	1.3			(1.9	)		4.5			(0.1	)	5
	Qualified nuclear decommissioning trust fund income	2.4			4.8			—			—		—
	Tax exempt income	(0.2	)		(0.5	)		—			—		—
	Domestic production activities deduction	(2.0	)		(4.1	)		—			—		—
	Health care reform legislation	0.1			—			0.2			—		0.2
	Amortization of investment tax credit, net deferred	(1.1	)		(2.0	)		(0.3	)		(0.1	)	(0.3	)
	taxes
	Plant basis differences	(1.9	)		—			(0.1	)		(10.4	)	0.2
	Production tax credits and other credits	(2.4	)		(4.8	)		—			—		—
	Non-controlling interest	(1.8	)		(3.7	)		—			—		—
	Statute of limitations expiration	(2.6	)		(5.3	)		—			—		—
	Other	—			(0.6	)		0.3			0.1		(0.2	)
	Effective income tax rate	26.8	%		16.9	%		39.6	%		24.5	%	39.9	%
	For the Year Ended December 31, 2013	Exelon			Generation			ComEd			PECO		BGE
	U.S. Federal statutory rate	35	%		35	%		35	%		35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	4.8			1.8			3.4			1.6		4.9
	Qualified nuclear decommissioning trust fund income	3.7			6.1			—			—		—
	Tax exempt income	(0.2	)		(0.3	)		—			—		—
	Domestic production activities deduction	—			—			—			—		—
	Health care reform legislation	0.1			—			0.7			—		0.2
	Amortization of investment tax credit, net deferred	(1.9	)		(3.0	)		(0.6	)		(0.1	)	—
	taxes
	Plant basis differences	(1.6	)		—			(0.8	)		(7.1	)	(0.2	)
	Production tax credits and other credits	(2.1	)		(3.4	)		(0.1	)		—		—
	Statute of limitations expiration	(0.1	)		(0.2	)		—			—		—
	Other	(0.1	)		0.7			0.3			(0.3	)	(0.9	)
	Effective income tax rate	37.6	%		36.7	%		37.9	%		29.1	%	39	%
	For the Year Ended December 31, 2012	Exelon (a)			Generation (a)			ComEd			PECO		BGE (b)
	U.S. Federal statutory rate	35	%		35	%		35	%		35	%	35	%
	Increase (decrease) due to:
	State income taxes, net of Federal income tax benefit	(3.5	)		4.9			4.6			2		24.3
	Qualified nuclear decommissioning trust fund income	5.4			9.1			—			—		—
	Tax exempt income	(0.2	)		(0.4	)		—			—		—
	Domestic production activities deduction	—			—			—			—		—
	Health care reform legislation	0.1			—			0.4			—		11.6
	Amortization of investment tax credit	(1.1	)		(1.3	)		(0.4	)		(0.3	)	(8.6	)
	Plant basis differences	(2.4	)		—			(0.3	)		(11.5	)	(9.0	)
	Production tax credits and other credits	(2.2	)		(3.7	)		—			—		—
	Fines and Penalties	2.6			4.4			—			—		—
	Merger expenses (c)	2.4			—			—			—		24.2
	Statute of limitations expiration	(0.1	)		(0.3	)		—			—		—
	Other	(1.1	)		(0.4	)		(0.6	)		(0.2	)	(13.9	)
	Effective income tax rate	34.9	%		47.3	%		38.7	%		25	%	63.6	%
	_____________________
	(a)	Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012.
	(b)	BGE activity represents the activity for the twelve months ended December 31, 2012.
	(c)	Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger.
Tax Effects of Temporary Differences	The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2014 and 2013 are presented below:
	For the Year Ended December 31, 2014	Exelon				Generation				ComEd			PECO			BGE
	Plant basis differences	$	(12,143	)		$	(3,834	)		$	(3,945	)	$	(2,749	)	$	(1,661	)
	Accrual based contracts	(178		)		(178		)		—			—			—
	Derivatives and other financial instruments	(46		)		(79		)		(4		)	—			—
	Deferred pension and postretirement obligation	1,914				(390		)		(543		)	2			(53		)
	Nuclear decommissioning activities	(726		)		(726		)		—			—			—
	Deferred debt refinancing costs	112				57				(18		)	(2		)	(4		)
	Regulatory assets and liabilities	(1,824		)		—				(286		)	27			(258		)
	Tax loss carryforward	111				48				—			11			39
	Tax credit carryforward	97				143				—			—			—
	Investment in CENG	(563		)		(563		)		—			—			—
	Other, net	1,029				346				255			111			30
	Deferred income tax liabilities (net)	$	(12,217	)		$	(5,176	)		$	(4,541	)	$	(2,600	)	$	(1,907	)
	Unamortized investment tax credits	(555		)		(528		)		(20		)	(2		)	(5		)
	Total deferred income tax liabilities (net) and	$	(12,772	)		$	(5,704	)		$	(4,561	)	$	(2,602	)	$	(1,912	)
	unamortized investment tax credits
	For the Year Ended December 31, 2013	Exelon				Generation				ComEd			PECO			BGE
	Plant basis differences	$	(11,612	)		$	(3,879	)		$	(3,523	)	$	(2,573	)	$	(1,538	)
	Accrual based contracts	(214		)		(214		)		—			—			—
	Derivatives and other financial instruments	(509		)		(505		)		(4		)	—			—
	Deferred pension and postretirement obligation	1,489				(362		)		(522		)	—			(74		)
	Nuclear decommissioning activities	(647		)		(646		)		—			—			—
	Deferred debt refinancing costs	173				79				(21		)	(3		)	(5		)
	Regulatory assets and liabilities	(1,611		)		—				(241		)	42			(253		)
	Tax loss carryforward	252				76				47			11			52
	Tax credit carryforward	534				534				—			—			—
	Investment in CENG	(541		)		(541		)		—			—			—
	Other, net	804				67				154			122			26
	Deferred income tax liabilities (net)	$	(11,882	)		$	(5,391	)		$	(4,110	)	$	(2,401	)	$	(1,792	)
	Unamortized investment tax credits	(490		)		(454		)		(22		)	(3		)	(6		)
	Total deferred income tax liabilities (net) and	$	(12,372	)		$	(5,845	)		$	(4,132	)	$	(2,404	)	$	(1,798	)
	unamortized investment tax credits
Summary of Loss Carryforwards	The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2014.
		Exelon			Generation			ComEd			PECO		BGE
	Federal
	Federal general business credits carryforward	184		(a)	184			—			—		—
	State
	State net operating losses and other credit carryforwards	3,141			1,693			—			170		730		(e)
	Deferred taxes on state tax attributes (net)	169			96			—			11		39
	Valuation allowance on state tax attributes	50			48			—			—		1
	_____________________
	(a)	Exelon’s federal general business credit carryforwards will expire beginning in 2032.
	(b)	Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015
	(c)	Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015.
	(d)	PECO’s state net operating losses will expire beginning in 2031.
	(e)	BGE’s state net operating losses will expire beginning in 2026
Reconciliation of Unrecognized Tax Benefits Excluding Amounts Pertaining to Examined Tax Returns Foll Forward	The following table provides a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2014, 2013 and 2012:
		Exelon				Generation				ComEd			PECO			BGE
	Unrecognized tax benefits at January 1, 2014	$	2,175			$	1,415			$	324		$	44		$	—
	Increases based on tax positions related to 2014	15				15				—			—			—
	Change to positions that only affect timing	(255		)		33				(175		)	—			—
	Increases based on tax positions prior to 2014	18				18				—			—			—
	Decreases based on tax positions prior to 2014	(1		)		(2		)		—			—			—
	Decrease from settlements with taxing authorities	(35		)		(34		)		—			—			—
	Decreases from expiration of statute of limitations	(88		)		(88		)		—			—			—
	Unrecognized tax benefits at December 31, 2014	$	1,829			$	1,357			$	149		$	44		$	—
		Exelon				Generation				ComEd			PECO			BGE
	Unrecognized tax benefits at January 1, 2013	$	1,024			$	876			$	67		$	44		$	—
	Increases based on tax positions related to 2013	19				19				—			—			—
	Change to positions that only affect timing	649				36				257			—			—
	Increases based on tax positions prior to 2013	493				493				—			—			—
	Decreases based on tax positions prior to 2013	(6		)		(5		)		—			—			—
	Decreases from expiration of statute of limitations	(4		)		(4		)		—			—			—
	Unrecognized tax benefits at December 31, 2013	$	2,175			$	1,415			$	324		$	44		$	—
		Exelon				Generation				ComEd			PECO			BGE
	Unrecognized tax benefits at January 1, 2012	$	807			$	683			$	70		$	48		$	11
	Merger balance transfer	195				183				—			—			—
	Increases based on tax positions related to 2012	34				3				—			—			—
	Change to positions that only affect timing	(88		)		(69		)		(3		)	(4		)	(11		)
	Increases based on tax positions prior to 2012	91				91				—			—			—
	Decreases based on tax positions prior to 2012	(6		)		(6		)		—			—			—
	Decreases related to settlements with taxing authorities	(2		)		(2		)		—			—			—
	Decreases from expiration of statute of limitations	(7		)		(7		)		—			—			—
	Unrecognized tax benefits at December 31, 2012	$	1,024			$	876			$	67		$	44		$	—
Summary of Open Tax Years by Jurisdiction	Description of tax years that remain open to assessment by major jurisdiction
	Taxpayer	Open Years
	Exelon (and predecessors) and subsidiaries consolidated Federal income tax returns	1999, 2001-2013
	Constellation and subsidiaries consolidated Federal income tax returns	2011-March 2012
	Exelon and subsidiaries Illinois unitary income tax returns	2007-2013
	Constellation combined New York corporate income tax returns	2008-2013
	Various separate company Pennsylvania corporate net income tax returns	2010-2013
	BGE Maryland corporate net income tax returns	2011-2013
	Various Exelon Maryland corporate net income tax returns	2012-2013
	Various Constellation (Non-BGE) Maryland corporate net income tax returns	2011-2013

Asset_Retirement_Obligations_T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Nuclear Decommissioning Asset Retirement Obligation Rollforward	The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets, from January 1, 2013 to December 31, 2014:
		Exelon and
		Generation
	Nuclear decommissioning ARO at January 1, 2013	$	4,741
	Accretion expense	259
	Net decrease due to changes in, and timing of, estimated future cash flows	(140		)
	Costs incurred to decommission retired plants	(5		)
	Nuclear decommissioning ARO at December 31, 2013 (a)	4,855
	Consolidation of CENG (b)	1,760
	Accretion expense	334
	Net increase due to changes in, and timing of, estimated future cash flows	19
	Costs incurred to decommission retired plants	(7		)
	Nuclear decommissioning ARO at December 31, 2014 (a)	$	6,961
	_________________________
	(a)	Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
	(b)	Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
Unrealized Gains Losses On Nuclear Decommissioning Trust Funds	The following table provides unrealized gains on NDT funds for 2014, 2013 and 2012:
		Exelon and Generation
		For the Years Ended December 31,
		2014			2013			2012
	Net unrealized gains on decommissioning trust	$	180		$	406		$	386
	funds—Regulatory Agreement Units (a)
	Net unrealized gains on decommissioning trust	134			146			105
	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 $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.
	(c)	Net unrealized gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Nuclear Decommissioning Pledged Assets	The following table provides the pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2014 and 2013:
		Exelon and Generation
		2014			2013
	Carrying value of Zion Station pledged assets	$	319		$	458
	Payable to Zion Solutions (a)	292			414
	Current portion of payable to Zion Solutions (b)	137			109
	Cumulative withdrawals by Zion Solutions to pay decommissioning costs	666			498
	___________________
	(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.
Non Nuclear Decommissioning Asset Retirement Obligation Rollforward	The following table provides a rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1, 2013 to December 31, 2014:
		Exelon			Generation			ComEd			PECO			BGE
	Non-nuclear AROs at January 1, 2013	$	343		$	207		$	99		$	29		$	8
	Net increase (decrease) due to changes in, and	1			(11		)	—			—			12
	timing of, estimated future cash flows (a)
	Development projects (b)	2			2			—			—			—
	Accretion expense (c)	18			13			4			1			—
	Payments	(13		)	(10		)	(2		)	—			(1		)
	Non-nuclear AROs at December 31, 2013 (d)	351			201			101			30			19
	Net increase (decrease) due to changes in, and	(1		)	(2		)	2			—			(1		)
	timing of, estimated future cash flows (a)
	Development projects (b)	11			11			—			—			—
	Accretion expense (c)	15			11			3			1			—
	Liabilities held for sale (e)	(4		)	(4		)	—			—			—
	Sale of generating assets (f)	(20		)	(20		)	—			—			—
	Payments	(6		)	(3		)	(2		)	(1		)	—
	Non-nuclear AROs at December 31, 2014 (d)	$	346		$	194		$	104		$	30		$	18
	________________________
	(a)	During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013.
	(b)	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.
	(c)	For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
	(d)	During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.
	(e)	Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.
	(f)	Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations.

Retirement_Benefits_Tables

Retirement Benefits (Tables)	12 Months Ended
	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Schedule Of Pension And Other Postretirement Participation
			Operating Company
	Name of Plan:		Generation		ComEd		PECO		BGE		BSC
	Qualified Pension Plans:
	Exelon Corporation Retirement Program(a)		X		X		X		X		X
	Exelon Corporation Cash Balance Pension Plan(a)		X		X		X		X		X
	Exelon Corporation Pension Plan for Bargaining		X		X						X
	Unit Employees(a)
	Exelon New England Union Employees Pension		X
	Plan(a)
	Exelon Employee Pension Plan for Clinton, TMI		X		X						X
	and Oyster Creek(a)
	Pension Plan of Constellation Energy Group, Inc.(b)		X		X		X		X		X
	Pension Plan of Constellation Energy Nuclear		X						X		X
	Group, LLC(c)
	Nine Mile Point Pension Plan(c)		X								X
	Constellation Mystic Power, LLC Union Employees		X
	Pension Plan Including Plan A and Plan B(b)
	Non-Qualified Pension Plans:
	Exelon Corporation Supplemental Pension Benefit		X		X		X				X
	Plan and 2000 Excess Benefit Plan(a)
	Exelon Corporation Supplemental Management		X		X		X		X		X
	Retirement Plan(a)
	Constellation Energy Group, Inc. Senior Executive		X						X		X
	Supplemental Plan(b)
	Constellation Energy Group, Inc. Supplemental		X						X		X
	Pension Plan(b)
	Constellation Energy Group, Inc. Benefits		X						X		X
	Restoration Plan(b)
	Constellation Nuclear Plan, LLC Executive		X								X
	Retirement Plan(c)
	Constellation Energy Nuclear Plan, LLC Benefits		X								X
	Restoration Plan(c)
	Baltimore Gas & Electric Company Executive		X						X		X
	Benefit Plan(b)
	Baltimore Gas & Electric Company Manager		X						X		X
	Benefit Plan(b)
			Operating Company
	Name of Plan:		Generation		ComEd		PECO		BGE		BSC
	Other Postretirement Benefit Plans:
	PECO Energy Company Retiree Medical Plan(a)		X		X		X		X		X
	Exelon Corporation Health Care Program(a)		X		X				X		X
	Exelon Corporation Employees’ Life Insurance		X		X		X		X		X
	Plan(a)
	Constellation Energy Group, Inc. Retiree Medical		X		X		X		X		X
	Plan(b)
	Constellation Energy Group, Inc. Retiree Dental		X						X		X
	Plan(b)
	Constellation Energy Group, Inc. Employee Life		X		X		X		X		X
	Insurance Plan and Family Life Insurance Plan(b)
	Constellation Mystic Power, LLC		X
	Post-Employment Medical Account Savings Plan(b)
	Exelon New England Union Post-Employment		X
	Medical Savings Account Plan(a)
	Retiree Medical Plan of Constellation Energy		X						X		X
	Nuclear Group LLC(c)
	Retiree Dental Plan of Constellation Energy		X						X		X
	Nuclear Group LLC(c)
	Nine Mile Point Nuclear Station, LLC Medical Care		X								X
	and Prescription Drug Plan for Retired
	Employees(c)
	______________________
	(a)	These plans are collectively referred to as the Legacy Exelon plans.
	(b)	These plans are collectively referred to as the Legacy Constellation Energy Group (CEG) Plans.
(c)	These plans are collectively referred to as the Legacy CENG plans.
Defined Benefit Plan Change In Benefit Obligation RollForward	The following table provides a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:
		Pension Benefits								Other
										Postretirement Benefits
		2014				2013				2014				2013
	Change in benefit obligation:
	Net benefit obligation at beginning of year	$	15,459			$	16,800			$	4,451			$	4,820
	Service cost	293				317				117				162
	Interest cost	749				650				186				194
	Plan participants’ contributions	—				—				42				34
	Actuarial loss (gain)	2,095				(1,363		)		502				(551		)
	Plan amendments	—				1				(1,012		)		15
	Acquisitions/divestitures(a)	594				—				142				—
	Curtailments	(8		)		—				—				—
	Settlements	(30		)		(69		)		—				—
	Gross benefits paid	(896		)		(877		)		(231		)		(223		)
	Net benefit obligation at end of year	$	18,256			$	15,459			$	4,197			$	4,451
		Pension Benefits								Other
										Postretirement Benefits
		2014				2013				2014				2013
	Change in plan assets:
	Fair value of net plan assets at beginning of year	$	13,571			$	13,357			$	2,238			$	2,135
	Actual return on plan assets	1,443				821				90				209
	Employer contributions	332				339				291				83
	Plan participants’ contributions	—				—				42				34
	Benefits paid	(896		)		(877		)		(231		)		(223		)
	Acquisitions/divestitures(a)	454				—				—				—
	Settlements	(30		)		(69		)		—				—
	Fair value of net plan assets at end of year	$	14,874			$	13,571			$	2,430			$	2,238
	_______________________
	(a)	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet.  As a result, Exelon became a sponsor of CENG’s pension and OPEB plans effective July 14, 2014.  See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.
Schedule of Amounts Recognized in Balance Sheet	Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
		Pension Benefits								Other
										Postretirement Benefits
		2014				2013				2014				2013
	Other current liabilities	$	16			$	12			$	25			$	23
	Pension obligations	3,366				1,876				—				—
	Non-pension postretirement benefit obligations	—				—				1,742				2,190
	Unfunded status (net benefit obligation less net plan	$	3,382			$	1,888			$	1,767			$	2,213
	assets)
Defined Benefit Plan Pension Plans With Projected Benefit Obligations And Accumulated Benefit Obligations In Excess Of Plan Assets
	The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans with a PBO or ABO in excess of plan assets.
		PBO in
		excess of plan assets
		2014				2013
	Projected benefit obligation	$	18,256			$	15,452
	Fair value of net plan assets	14,874				13,564
		ABO in
		excess of plan assets
		2014				2013
	Projected benefit obligation	$	18,256			$	15,452
	Accumulated benefit obligation	17,191				14,552
	Fair value of net plan assets	14,874				13,564
Schedule of Defined Benefit Plans Disclosures	A portion of the net periodic benefit cost for all pension and OPEB plans are capitalized within each of the Registrant's Consolidated Balance Sheets. The following table presents the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended December 31, 2014, 2013 and 2012.
		Pension Benefits												Other
														Postretirement Benefits
		2014				2013				2012				2014				2013			2012
	Components of net periodic
	benefit cost:
	Service cost	$	293			$	317			$	280			$	117			$	162		$	156
	Interest cost	749				650				698				186				194			205
	Expected return on assets	(994		)		(1,015		)		(988		)		(154		)		(132		)	(115		)
	Amortization of:
	Transition obligation	—				—				—				—				—			11
	Prior service cost (credit)	14				14				15				(122		)		(19		)	(17		)
	Actuarial loss	420				562				450				50				83			81
	Curtailment benefits	—				—				—				—				—			(7		)
	Settlement charges	2				9				31				—				—			—
	Contractual termination benefits (a)	—				—				14				—				—			6
	Net periodic benefit cost	$	484			$	537			$	500			$	77			$	288		$	320
	______________________
	(a)	ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in 2012.
Changes In Plan Assets And Benefit Obligations Recognized In OCI And Regulatory Assets	The following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2014, 2013 and 2012 for all plans combined.
		Pension Benefits												Other
														Postretirement Benefits
		2014				2013				2012				2014				2013			2012
	Changes in plan assets and benefit
	obligations recognized in AOCI and regulatory assets (liabilities):
	Current year actuarial (gain) loss	$	1,639			$	(1,169	)		$	1,693			$	561			$	(628	)	$	304
	Amortization of actuarial loss	(420		)		(562		)		(450		)		(50		)		(83		)	(81		)
	Current year prior service (credit) cost	—				—				1				(1,012		)		15			(109		)
	Amortization of prior service (cost)	(14		)		(14		)		(15		)		122				19			17
	credit
	Current year transition (asset)	—				—				—				—				—			1
	obligation
	Amortization of transition asset	—				—				—				—				—			(11		)
	(obligation)
	Curtailments	—				—				(10		)		—				—			(1		)
	Settlements	(2		)		(8		)		(31		)		—				—			—
	Total recognized in AOCI and	$	1,203			$	(1,753	)		$	1,188			$	(379	)		$	(677	)	$	120
	regulatory assets (liabilities) (a)
	______________________
	(a)	Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012.
Changes In Plan Assets And Benefit Obligations Not Recognized In OCI And Regulatory Assets	The following table provides the components of Exelon’s gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as components of periodic benefit cost at December 31, 2014 and 2013, respectively, for all plans combined:
		Pension Benefits								Other
										Postretirement Benefits
		2014				2013				2014				2013
	Prior service cost (credit)	$	49			$	62			$	(963	)		$	(73	)
	Actuarial loss	7,407				6,192				985				474
	Total (a)	$	7,456			$	6,254			$	22			$	401
	_______________________
	(a)	Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at December 31, 2013.
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year	The valuation is expected to be completed in the first quarter of 2015 for the majority of the benefit plans.
		Pension Benefits				Other
						Postretirement Benefits
	Prior service cost (credit)	$	13			$	(175	)
	Actuarial loss	562				74
	Total (a)	$	575			$	(101	)
	___________________
	(a)	Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, respectively.
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Benefit Obligation	The following assumptions were used to determine the benefit obligations for the plans at December 31, 2014, 2013 and 2012. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
		Pension Benefits									Other Postretirement Benefits
		2014			2013			2012			2014			2013			2012
	Discount rate	3.94	%		4.8	%		3.92	%		3.92	%		4.9	%		4	%
	Rate of			(a)			(b)			(c)			(a)			(b)			(c)
	compensation
	increase
	Mortality table	RP-2000 table with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA			RP-2000 table with Scale AA improvements			RP-2000 table with Scale BB-2D improvements (adjusted)			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements
					improvements
	Health care cost	N/A			N/A			N/A			6.00%			6.00%			6.50%
	trend on covered										decreasing			decreasing			decreasing
	charges										to			to			to
											ultimate			ultimate			ultimate
											trend of			trend of			trend of
											5.00% in			5.00% in			5.00% in
											2017			2017			2017
	_____________________________
	(a)	3.25% for 2015-2019 and 3.75% thereafter.
	(b)	3.25% for 2014-2018 and 3.75% thereafter.
	(c)	3.25% for 2013-2017 and 3.75% thereafter.
Defined Benefit Plan Weighted Average Assumptions Used In Calculating Net Periodic Benefit Cost	The following assumptions were used to determine the net periodic benefit costs for all the plans for the years ended December 31, 2014, 2013 and 2012:
		Pension Benefits									Other Postretirement Benefits
		2014			2013			2012			2014			2013			2012
	Discount rate	4.8	%	(a)	3.92	%	(b)	4.74	%	(c)	4.9	%	(a)	4	%	(b)	4.8	%	(c)
	Expected return on	7	%	(d)	7.5	%	(d)	7.5	%	(d)	6.59	%	(d)	6.45	%	(d)	6.68	%	(d)
	plan assets
	Rate of			(e)			(f)	3.75	%				(e)			(f)	3.75	%
	compensation
	increase
	Mortality table	RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements			RP-2000 table with Scale AA improvements
	Health care cost	N/A			N/A			N/A			6.00%			6.50%			6.50%
	trend on covered										decreasing			decreasing			decreasing
	charges										to			to			to
											ultimate			ultimate			ultimate
											trend of			trend of			trend of
											5.00% in			5.00% in			5.00% in
											2017			2017			2017
	___________________________
	(a)	The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet.  As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for further information.
	(b)	The discount rates above represent the initial discount rates used to establish Exelon's pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these measurements.
	(c)	The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurements.
	(d)	Not applicable to pension and other postretirement benefit plans that do not have plan assets.
	(e)	3.25% for 2014-2018 and 3.75% thereafter.
	(f)	3.25% for 2013-2017 and 3.75% thereafter.
Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates	A one percentage point change in assumed health care cost trend rates would have the following effects:
	Effect of a one percentage point increase in assumed health care cost trend:
	on 2014 total service and interest cost components	$	35
	on postretirement benefit obligation at December 31, 2014	162
	Effect of a one percentage point decrease in assumed health care cost trend:
	on 2014 total service and interest cost components	(24		)
	on postretirement benefit obligation at December 31, 2014	(113		)
Pension And Other Postretirement Benefit Contributions
	The following table provides contributions made by Generation, ComEd, PECO, BGE and BSC to the pension and other postretirement benefit plans:
		Pension Benefits												Other Postretirement Benefits
		2014(c)				2013				2012				2014				2013			2012 (a)
	Generation	$	173			$	119			$	48			$	124			$	30		$	135
	ComEd	122				118				25				125				4			119
	PECO	11				11				13				5				20			33
	BGE (b)	—				—				—				17				24			12
	BSC(d)	26				91				63				20				5			24
	Exelon	$	332			$	339			$	149			$	291			$	83		$	323
	_________________________
	(a)	The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012. Effective January 1, 2013, Exelon is no longer receiving this subsidy.
	(b)	BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statements.
	(c)	Exelon's and Generation's pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CENG.
	(d)	Includes $9 million, $72 million, and $13 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2014, 2013, and 2012, respectively.
Defined Benefit Plan Estimated Future Benefit Payments
	Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2014 were:
		Pension				Other
		Benefits				Postretirement
						Benefits
	2015	$	1,064			$	217
	2016	962				223
	2017	979				230
	2018	1,004				236
	2019	1,032				247
	2020 through 2024	5,825				1,373
	Total estimated future benefit payments through 2024	$	10,866			$	2,526
Schedule Of Pension And Other Postretirement Benefit Costs	. These amounts include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:
	For the Year Ended December 31,	Generation				ComEd				PECO				BSC (a)				BGE (b)(c)			Exelon
	2014	$	250			$	162			$	36			$	46			$	67		561
	2013	347				309				43				71				55			825
	2012	341				282				50				99				60			820
	_____________________
	(a)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charge.
	(b)	The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 2012.
	(c)	BGE’s pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of December 31, 2012.
Defined Benefit Plan Weighted Average Asset Allocations And Target Allocations	Exelon’s pension and other postretirement benefit plan target asset allocations and December 31, 2014 and 2013 asset allocations were as follows:
	Pension Plans
					Percentage of Plan Assets
					at December 31,
	Asset Category	Target Allocation			2014			2013
	Equity securities	32	%		33	%		35	%
	Fixed income securities	37	%		37			37
	Alternative investments (a)	31	%		30			28
	Total				100	%		100	%
	Other Postretirement Benefit Plans
					Percentage of Plan Assets
					at December 31,
	Asset Category	Target Allocation			2014			2013
	Equity securities	41	%		42	%		45	%
	Fixed income securities	34	%		34			37
	Alternative investments (a)	25	%		24			18
	Total				100	%		100	%
	___________________
	(a)	Alternative investments include private equity, hedge funds and real estate.
Defined Benefit Plan Fair Value Of Plan Assets
	The following table presents Exelon’s pension and other postretirement benefit plan assets measured and recorded at fair value on Exelon’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2014 and 2013:
	At December 31, 2014 (a)	Level 1				Level 2				Level 3				Total
	Pension plan assets
	Cash equivalents	$	1			$	—			$	—			$	1
	Equities:
	Domestic	1,556				1,133				2				2,691
	Foreign	1,705				316				—				2,021
	Equities subtotal	3,261				1,449				2				4,712
	Fixed income:
	Debt securities issued by the U.S. Treasury	1,051				88				—				1,139
	and other U.S. government corporations and agencies
	Debt securities issued by states of the	—				80				—				80
	United States and by political subdivisions of the states
	Corporate debt securities	—				3,125				120				3,245
	Other	—				942				152				1,094
	Derivative instruments (b):
	Assets	—				4				—				4
	Liabilities	—				(16		)		—				(16		)
	Fixed income subtotal	1,051				4,223				272				5,546
	Private equity	—				—				904				904
	Hedge funds	—				1,355				1,329				2,684
	Real estate	243				—				744				987
	Pension plan assets subtotal	4,556				7,027				3,251				14,834
	At December 31, 2014 (a)	Level 1				Level 2				Level 3				Total
	Other postretirement benefit plan assets
	Cash equivalents	11				—				—				11
	Equities:
	Domestic	296				378				—				674
	Foreign	184				147				—				331
	Equities subtotal	480				525				—				1,005
	Fixed income:
	Debt securities issued by the U.S. Treasury	15				59				—				74
	and other U.S. government corporations and agencies
	Debt securities issued by states of the	—				197				—				197
	United States and by political subdivisions of the states
	Corporate debt securities	—				42				—				42
	Other	253				272				—				525
	Fixed income subtotal	268				570				—				838
	Hedge funds	—				339				110				449
	Real estate	8				—				116				124
	Other postretirement benefit plan assets subtotal	767				1,434				226				2,427
	Total pension and other postretirement benefit plan assets (c)	$	5,323			$	8,461			$	3,477			$	17,261
	At December 31, 2013 (a)	Level 1				Level 2				Level 3				Total
	Pension plan assets
	Equities:
	Domestic	$	1,587			$	865			$	2			$	2,454
	Foreign	1,773				302				—				2,075
	Equities subtotal	3,360				1,167				2				4,529
	Fixed income:
	Debt securities issued by the U.S. Treasury	908				99				—				1,007
	and other U.S. government corporations and agencies
	Debt securities issued by states of the	—				88				—				88
	United States and by political subdivisions of the states
	Foreign debt securities	—				205				—				205
	Corporate debt securities	—				2,927				41				2,968
	Other	5				899				—				904
	Derivative instruments (b):
	Assets	—				7				—				7
	Liabilities	—				(134		)		—				(134		)
	Fixed income subtotal	913				4,091				41				5,045
	Private equity	—				—				806				806
	Hedge funds	—				1,266				1,039				2,305
	Real estate	264				2				582				848
Pension plan assets subtotal	4,537				6,526				2,470				13,533
At December 31, 2013 (a)	Level 1				Level 2				Level 3				Total
Other postretirement benefit plan assets
Cash equivalents	51				—				—				51
Equities:
Domestic	296				345				—				641
Foreign	154				170				—				324
Equities subtotal	450				515				—				965
Fixed income:
Debt securities issued by the U.S. Treasury	17				46				—				63
and other U.S. government corporations and agencies
Debt securities issued by states of the	—				149				—				149
United States and by political subdivisions of the states
Foreign debt securities	—				2				—				2
Corporate debt securities	—				50				—				50
Other	305				225				—				530
Fixed income subtotal	322				472				—				794
Private equity	—				—				2				2
Hedge funds	—				295				4				299
Real estate	8				5				109				122
Other postretirement benefit plan assets subtotal	831				1,287				115				2,233
Total pension and other postretirement benefit	$	5,368			$	7,813			$	2,585			$	15,766
plan assets (c)
__________________________
(a)	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)	Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.
(c)	Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.
Defined Benefit Plan Fair Value Of Plan Assets Unobservable Input Reconciliation	The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the years ended December 31, 2014 and 2013:
		Hedge				Private				Real				Fixed				Equities			Total
		funds				equity				estate				income
	Pension Assets
	Balance as of January 1, 2014	$	1,039			$	806			$	582			$	41			$	2		$	2,470
	Actual return on plan assets:
	Relating to assets still held at the	77				112				83				7				—			279
	reporting date
	Relating to assets sold during the	3				—				—				—				—			3
	period
	Purchases, sales and settlements:
	Purchases	311				173				136				227				—			847
	Sales	(38		)		—				(19		)		(3		)		—			(60		)
	Settlements (a)	(33		)		(203		)		(65		)		—				—			(301		)
	Transfers into (out of) Level 3 (b)(c)	(30		)		16				27				—				—			13
	Balance as of December 31, 2014	$	1,329			$	904			$	744			$	272			$	2		$	3,251
	Other Postretirement Benefits
	Balance as of January 1, 2014	$	4			$	2			$	109			$	—			$	—		$	115
	Actual return on plan assets:
	Relating to assets still held at the	1				—				13				—				—			14
	reporting date
	Purchases, sales and settlements:
	Purchases	109				1				1				—				—			111
	Sales	(4		)		(2		)		(7		)		—				—			(13		)
	Settlements (a)	—				(1		)		—				—				—			(1		)
	Balance as of December 31, 2014	$	110			$	—			$	116			$	—			$	—		$	226
		Hedge				Private				Real				Fixed				Equities			Total
		funds				equity				estate				income
	Pension Assets
	Balance as of January 1, 2013	$	1,235			$	754			$	426			$	—			$	—		$	2,415
	Actual return on plan assets:
	Relating to assets still held at the	143				86				63				—				—			292
	reporting date
	Relating to assets sold during the	3				—				(4		)		—				—			(1		)
	period
	Purchases, sales and settlements:
	Purchases	360				123				226				41				2			752
	Sales	(76		)		—				(91		)		—				—			(167		)
	Settlements (a)	(3		)		(157		)		(38		)		—				—			(198		)
	Transfers into (out of) Level 3 (c)	(623		)		—				—				—				—			(623		)
	Balance as of December 31, 2013	$	1,039			$	806			$	582			$	41			$	2		$	2,470
	Other Postretirement Benefits
	Balance as of January 1, 2013	$	12			$	1			$	95			$	—			$	—		$	108
	Actual return on plan assets:
	Relating to assets still held at the	1				—				11				—				—			12
	reporting date
	Purchases, sales and settlements:
	Purchases	—				1				3				—				—			4
	Sales	(1		)		—				—				—				—			(1		)
	Settlements (a)	(4		)		—				—				—				—			(4		)
	Transfers into (out of) Level 3 (c)	(4		)		—				—				—				—			(4		)
	Balance as of December 31, 2013	$	4			$	2			$	109			$	—			$	—		$	115
	________________________
	(a)	Represents cash settlements only.
	(b)	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.
	(c)	As of January 1, 2014 and January 1, 2013, hedge fund investments that contained redemption restrictions limiting Exelon’s ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2014 and December 31, 2013, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $43 million and $627 million in 2014 and 2013 respectively.
Schedule Of Defined Contributions	. The following table presents matching contributions to the savings plan for the years ended December 31, 2014, 2013 and 2012:
	For the Year Ended December 31,	Exelon				Generation				ComEd				PECO				BGE (a)			BSC (b)
	2014	$	103			$	51			$	26			$	8			$	8		$	10
	2013	85				40				22				8				8			7
	2012	67				30				19				7				7			5
	_________________________
	(a)	BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012.
	(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)	12 Months Ended
	Dec. 31, 2014
Restructuring and Related Activities [Abstract]
Business Acquisition, Integration, Restructuring and Other Related Costs [Text Block]	ounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration:
	Year Ended December 31, 2014		Exelon and Generation
	Severance Liability
	Balance at December 31, 2013		$	2
	Integration of CENG (a)		19
	Severance charges		3
	Payments		(11		)
	Balance at December 31, 2014		$	13
	______________________
	(a)	Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.
Schedule of Restructuring and Related Costs	For the year ended December 31, 2012, the Registrants recorded the following severance benefit costs associated with identified job reductions within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, except for those costs that were capitalized as regulatory assets related to ComEd and BGE:
	Year Ended December 31, 2012
	Severance Benefits (a)		Exelon (b)				Generation			ComEd (b)			PECO			BGE (b)
	Severance charges		$	124			$	80		$	14		$	7		$	17
	Stock compensation		7				4			1			—			1
	Other charges		7				4			1			—			1
	Total severance benefits		$	138			$	88		$	16		$	7		$	19
	________________________
	(a)	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
	(b)	Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period.
Schedule of Corporate Restructuring Severance Obligations	Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations:
	Severance liability	Exelon				Generation			ComEd			PECO			BGE
	Balance at December 31, 2012	$	111			$	33		$	1		$	—		$	11
	Severance charges (a)	5				1			—			—			—
	Stock compensation	1				—			—			—			—
	Payments	(64		)		(24		)	(1		)	—			(5		)
	Balance at December 31, 2013	$	53			$	10		$	—		$	—		$	6
	Payments	(41		)		(7		)	—			—			(4		)
	Balance at December 31, 2014	$	12			$	3		$	—		$	—		$	2
	________________________
	(a)	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon’s ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2014 and December 31, 2013.
Schedule Of Severance Costs	For the years ended December 31, 2014, 2013, and 2012, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
	Severance Benefits (a)	Exelon				Generation			ComEd			PECO			BGE
	Severance Charges-2014	$	7			$	5		$	1		$	—		$	1
	Severance Charges-2013	18				16			2			—			—
	Severance Charges-2012	19				14			2			1			3
	________________________
	(a)	The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material.
	(b)	The amount of ongoing severance for Generation for the year ended December 31, 2014 includes a $3 million severance reserve as a result of anticipated employee position reductions due to recent acquisitions.

Preferred_and_Preference_Secur1

Preferred and Preference Securities (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule of Stock by Class
				December 31,
		Redemption		2014	2013	2014		2013
		Price (a)		Shares Outstanding		Dollar Amount
	Series (without mandatory redemption)
	7.125%, 1993 Series	$	100	400,000	400,000	$	40	$	40
	6.97%, 1993 Series	100		500,000	500,000	50		50
	6.70%, 1993 Series	100		400,000	400,000	40		40
	6.99%, 1995 Series	100.35		600,000	600,000	60		60
	Total preference stock			1,900,000	1,900,000	$	190	$	190
	______________________
	(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.
	The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013:
					December 31,
					2014	2013
		Par Value		Shares Authorized	Shares Outstanding
	Common Stock
	Exelon	no par value		2,000,000,000	859,833,343	857,290,484
	ComEd	$	12.5	250,000,000	127,016,947	127,016,896
	PECO	no par value		500,000,000	170,478,507	170,478,507
	BGE	no par value		175,000,000	1,000	1,000

Common_Stock_Tables

Common Stock (Tables)	12 Months Ended
	Dec. 31, 2014
Common Stock [Abstract]
Schedule of Stock by Class
						December 31,
		Redemption				2014			2013			2014		2013
		Price (a)				Shares Outstanding						Dollar Amount
	Series (without mandatory redemption)
	7.125%, 1993 Series	$	100			400,000			400,000			$	40	$	40
	6.97%, 1993 Series	100				500,000			500,000			50		50
	6.70%, 1993 Series	100				400,000			400,000			40		40
	6.99%, 1995 Series	100.35				600,000			600,000			60		60
	Total preference stock					1,900,000			1,900,000			$	190	$	190
	______________________
	(a)	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.
	The following table presents common stock authorized and outstanding as of December 31, 2014 and 2013:
									December 31,
									2014			2013
		Par Value				Shares Authorized			Shares Outstanding
	Common Stock
	Exelon	no par value				2,000,000,000			859,833,343			857,290,484
	ComEd	$	12.5			250,000,000			127,016,947			127,016,896
	PECO	no par value				500,000,000			170,478,507			170,478,507
	BGE	no par value				175,000,000			1,000			1,000
Stock Based Compensation Components	The following table presents the stock-based compensation expense included in Exelon’s Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
	Components of Stock-Based Compensation Expense	2014				2013				2012
	Performance share awards	$	59			$	48			$	46
	Restricted stock units	61				61				50
	Stock options	2				3				15
	Other stock-based awards	5				6				4
	Total stock-based compensation expense included in operating and	127				118				115
	maintenance expense
	Income tax benefit	(47		)		(44		)		(44		)
	Total after-tax stock-based compensation expense	$	80			$	74			$	71
Stock Based Compensation Expense Subsidiaries	The following table presents stock-based compensation expense (pre-tax) for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
	Subsidiaries	2014				2013				2012 (a)
	Generation	$	52			$	48			$	42
	ComEd	7				9				11
	PECO	3				5				5
	BGE	5				6				5
	BSC (b)	60				50				52
	Total	$	127			$	118			$	115
	________________________
	(a)	BGE’s stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. This amount is not included in Exelon’s stock-based compensation expense for the year ended December 31, 2012 shown in the table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary above.
	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.
Stock Based Compensation Tax Benefit	The following table presents information regarding Exelon’s tax benefits for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
		2014				2013				2012
	Realized tax benefit when exercised/distributed:
	Stock options	$	—			$	—			$	3
	Restricted stock units	17				11				11
	Performance share awards	11				11				7
	Stock deferral plan	—				1				—
	Excess tax benefits included in other financing activities of Exelon’s
	Consolidated Statements of Cash Flows:
	Stock options	$	—			$	—			$	2
Schedule of Assumptions Used	The following table presents the weighted average assumptions used in the pricing model for grants and the resulting weighted average grant date fair value of stock options granted for the year ended 2012:
		Year ended December 31, 2012
	Dividend yield	5.28	%
	Expected volatility	23.2	%
	Risk-free interest rate	1.3	%
	Expected life (years)	6.25
	Weighted average grant date fair value (per share)	4.18
Schedule of Share-based Compensation, Stock Options, Activity	The following table presents information with respect to stock option activity for the year ended December 31, 2014:
		Shares			Weighted				Weighted		Aggregate
					Average				Average		Intrinsic
					Exercise				Remaining		Value
					Price				Contractual
					(per				Life
					share)				(years)
	Balance of shares outstanding at December 31, 2013	21,035,445			$	46.07
	Options exercised	(291,805	)		25.27
	Options forfeited	(8,886	)		55.78
	Options expired	(1,903,787	)		41.47
	Balance of shares outstanding at December 31, 2014	18,830,967			$	46.85			4.11		$	29
	Exercisable at December 31, 2014 (a)	18,398,932			$	47.01			4.04		$	29
	____________________
	(a)	Includes stock options issued to retirement eligible employees.
Stock Options Exercised	The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2014, 2013 and 2012:
		Year Ended
		December 31,
		2014				2013				2012
	Intrinsic value(a)	$	3			$	4			$	19
	Cash received for exercise price	7				19				47
	______________________
	(a)	The difference between the market value on the date of exercise and the option exercise price.
Schedule of Nonvested Share Activity	The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2014:
		Shares			Weighted Average
					Exercise Price
					(per share)
	Nonvested at December 31, 2013 (a)	847,118			$	40.22
	Vested	(406,197	)		40.21
	Forfeited	(8,886	)		55.78
	Nonvested at December 31, 2014 (a)	432,035			$	39.91
	_____________________
	(a)	Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
Schedule of Nonvested Restricted Stock Units Activity	The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2014:
		Shares			Weighted Average
					Grant Date Fair
					Value (per share)
	Nonvested at December 31, 2013 (a)	3,386,697			$	34.1
	Granted	2,252,574			28.71
	Vested	(1,216,016	)		35.36
	Forfeited	(86,094	)		31.99
	Undistributed vested awards (b)	(578,943	)		29.17
	Nonvested at December 31, 2014 (a)	3,758,218			$	31.27
	_______________________
	(a)	Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
	(b)	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014.
Schedule of Nonvested Performance-based Units Activity	The following table summarizes Exelon’s nonvested performance share awards activity for the year ended December 31, 2014:
		Shares			Weighted Average
					Grant Date Fair
					Value (per share)
	Nonvested at December 31, 2013 (a)	2,014,190			$	32.74
	Granted	1,712,085			28.75
	Change in performance	98,227			31.85
	Vested	(497,714	)		35.05
	Forfeited	(29,476	)		30.16
	Undistributed vested awards (b)	(601,215	)		28.96
	Nonvested at December 31, 2014 (a)	2,696,097			$	30.62
	_______________________
	(a)	Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
	(b)	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014.
Not Settled Performance Share Awards Balance Sheet Presentation	The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:
		December 31,
		2014				2013
	Current liabilities(a)	$	28			$	13
	Deferred credits and other liabilities (b)	36				24
	Common stock	33				32
	Total	$	97			$	69
	__________________________
	(a)	Represents the current liability related to performance share awards expected to be settled in cash.
	(b)	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings_Per_Share_and_Equity_1

Earnings Per Share and Equity (Tables)	12 Months Ended
	Dec. 31, 2014
Earnings Per Share [Abstract]
Reconciliation of basic and diluted earnings per share	The following table sets forth the components of basic and diluted earnings per share and shows the effect of the stock options, performance share awards and restricted stock on the weighted average number of shares outstanding used in calculating diluted earnings per share:
		Year Ended December 31,
		2014		2013		2012
	Net income attributable to common shareholders	$	1,623	$	1,719	$	1,160
	Weighted average common shares outstanding—basic	860		856		816
	Assumed exercise and/or distributions of stock-based awards	4		4		3
	Weighted average common shares outstanding—diluted	864		860		819

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule Of Accumulated Other Comprehensive Income (Loss)	The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2014 and 2013:
	For the Year Ended December 31, 2014	Gains and			Unrealized			Pension and			Foreign			AOCI of			Total
		(Losses) on			Gains and			Non-Pension			Currency			Equity
		Cash Flow			(Losses) on			Postretirement			Items			Investments
		Hedges			Marketable			Benefit Plan
					Securities			items
	Exelon (a)
	Beginning balance	$	120		$	2		$	(2,260	)	$	(10	)	$	108		$	(2,040	)
	OCI before reclassifications	(31		)	(1		)	(498		)	(9		)	11			(528		)
	Amounts reclassified from AOCI (b)	(117		)	2			118			—			(119		)	(116		)
	Net current-period OCI	(148		)	1			(380		)	(9		)	(108		)	(644		)
	Ending balance	$	(28	)	$	3		$	(2,640	)	$	(19	)	$	—		$	(2,684	)
	Generation (a)
	Beginning balance	$	114		$	2		$	—		$	(10	)	$	108		$	214
	OCI before reclassifications	(15		)	(1		)	—			(9		)	11			(14		)
	Amounts reclassified from AOCI (b)	(117		)	—			—			—			(119		)	(236		)
	Net current-period OCI	(132		)	(1		)	—			(9		)	(108		)	(250		)
	Ending balance	$	(18	)	$	1		$	—		$	(19	)	$	—		$	(36	)
	PECO (a)
	Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1
	OCI before reclassifications	—			—			—			—			—			—
	Amounts reclassified from AOCI (b)	—			—			—			—			—			—
	Net current-period OCI	—			—			—			—			—			—
	Ending balance	$	—		$	1		$	—		$	—		$	—		$	1
	For the Year Ended December 31, 2013	Gains and			Unrealized			Pension and			Foreign			AOCI of			Total
		(Losses) on			Gains and			Non-Pension			Currency			Equity
		Cash Flow			(Losses) on			Postretirement			Items			Investments
		Hedges			Marketable			Benefit Plan
					Securities			items
	Exelon (a)
	Beginning balance	$	368		$	—		$	(3,137	)	$	—		$	2		$	(2,767	)
	OCI before reclassifications	29			2			669			(10		)	101			791
	Amounts reclassified from AOCI (b)	(277		)	—			208			—			5			(64		)
	Net current-period OCI	(248		)	2			877			(10		)	106			727
	Ending balance	$	120		$	2		$	(2,260	)	$	(10	)	$	108		$	(2,040	)
	Generation (a)
	Beginning balance	$	512		$	—		$	—		$	—		$	1		513
	OCI before reclassifications	15			2			—			(10		)	102			109
	Amounts reclassified from AOCI (b)	(413		)	—			—			—			5			(408		)
	Net current-period OCI	(398		)	2			—			(10		)	107			(299		)
	Ending balance	$	114		$	2		$	—		$	(10	)	$	108		$	214
	PECO (a)
	Beginning balance	$	—		$	1		$	—		$	—		$	—		$	1
	OCI before reclassifications	—			—			—			—			—			—
	Amounts reclassified from AOCI (b)	—			—			—			—			—			—
	Net current-period OCI	—			—			—			—			—			—
	Ending balance	$	—		$	1		$	—		$	—		$	—		$	1
	_______________________
	(a)	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
	(b)	See next tables for details about these reclassifications.
Reclassification Out Of Accumulated Other Comprehensive Income	The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2014 and 2013:
	For the Year Ended December 31, 2014
	Details about AOCI components	Items reclassified out of AOCI (a)						Affected line item in the Statements of Operations and Comprehensive Income
		Exelon			Generation
	Gains and (losses) on cash flow hedges
	Energy related hedges	$	195		$	195		Operating revenues
		195			195			Total before tax
		(78		)	(78		)	Tax expense
		$	117		$	117		Net of tax
	Gains and (losses) on available
	for sale securities
	Other available securities for sale	$	(2	)	$	—		Other Income and Deductions
		$	(2	)	$	—		Net of tax
	Amortization of pension and other
	postretirement benefit plan items
	Prior service costs (b)	$	46		$	—
	Actuarial losses (b)	(239		)	—
		(193		)	—			Total before tax
		75			—			Tax benefit
		$	(118	)	$	—		Net of tax
	Equity investments
	Sale of equity method investment	$	5		$	5
	Reversal of CENG equity method AOCI	193			193			Equity in losses of unconsolidated affiliates
		198			198			Total before tax
		(79		)	(79		)	Tax expense
		$	119		$	119		Net of tax
	Total Reclassifications	$	116		$	236		Net of tax
	For the Year Ended December 31, 2013
	Details about AOCI components	Items reclassified out of AOCI (a)						Affected line item in the Statements of Operations and Comprehensive Income
		Exelon			Generation
	Gains and (losses) on cash flow hedges
	Energy related hedges	$	464		$	683		Operating revenues
	Other cash flow hedges	(3		)	—			Interest expense
		461			683			Total before tax
		(184		)	(270		)	Tax expense
		$	277		$	413		Net of tax
	Amortization of pension and other
	postretirement benefit plan items
	Prior service costs (b)	$	(2	)	$	—
	Actuarial losses (b)	(339		)	—
	Deferred compensation unit plan (c)	(1		)	—
		(342		)	—			Total before tax
		134			—			Tax benefit
		$	(208	)	$	—		Net of tax
	Equity investments
	Capital activity	$	(8	)	$	(8	)	Equity in losses of unconsolidated affiliates
		(8		)	(8		)	Total before tax
		3			3			Tax benefit
		$	(5	)	$	(5	)	Net of tax
	Total Reclassifications	$	64		$	408		Net of tax
	_____________________
	(a)	Amounts in parenthesis represent a decrease in net income.
	(b)	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 16 — Retirement Benefits for additional details).
	(c)	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.
Schedule of Components of Income Tax Expense (Benefit)	The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years ended December 31, 2014 and 2013:
		For the Years Ended December 31,
		2014			2013			2012
	Exelon
	Pension and non-pension postretirement benefit plans:
	Prior service benefit reclassified to periodic benefit cost	$	19		$	—		$	(1	)
	Actuarial loss reclassified to periodic cost	(93		)	(133		)	(110		)
	Transition obligation reclassified to periodic cost	—			—			(2		)
	Pension and non-pension postretirement benefit plans valuation adjustment	317			(430		)	237
	Change in unrealized loss on cash flow hedges	96			166			68
	Change in marketable securities	—			—			1
	Change in unrealized income on equity investments	73			(71		)	(1		)
	Total	$	412		$	(468	)	$	192
	Generation
	Change in unrealized loss on cash flow hedges	$	84		$	262		$	262
	Change in unrealized income on equity investments	73			(72		)	1
	Total	$	157		$	190		$	263

Commitments_and_Contingencies_1

Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2014
Environmental Loss Contingency Tables [Abstract]
Schedule of Government Settlement Agreements	Under the settlement agreement, Generation has received cumulative cash reimbursements for costs incurred as follows:
		Total			Net (a)
	Cumulative cash reimbursements (b)	$	836		$	702
	_____________________________
	(a)	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.
	(b)	Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.
	As of December 31, 2014, and 2013, the amount of SNF storage costs for which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:
		31-Dec-14			31-Dec-13
	DOE receivable - current (a)	$	82		$	71
	DOE receivable - noncurrent (b)	7			—
	Amounts owed to co-owners (a)(c)	(5		)	(18		)
	_____________________________
	(a)	Recorded in Accounts receivable, other.
	(b)	Recorded in Deferred debits and other assets, other
	(c)	Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other.  CENG amounts owed to co-owners are recorded in Accounts payable. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.
Energy Commitments	At December 31, 2014, Generation’s short- and long-term commitments, relating to the purchases from unaffiliated utilities and others of energy, capacity and transmission rights, are as indicated in the following tables:
		Net Capacity				REC			Transmission Rights		Total
		Purchases  (a)				Purchases (b)			Purchases (c)
	2015	$	418			$	152		$	20	$	590
	2016	283				228			15		526
	2017	222				121			15		358
	2018	112				29			16		157
	2019	117				5			16		138
	Thereafter	279				1			35		315
	Total	$	1,431			$	536		$	117	$	2,084
	_____________________________
	(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 December 31, 2014, 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 December 31, 2014, capacity offsets were $132 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 of December 31, 2014 are as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	ComEd
	Electric supply procurement (a)	$	620			$	329		$	151	$	140	$	—	$	—	$	—
	Renewable energy and RECs (b)	1,517				75			76		77		78		84		1,127
	PECO
	Electric supply procurement (c)	609				527			82		—		—		—		—
	AECs (d)	13				2			2		2		2		2		3
	BGE
	Electric supply procurement (e)	1,315				779			448		88		—		—		—
	Curtailment services (f)	115				40			34		29		12		—		—
	_______________________
	(a)	ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, 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)	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.
	(c)	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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 3 — Regulatory Matters for additional information.
	(d)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 — Regulatory Matters for additional information.
	(e)	BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters for additional information.
	(f)	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. See Note 3 — Regulatory Matters for additional information.
Other Purchase Obligation	The Registrants’ other purchase obligations as of December 31, 2014, 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	$	894			$	336		$	258	$	150	$	36	$	30	$	84
	Generation (a)(b)	396				163			67		42		30		24		70
	ComEd (c)	148				63			77		1		1		1		5
	PECO (c)	7				3			4		—		—		—		—
	BGE (c)	343				107			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 assets-held-for-sale. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information.
	(c)	Purchase obligations include commitments related to smart meter installation. See Note 3 — Regulatory Matters for additional information.
Fuel Purchase Commitments	As of December 31, 2014, these commitments were as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	Generation	$	8,981			$	1,404		$	1,119	$	1,124	$	1,001	$	888	$	3,445
	PECO	428				146			103		60		34		14		71
	BGE	611				111			82		67		57		54		240
Commercial Commitments	PECO’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	Letters of credit (non-debt) (a)	$	22			$	22		$	—	$	—	$	—	$	—	$	—
	Surety bonds(b)	18				18			—		—		—		—		—
	Performance guarantees(c)	178				—			—		—		—		—		178
	Total commercial commitments	$	218			$	40		$	—	$	—	$	—	$	—	$	178
	________________________
	(a)	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
	(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
	(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
	ComEd’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	Letters of credit (non-debt) (a)	$	17			$	17		$	—	$	—	$	—	$	—	$	—
	Surety bonds(b)	5				3			—		—		—		—		2
	Performance guarantees (c)	200				—			—		—		—		—		200
	Total commercial commitments	$	222			$	20		$	—	$	—	$	—	$	—	$	202
	_________________________
	(a)	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
	(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
	(c)	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.
	Exelon’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	Letters of credit (non-debt) (a)	$	1,233			$	1,151		$	77	$	5	$	—	$	—	$	—
	Surety bonds(b)	596				545			10		4		1		2		34
	Performance guarantees (c)	1,239				472			20		20		20		20		687
	Energy marketing contract	3,220				3,220			—		—		—		—		—
	guarantees (d)
	Lease guarantees(e)	40				—			—		—		—		—		40
	Nuclear insurance premiums (f)	3,014				—			—		—		—		—		3,014
	Underwriters discount (g)	60				60			—		—		—		—		—
	Total commercial commitments	$	9,402			$	5,448		$	107	$	29	$	21	$	22	$	3,775
	___________________________
	(a)	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
	(b)	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
	(c)	Performance guarantees—Guarantees issued to ensure performance under specific contracts. Additionally includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.
	(d)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.2 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 market prices.
	(e)	Lease guarantees—Guarantees issued to ensure payments on building leases.
	(f)	Nuclear insurance premiums—Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
	(g)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19 - Common Stock for further details of the equity securities offering.
	BGE’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	Letters of credit (non-debt) (a)	$	1			$	1		$	—	$	—	$	—	$	—	$	—
	Surety bonds (b)	11				11			—		—		—		—		—
	Performance guarantees (c)	253				3			—		—		—		—		250
	Total commercial commitments	$	265			$	15		$	—	$	—	$	—	$	—	$	250
	________________________
	(a)	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
	(b)	Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
	(c)	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.
	Generation’s commercial commitments as of December 31, 2014, representing commitments potentially triggered by future events, were as follows:
						Expiration within
		Total				2015			2016		2017		2018		2019		2020
																	and beyond
	Letters of credit (non-debt) (a)	$	1,187			$	1,106		$	76	$	5	$	—	$	—	$	—
	Surety bonds	481				468			3		—		—		—		10
	Performance guarantees (b)	458				319			20		20		20		20		59
Energy marketing contract	1,244				1,244			—		—		—		—		—
guarantees (c)
Nuclear insurance premiums (d)	3,014				—			—		—		—		—		3,014
Total commercial commitments	$	6,384			$	3,137		$	99	$	25	$	20	$	20	$	3,083
________________________
(a)	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
(b)	Performance guarantees—Guarantees issued to ensure performance under specific contracts.
(c)	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 market prices.
(d)	Nuclear insurance premiums — Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
Other Commitments	The commitment includes approximately $20 million of in-kind services. As of December 31, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:
		Total
	2015	$	98
	2016	38
	2017	20
	2018	11
	Total	$	167
Operating Leases Of Lessee Disclosure	Minimum future operating lease payments, including lease payments for vehicles, real estate, computers, rail cars, operating equipment and office equipment, as of December 31, 2014 were:
		Exelon				Generation (b)			ComEd (c)		PECO (c)		BGE (c)(d)
	2015	$	99			$	51		$	14	$	3	$	13
	2016	102				57			13		3		11
	2017	102				63			8		3		10
	2018	86				57			4		3		9
	2019	70				43			4		2		7
	Remaining years	699				628			2		—		27
	Total minimum future lease payments	$	1,158		(a)	$	899	(a)	$	45	$	14	$	77
	______________________
	(a)	Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment.
	(b)	The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million .
	(c)	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, and BGE’s annual obligation for these arrangements, included in each of the years 2015—2019, was $2 million, $3 million, and $2 million respectively.
	(d)	Includes all future lease payments on a 99 year real estate lease that expires in 2106.
Operating Leases Rent Expense	The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2014, 2013 and 2012:
	For the Year Ended December 31,	Exelon				Generation (a)			ComEd		PECO		BGE
	2014	$	865			$	806		$	15	$	14	$	12
	2013	806				744			15		21		11
	2012	930				872			18		27		12
	__________________________
	(a)	Includes Generation’s PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the Energy Commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation’s PPAs and other capacity contracts totaled $755 million, $694 million and $801 million during 2014, 2013 and 2012, respectively.
Accrued environmental liabilities	As of December 31, 2014 and 2013, the Registrants have accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
	December 31, 2014	Total environmental				Portion of total related to MGP
		investigation				investigation and remediation
		and remediation reserve
	Exelon	$	347			$	277
	Generation	63				—
	ComEd	238				235
	PECO	45				42
	BGE	1				—
	31-Dec-13	Total environmental				Portion of total related to MGP
		investigation				investigation and remediation
		and remediation reserve
	Exelon	$	338			$	273
	Generation	56				—
	ComEd	234				229
	PECO	47				44
	BGE	1				—

Supplemental_Financial_Informa1

Supplemental Financial Information (Tables)	12 Months Ended
	Dec. 31, 2014
Supplemental Financial Information [Abstract]
Components of taxes other than income	The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2014, 2013 and 2012.
	For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
	Taxes other than income
	Utility (a)	$	456			$	89			$	238			$	128		$	86
	Property	396				240				25				15			114
	Payroll	200				118				28				14			18
	Other	102				18				2				2			3
	Total taxes other than income	$	1,154			$	465			293				$	159		$	221
	For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
	Taxes other than income
	Utility (a)	$	449			$	79			$	241			$	129		$	82
	Property	302				205				24				14			112
	Payroll	159				89				27				13			15
	Other	185				16				7				2			4
	Total taxes other than income	$	1,095			$	389			$	299			$	158		$	213
	For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
	Taxes other than income
	Utility (a)	$	463			$	82			$	239			$	141		$	75
	Property	227				189				22				13			111
	Payroll	131				78				26				12			18
	Other	198				20				8				(4		)	4
	Total taxes other than income	$	1,019			$	369			$	295			$	162		$	208
	_____________________
	(a)	Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Components of non-operating income and expenses
	For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning
	trust funds (a)—
	Regulatory agreement units	$	216			$	216			$	—			$	—		$	—
	Non-regulatory agreement units	159				159				—				—			—
	Net unrealized gains on decommissioning
	trust funds—
	Regulatory agreement units	180				180				—				—			—
	Non-regulatory agreement units	134				134				—				—			—
	Net unrealized gains on pledged assets—
	Zion Station decommissioning	29				29				—				—			—
	Regulatory offset to decommissioning trust	(358		)		(358		)		—				—			—
	fund-related activities (b)
	Total decommissioning-related activities	360				360				—				—			—
	Investment income	1				1				—				(1		)	7			(c)
	Long-term lease income	24				—				—				—			—
	Interest income related to uncertain income tax	40				54				—				—			—
	positions
	AFUDC—Equity	21				—				3				6			12
	Other	9				(9		)		14				2			(1		)
	Other, net	$	455			$	406			$	17			$	7		$	18
	For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust
	funds (a)—
	Regulatory agreement units	$	256			$	256			$	—			$	—		$	—
	Non-regulatory agreement units	77				77				—				—			—
	Net unrealized gains on decommissioning trust
	funds—
	Regulatory agreement units	406				406				—				—			—
	Non-regulatory agreement units	146				146				—				—			—
	Net unrealized gains on pledged assets—
	Zion Station decommissioning	7				7				—				—			—
	Regulatory offset to decommissioning trust	(546		)		(546		)		—				—			—
	fund-related activities (b)
	Total decommissioning-related activities	346				346				—				—			—
	Investment income	8				(1		)		—				(1		)	9			(c)
	Long-term lease income	28				—				—				—			—
	Interest income related to uncertain income tax	24				4				—				—			—
	positions
	AFUDC—Equity	22				—				11				4			7
	Other	32				6				15				3			1
	Other, net	$	460			$	355			$	26			$	6		$	17
	For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning
	trust funds (a)—
	Regulatory agreement units	$	189			$	189			$	—			$	—		$	—
	Non-regulatory agreement units	102				102				—				—			—
	Net unrealized losses on decommissioning
	trust funds—
	Regulatory agreement units	386				386				—				—			—
	Non-regulatory agreement units	105				105				—				—			—
	Net unrealized gains on pledged assets—
	Zion Station decommissioning	73				73				—				—			—
	Regulatory offset to decommissioning trust	(530		)		(530		)		—				—			—
	fund-related activities (b)
	Total decommissioning-related activities	325				325				—				—			—
	Investment income	20				3				1				2			11			(c)
Long-term lease income	29				—				—				—			—
Interest income related to uncertain income tax	15				2				20				—			—
positions
AFUDC—Equity	17				—				6				4			10
Credit Facility termination fees	(85		)		(85		)		—				—			—
Other	32				1				12				2			2
Other, net	$	353			$	246			$	39			$	8		$	23
_________________________
(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 for additional information regarding the accounting for nuclear decommissioning.
(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.
Components of depreciation, amortization and accretion, and other, net	The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012.
	For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
	Depreciation, amortization, accretion and
	depletion
	Property, plant and equipment	$	2,080			$	922			$	588			$	227		$	288
	Regulatory assets	191				—				99				9			83
	Amortization of intangible assets, net	44				44				—				—			—
	Amortization of energy contract assets and	135				135				—				—			—
	liabilities (a)
	Nuclear fuel (b)	1,073				1,073				—				—			—
	ARO accretion (c)	345				345				—				—			—
	Total depreciation, amortization, accretion and	$	3,868			$	2,519			$	687			$	236		$	371
	depletion
	For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
	Depreciation, amortization, accretion and
	depletion
	Property, plant and equipment	$	1,893			$	813			$	545			$	219		$	264
	Regulatory assets	212				—				119				9			84
	Amortization of intangible assets, net	48				43				5				—			—
	Amortization of energy contract assets and	430				507				—				—			—
	liabilities (a)
	Nuclear fuel (b)	921				921				—				—			—
	ARO accretion (c)	275				275				—				—			—
	Total depreciation, amortization, accretion and	$	3,779			$	2,559			$	669			$	228		$	348
	depletion
	For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
	Depreciation, amortization, accretion and
	depletion
	Property, plant and equipment	$	1,712			$	733			$	525			$	207		$	245
	Regulatory assets	129				—				80				10			53
	Amortization of intangible assets, net	40				35				5				—			—
	Amortization of energy contract assets and	1,110				1,110				—				—			—
	liabilities (a)
	Nuclear fuel (b)	848				848				—				—			—
	ARO accretion (c)	240				240				—				—			—
	Total depreciation, amortization and accretion	$	4,079			$	2,966			$	610			$	217		$	298
	________________________
	(a)	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
	(b)	Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
	(c)	Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Schedule of Cash Flow, Supplemental Disclosure
	For the year ended December 31, 2014	Exelon				Generation				ComEd				PECO			BGE
	Cash paid (refunded) during the year:
	Interest (net of amount capitalized)	$	940			$	322			$	292			$	94		$	111
	Income taxes (net of refunds)	$	314			227				(6		)		85			(21		)
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit	$	560			$	249			162				$	36		$	64
	costs
	Loss from equity method investments	22				20				—				—			—
	Provision for uncollectible accounts	156				14				26				52			64
	Provision for excess and obsolete inventory	5				5				—				—			—
	Stock-based compensation costs	91				—				—				—			—
	Other decommissioning-related activity (a)	(132		)		(132		)		—				—			—
	Energy-related options (b)	122				122				—				—			—
	Amortization of regulatory asset related to debt	11				—				8				3			—
	costs
	Amortization of rate stabilization deferral	65				—				—				—			65
	Amortization of debt fair value adjustment	(23		)		(23		)		—				—			—
	Merger-related commitments	44				44				—				—			—
	Amortization of debt costs	53				12				4				2			2
	Discrete impacts from EIMA (c)	53				—				53				—			—
	Lower of cost or market inventory adjustment	29				29				—				—			—
	Other	(2		)		6				2				(1		)	(15		)
	Total other non-cash operating activities	$	1,054			$	346			$	255			$	92		$	180
	Changes in other assets and liabilities:
	Under/over-recovered energy and transmission	$	47			$	—			$	36			$	—		$	11
	costs
	Other regulatory assets and liabilities	(167		)		—				(13		)		(16		)	(121		)
	Cash deposits (d)	(241		)		(241		)		—				—			—
	Other current assets	7				81				(10		)		(2		)	(44		)
	Other noncurrent assets and liabilities	(204		)		(89		)		32				1			(9		)
	Total changes in other assets and liabilities	$	(558	)		$	(249	)		$	45			$	(17	)	$	(163	)
	Non-cash investing and financing activities:
	Change in ARC	$	72			$	72			$	—			$	—		$	—
	Change in capital expenditures not paid	220				(61		)	(e)	78				—			25
	Fair value of net assets recorded upon CENG	(3,400		)		(3,400		)		—				—			—
	consolidation (f)
	Issuance of equity units (g)	131				—				—				—			—
	Nuclear fuel procurement (h)	70				70				—				—			—
	Indemnification of like-kind exchange position (i)	—				—				5				—			—
	____________________________
	(a)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
	(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
	(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters for more information.
	(d)	Relates primarily to cash deposits made to ISO's/RTO's.
	(e)	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.
	(f)	See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
	(g)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19 — Common Stock for additional information.
	(h)	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.
	(i)	See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.
	For the year ended December 31, 2013	Exelon				Generation				ComEd				PECO			BGE
	Cash paid (refunded) during the year:
	Interest (net of amount capitalized)	$	866			$	291			$	283			$	95		$	130
	Income taxes (net of refunds)	112				(18		)		33				70			42
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	825			$	345			$	308			$	43		$	56
	Gain from equity method investments	(10		)		(10		)		—				—			—
	Provision for uncollectible accounts	101				10				(15		)		61			44
	Provision for excess and obsolete inventory	9				9				—				—			—
	Stock-based compensation costs	120				—				—				—			—
	Other decommissioning-related activity (a)	(169		)		(169		)		—				—			—
	Energy-related options (b)	104				104				—				—			—
	Amortization of regulatory asset related to debt	12				—				9				3			—
	costs
Amortization of rate stabilization deferral	66				—				—				—			66
Amortization of debt fair value adjustment	(34		)		(34		)		—				—			—
Discrete impacts from EIMA (c)	(271		)		—				(271		)		—			—
Amortization of debt costs	18				10				1				2			2
Other	(53		)		5				(4		)		(1		)	(15		)
Total other non-cash operating activities	$	718			$	270			$	28			$	108		$	153
Changes in other assets and liabilities:
Under/over-recovered energy and transmission	$	12			$	—			$	(35	)		$	9		$	38
costs
Other regulatory assets and liabilities	(64		)		—				(43		)		(16		)	(71		)
Other current assets	(165		)		(151		)		51				13			(8		)
Other noncurrent assets and liabilities	322				15				268			(d)	(12		)	(23		)
Total changes in other assets and liabilities	$	105			$	(136	)		$	241			$	(6	)	$	(64	)
Non-cash investing and financing activities:
Change in ARC	$	(128	)		$	(128	)		$	—			$	—		$	4
Change in capital expenditures not paid	(38		)		(107		)	(e)	(8		)		13			(48		)
Consolidated VIE dividend to noncontrolling interest	63				63				—				—			—
Indemnification of like-kind exchange position (f)	—				—				176				—			—
______________________
(a)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(b)	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters for more information.
(d)	Relates primarily to interest payable related to like-kind exchange tax position. See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.
(e)	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.
(f)	See Note 14 — Income Taxes for discussion of the like-kind exchanged tax position.
For the year ended December 31, 2012	Exelon				Generation				ComEd				PECO			BGE
Cash paid (refunded) during the year:
Interest (net of amount capitalized)	$	761			$	286			$	288			$	113		$	136
Income taxes (net of refunds)	(171		)		175				(42		)		(64		)	(112		)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	820			$	341			$	282			$	50		$	57
Earnings from equity method investments	91				91				—				—			—
Provision for uncollectible accounts	164				22				42				60			44
Provision for excess and obsolete inventory	6				6				1				—			—
Stock-based compensation costs	94				—				—				—			—
Other decommissioning-related activity (a)	(145		)		(145		)		—				—			—
Energy-related options (b)	160				160				—				—			—
Amortization of regulatory asset related to debt costs	18				—				13				3			2
Amortization of rate stabilization deferral	57				—				—				—			67
Amortization of debt fair value adjustment	(34		)		(34		)		—				—			—
Merger-related commitments (c)	141				32				—				—			27
Severance costs	99				34				—				—			—
Discrete impacts from EIMA (d)	(96		)		—				(96		)		—			—
Amortization of debt costs	19				11				5				3			2
Other	(30		)		—				5				9			(6		)
Total other non-cash operating activities	$	1,364			$	518			$	252			$	125		$	193
Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	71			$	—			$	28			$	20		$	26
Other regulatory assets and liabilities	(404		)		$	—			(68		)		18			(112		)
Other current assets	213				(30		)		33				(12		)	(7		)
Other noncurrent assets and liabilities	(248		)		(98		)		(95		)		(10		)	8
Total changes in other assets and liabilities	$	(368	)		$	(128	)		$	(102	)		$	16		$	(85	)
Non-cash investing and financing activities:
Change in ARC	$	781			$	781			$	2			$	—		$	—
Change in capital expenditures not paid	160				103			(e)	15				26			(4		)
Consolidated VIE dividend to noncontrolling interest	7,365				5,264				—				—			—
_________________________
(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 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)	Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments.
(d)	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters.
(e)	Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley.
Investments	The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2014 and 2013.
	31-Dec-14	Exelon				Generation				ComEd				PECO			BGE
	Investments
	Equity method investments:
	Financing trusts (a)	$	22			$	—			$	6			$	8		$	8
	Bloom Energy	13				13				—				—			—
	Net Power	9				9				—				—			—
	Sunnyside	5				5				—				—			—
	Other equity method investments	1				1				—				—			—
	Total equity method investments	50				28				6				8			8
	Other investments:
	Net investment in leases	367				7				—				—			—
	Employee benefit trusts and investments (b)	85				27				—				23			4
	Other investments (c)	42				42				—				—			—
	Total investments	$	544			$	104			$	6			$	31		$	12
	31-Dec-13	Exelon				Generation				ComEd				PECO			BGE
	Investments
	Equity method investments:
	Financing trusts (a)	$	22			$	—			$	6			$	8		$	8
	Keystone Fuels, LLC	32				32				—				—			—
	Conemaugh Fuels, LLC	21				21				—				—			—
	CENG	1,925				1,925				—				—			—
	Safe Harbor	285				285				—				—			—
	Malacha	8				8				—				—			—
	Other equity method investments	2				2				—				—			—
	Total equity method investments	2,295				2,273				6				8			8
	Other investments:
	Net investment in leases	705				7				—				—			—
	Employee benefit trusts and investments (b)	90				23				5				23			5
	Other investments (c)	22				22				—				—			—
	Total investments	$	3,112			$	2,325			$	11			$	31		$	13
	_________________________
	(a)	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.
	(b)	The Registrants’ investments in these marketable securities are recorded at fair market value.
	(c)	Includes cost method and available-for-sale investments.
Accrued Liabilities Current	The following tables provide additional information about liabilities of the Registrants at December 31, 2014 and 2013.
	31-Dec-14	Exelon				Generation				ComEd				PECO			BGE
	Accrued expenses
	Compensation-related accruals (a)	$	832			$	447			$	153			$	50		$	58
	Taxes accrued	305				248				59				3			42
	Interest accrued	240				66				102				33			29
	Severance accrued	49				33				2				1			2
	Other accrued expenses	113			(b)	92			(b)	15				4			—
	Total accrued expenses	$	1,539			$	886			$	331			$	91		$	131
	31-Dec-13	Exelon				Generation				ComEd				PECO			BGE
	Accrued expenses
	Compensation-related accruals (a)	$	683			$	337			$	135			$	47		$	55
	Taxes accrued	315				212				62				24			16
	Interest accrued	234				72				95				32			29
	Severance accrued	66				31				3				1			4
	Other accrued expenses	335			(b)	324			(b)	12				2			7
	Total accrued expenses	$	1,633			$	976			$	307			$	106		$	111
	_______________________
	(a)	Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
	(b)	Includes $19 million and $228 million for amounts accrued related to Antelope Valley as of December 31, 2014 and December 31, 2013, respectively.

Segment_Information_Tables

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
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 years ended December 31, 2014, 2013, and 2012 is as follows:
		Generation (a)			ComEd			PECO			BGE (b)			Other (c)			Intersegment			Exelon
																	Eliminations
	Operating revenues(d):
	2014	$	17,393		$	4,564		3,094			$	3,165		$	1,285		$	(2,072	)	$	27,429
	2013	15,630			4,464			3,100			3,065			1,241			(2,612		)	24,888
	2012	14,437			5,443			3,186			2,091			1,396			(3,064		)	23,489
	Intersegment revenues(e):
	2014	$	762		$	4		$	2		$	25		$	1,280		$	(2,067	)	$	6
	2013	1,367			3			1			13			1,237			(2,607		)	14
	2012	1,660			2			3			9			1,381			(3,049		)	6
	Depreciation and amortization
	2014	$	967		$	687		$	236		$	371		$	53		$	—		$	2,314
	2013	856			669			228			348			52			—			2,153
	2012	768			610			217			238			48			—			1,881
	Operating expenses (d):
	2014	$	16,923		$	3,586		$	2,522		$	2,726		$	1,353		$	(2,071	)	$	25,039
	2013	13,976			3,510			2,434			2,616			1,324			(2,618		)	21,242
	2012	13,226			4,557			2,563			2,053			1,662			(3,043		)	21,018
	Equity in earnings (losses) of
	unconsolidated affiliates
	2014	$	(20	)	$	—		$	—		$	—		$	—		$	—		$	(20	)
	2013	10			—			—			—			—			—			10
	2012	(91		)	—			—			—			—			—			(91		)
	Interest expense, net:
	2014	$	356		$	321		$	113		$	106		$	169		$	—		$	1,065
	2013	357			579			115			122			183			—			1,356
	2012	301			307			123			111			86			—			928
	Income (loss) before income
	taxes:
	2014	$	1,226		$	676		$	466		$	351		$	(227	)	$	(6	)	$	2,486
	2013	1,675			401			557			344			(191		)	(13		)	2,773
	2012	1,058			618			508			(54		)	(325		)	(7		)	1,798
	Income taxes:
	2014	$	207		$	268		$	114		$	140		$	(63	)	$	—		$	666
	2013	615			152			162			134			(20		)	1			1,044
	2012	500			239			127			(23		)	(215		)	(1		)	627
	Net income (loss):
	2014	$	1,019		$	408		$	352		$	211		$	(164	)	$	(6	)	$	1,820
	2013	1,060			249			395			210			(171		)	(14		)	1,729
	2012	558			379			381			(31		)	(110		)	(6		)	1,171
	Capital expenditures:
	2014	$	3,012		$	1,689		$	661		$	620		$	95		$	—		6,077
	2013	2,752			1,433			537			587			86			—			5,395
	2012	3,554			1,246			422			500			67			—			5,789
	Total assets:
	2014	$	45,348		$	25,392		$	9,943		$	8,078		$	9,794		$	(11,741	)	$	86,814
	2013	41,232			24,118			9,617			7,861			8,317			(11,221		)	79,924
	__________________________
	(a)	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012, intersegment revenues for Generation include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.
	(b)	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014.
	(c)	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
	(d)	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
	(e)	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Analysis and reconciliation of reportable segment revenues for Generation	As of April 1, 2014, Generation total revenues and Generation total revenues net of purchased power and fuel expense includes 100% of the activity from CENG.
		2014									2013									2012
		Revenues			Intersegment			Total			Revenues			Intersegment			Total			Revenues			Intersegment			Total
		from			revenues			Revenues			from			revenues			Revenues			from			revenues			Revenues
		external									external									external
		customers (a)									customers (a)									customers (a)
	Mid-Atlantic	$	5,265		$	(6	)	$	5,259		$	5,182		$	22		$	5,204		$	5,082		$	(44	)	$	5,038
	Midwest	4,467			8			4,475			4,280			(10		)	4,270			4,824			24			4,848
	New England	1,417			5			1,422			1,245			(8		)	1,237			1,048			45			1,093
	New York	843			—			843			735			(21		)	714			582			(25		)	557
	ERCOT	938			(3		)	935			1,222			(6		)	1,216			1,365			2			1,367
	Other Regions (b)	1,319			(10		)	1,309			946			22			968			755			78			833
	Total Revenues	$	14,249		$	(6	)	$	14,243		$	13,610		$	(1	)	$	13,609		$	13,656		$	80		$	13,736
	for Reportable Segments
	Other (c)	3,144			6			3,150			2,020			1			2,021			781			(80		)	701
	Total	$	17,393		$	—		$	17,393		$	15,630		$	—		$	15,630		$	14,437		$	—		$	14,437
	Generation Consolidated Operating Revenues
	_______________________
	(a)	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
	(b)	Other regions include the South, West and Canada, which are not considered individually significant.
	(c)	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 $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues.
Reconciliation of revenues from segments to consolidated	Generation total revenues net of purchased power and fuel expense:
		2014									2013									2012
		RNF from			Intersegment			Total			RNF from			Intersegment			Total			RNF from			Intersegment			Total
		external			RNF			RNF			external			RNF			RNF			external			RNF			RNF
		customers (a)									customers (a)									customers (a)
	Mid-Atlantic	$	3,466		$	(49	)	$	3,417		$	3,273		$	(3	)	$	3,270		$	3,477		$	(44	)	$	3,433
	Midwest	2,580			14			2,594			2,585			1			2,586			2,974			24			2,998
	New England	432			(81		)	351			217			(32		)	185			151			45			196
	New York	457			26			483			14			(18		)	(4		)	101			(25		)	76
	ERCOT	573			(256		)	317			604			(168		)	436			403			2			405
	Other Regions (b)	611			(284		)	327			334			(133		)	201			53			78			131
	Total Revenues net of	$	8,119		$	(630	)	$	7,489		$	7,027		$	(353	)	$	6,674		$	7,159		$	80		$	7,239
	purchased power and fuel expense for Reportable Segments
	Other (c)	(651		)	630			(21		)	406			353			759			217			(80		)	137
	Total Generation	$	7,468		$	—		$	7,468		$	7,433		$	—		$	7,433		$	7,376		$	—		$	7,376
	Revenues net of purchased power and fuel expense
	____________________________
	(a)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
	(b)	Other regions include the South, West and Canada, which are not considered individually significant.
	(c)	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 $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.

Related_Party_Transactions_Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2014
Related Party Transactions [Abstract]
Related Party Transactions Income Statement Disclosure	The financial statements of PECO include related party transactions as presented in the tables below:
		For the Years Ended
		December 31,
		2014			2013		2012
	Operating revenues from affiliates:
	Generation (a)	$	2		$	1	$	3
	Purchased power from affiliate
	Generation (b)	$	194		$	392	$	533
	Operating and maintenance from affiliates:
	BSC (c)	$	96		$	98	$	107
	Generation	3			3		4
	Total operating and maintenance from affiliates	$	99		$	101	$	111
	Interest expense to affiliates, net:
	PECO Trust III	$	6		$	6	$	6
	PECO Trust IV	6			6		6
	Total interest expense to affiliates, net	$	12		$	12	$	12
	Capitalized costs
	BSC (c)	$	39		$	46	$	54
	Cash dividends paid to parent	$	320		$	332	$	343
	Contribution from parent	$	24		$	27	$	9
	The financial statements of Generation include related party transactions as presented in the tables below:
		For the Years Ended
		December 31,
		2014			2013		2012
	Operating revenues from affiliates:
	ComEd (a)	$	176		$	506	$	795
	PECO (b)	198			405		543
	BGE (c)	387			455		322
	CENG (d)	17			56		42
	BSC	1			1		—
	Total operating revenues from affiliates	$	779		$	1,423	$	1,702
	Purchase power and fuel from affiliates:
	ComEd	$	1		$	1	$	—
	BGE	25			13		8
	CENG (e)	282			992		793
	Keystone Fuels, LLC (i)	138			144		119
	Conemaugh Fuels, LLC (i)	99			98		101
	Safe Harbor Water Power Corporation (i)	12			22		23
	Total purchase power and fuel from affiliates	$	557		$	1,270	$	1,044
	Operating and maintenance from affiliates:
	ComEd (f)	$	3		$	2	$	2
	PECO (f)	2			1		3
	BSC (g)	618			571		625
	Total operating and maintenance from affiliates	$	623		$	574	$	630
	Interest expense to affiliates, net:
	Exelon Corporate	$	53		$	59	$	75
	Earnings (losses) in equity method investments
	CENG (h)	$	(19	)	$	9	$	(99	)
	Qualifying facilities and domestic power projects	(1		)	1		8
	Total earnings (losses) in equity method investments	$	(20	)	$	10	$	(91	)
	Capitalized costs
	BSC (g)	$	91		$	93	$	80
	Cash distribution paid to member	$	645		$	625	$	1,626
	Contribution from member	$	53		$	26	$	48
	The financial statements of BGE include related party transactions as presented in the tables below:
		For the Years Ended
		December 31,
		2014			2013		2012
	Operating revenues from affiliates:
	Generation (a)	$	25		$	13	$	10
	Purchased power from affiliate
	Generation (b)	$	382		$	452	$	396
	Operating and maintenance from affiliates:
	BSC (c)	$	103		$	83	$	106
Interest expense to affiliates, net:
BGE Capital Trust II	$	16		$	16	$	16
Capitalized costs
BSC (c)	$	19		$	15	$	21
Contribution from parent	$	—		$	—	$	66
The financial statements of ComEd include related party transactions as presented in the tables below:
	For the Years Ended
	December 31,
	2014			2013		2012
Operating revenues from affiliates
Generation	$	4		$	3	$	2
Purchased power from affiliate
Generation (a)	$	176		$	512	$	789
Operating and maintenance from affiliate
BSC (b)	$	166		$	157	$	163
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13	$	13
Capitalized costs
BSC (b)	$	77		$	69	$	92
Cash dividends paid to parent	$	307		$	220	$	105
Contribution from parent	$	273		$	—	$	11
The financial statements of Exelon include related party transactions as presented in the tables below:
	For the Years Ended
	December 31,
	2014			2013		2012
Operating revenues from affiliates:
PECO (a)	$	1		$	10	$	6
CENG (b)	17			56		42
BGE (a)	5			4		—
Total operating revenues from affiliates	$	23		$	70	$	48
Purchase power and fuel from affiliates:
CENG (c)	$	282		$	992	$	793
Keystone Fuels, LLC (d)	138			144		119
Conemaugh Fuels, LLC (d)	99			98		101
Safe Harbor Water Power Corp (d)	12			22		23
Total purchase power and fuel from affiliates	$	531		$	1,256	$	1,036
Interest expense to affiliates, net:
ComEd Financing III	$	13		$	13	$	13
PECO Trust III	6			6		6
PECO Trust IV	6			6		6
BGE Capital Trust II (f)	16			16		12
Total interest expense to affiliates, net	$	41		$	41	$	37
Earnings (losses) in equity method investments:
CENG (e)	$	(19	)	$	9	$	(99	)
Qualifying facilities and domestic power projects	(1		)	1		8
Total earnings (losses) in equity method investments	$	(20	)	$	10	$	(91	)
Related Party Transactions Balance Sheet Disclosure
		December 31,
		2014			2013
	Prepaid voluntary employee beneficiary association trust (c)	$	13		$	13
	Receivable from affiliates (current):
	Voluntary employee beneficiary association trust	$	2		$	3
	Generation	12			—
	Total receivable from affiliates (current)	$	14		$	3
	Receivable from affiliates (noncurrent):
	Generation (d)	$	2,389		$	2,293
	Exelon Corporate (e)	182			176
	Total receivable from affiliates (noncurrent)	$	2,571		$	2,469
	Payables to affiliates (current):
	Generation (a)	$	43		$	38
	BSC (b)	32			30
	ComEd Financing III	4			4
	PECO	2			—
	Exelon Corporate	3			9
	Other	—			2
	Total payables to affiliates (current)	$	84		$	83
	Long-term debt to ComEd financing trust
	ComEd Financing III	$	206		$	206
	_______________________
	(a)	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information.
	(b)	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
	(c)	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
	(d)	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.
	(e)	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.
		December 31,
		2014			2013
	Receivables from affiliates (current):
	CENG (d)	$	—		$	3
	ComEd (a)	43			38
	PECO (b)	29			38
	BGE (c)	40			27
	Other	1			2
	Total receivables from affiliates (current)	$	113		$	108
	Long-term debt due to affiliates (current):
	Exelon Corporate (l)	556			—
	Payables to affiliates (current):
	CENG (e)	$	—		$	85
	Exelon Corporate (j)	12			7
	BSC (g)	83			66
	ComEd	12			—
	Keystone Fuels, LLC (i)	—			12
	Conemaugh Fuels, LLC (i)	—			9
	Other	—			2
	Total payables to affiliates (current)	$	107		$	181
	Long-term debt due to affiliates (noncurrent):
	Exelon Corporate (l)	943			1,523
	Payables to affiliates (noncurrent):
	BSC (g)	$	1		$	—
	ComEd (k)	2,389			2,293
	PECO (k)	490			447
	Total payables to affiliates (noncurrent)	$	2,880		$	2,740
	_______________________
	(a)	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
	(b)	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
	(c)	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
	(d)	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
	(e)	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
	(f)	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
	(g)	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
	(h)	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(i)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
(j)	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.
(k)	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations.
(l)	In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term Debt to affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets.
	December 31,
	2014			2013
Prepaid voluntary employee beneficiary association trust (d)	$	1		$	1
Payables to affiliates (current):
Generation (b)	$	40		$	27
BSC (c)	17			20
Exelon Corporate	5			1
PECO	1			3
BGE Capital Trust II	3			4
Total payables to affiliates (current)	$	66		$	55
Long-term debt to BGE financing trust
BGE Capital Trust II	$	258		$	258
______________________
(a)	BGE provides energy to Generation for Generation’s own use.
(b)	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
(c)	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(d)	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
	December 31,
	2014			2013
Receivables from affiliates (current):
CENG (b)	$	—		$	3
Payables to affiliates (current):
CENG (c)	$	—		$	85
ComEd Financing III	4			4
PECO Trust III	1			1
BGE Capital Trust II	3			4
Keystone Fuels, LLC (d)	—			12
Conemaugh Fuels, LLC (d)	—			9
Other	—			1
Total payables to affiliates (current)	$	8		$	116
Long-term debt due to financing trusts:
ComEd Financing III	$	206		$	206
PECO Trust III	81			81
PECO Trust IV	103			103
BGE Capital Trust II	258			258
Total long-term debt due to financing trusts	$	648		$	648
____________________________
(a)	The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.
(b)	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(c)	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(d)	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
(e)	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(f)	The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012.
	December 31,
	2014			2013
Prepaid voluntary employee beneficiary association trust (d)	$	3		$	3
Receivable from affiliate (current):
ComEd	$	2		$	—
BGE	1			3
Total receivable from affiliates (current)	$	3		$	3
Receivable from affiliate (noncurrent):
Generation (e)	$	490		$	447
Payables to affiliates (current):
Generation (b)	$	29		$	38
BSC (c)	20			17
Exelon Corporate	2			2
PECO Trust III	1			1
Total payables to affiliates (current)	$	52		$	58
Long-term debt to financing trusts:
PECO Trust III	$	81		$	81
PECO Trust IV	103			103
Total long-term debt to financing trusts	$	184		$	184
________________________
(a)	PECO provides energy to Generation for Generation’s own use.
(b)	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.
(c)	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(d)	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.
(e)	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.

Quarterly_Data_Unaudited_Table

Quarterly Data (Unaudited) (Tables)	12 Months Ended
	Dec. 31, 2014
Quarterly Financial Data [Line Items]
Quarterly Financial Information	The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating Income								Net (Loss) Income
																	on Common
																	Stock
		2014			2013				2014				2013				2014				2013
	Quarter ended:
	31-Mar	$	7,237		$	6,082			$	168		(a)	$	513		(b)	$	90			$	(4	)	(c)
	30-Jun	6,024			6,141				842			(a)	1,005				522				490
	30-Sep	6,912			6,502				1,739			(a)	1,262			(b)	993				738
	31-Dec	7,255			6,163				348				889				18			(d)	495
	____________________________
	(a)	In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.
	(b)	In the first and third quarter of 2013, Exelon reclassified $5 million and $8 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.
	(c)	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
	(d)	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Average Basic And Diluted Shares And Net Income Per Basic And Diluted Share
		Average Basic Shares					Net (Loss) Income
		Outstanding					per Basic Share
		(in millions)
		2014		2013			2014				2013
	Quarter ended:
	31-Mar	858		855			$	0.1			$	(0.01	)
	30-Jun	860		856			0.61				0.57
	30-Sep	861		857			1.15				0.86
	31-Dec	861		856			0.02				0.6
		Average Diluted Shares					Net (Loss) Income
		Outstanding					per Diluted Share
		(in millions)
		2014		2013			2014				2013
	Quarter ended:
	31-Mar	861		855			$	0.1			$	(0.01	)
	30-Jun	864		860			0.6				0.57
	30-Sep	863		860			1.15				0.86
	31-Dec	868		860			0.02				0.59
Per Share Information	The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
		2014															2013
		Fourth			Third				Second				First				Fourth				Third				Second		First
		Quarter			Quarter				Quarter				Quarter				Quarter				Quarter				Quarter		Quarter
	High price	$	38.93		$	36.26			$	37.73			$	33.94			$	30.59			$	32.42			$	37.8	$	34.56
	Low price	33.07			30.66				33.11				26.45				26.64				29.42				29.84		29.1
	Close	37.08			34.09				36.48				33.56				27.39				29.64				30.88		34.48
	Dividends	0.31			0.31				0.31				0.31				0.31				0.31				0.31		0.525
Exelon Generation Co L L C [Member]
Quarterly Financial Data [Line Items]
Quarterly Financial Information	The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating (Loss) Income								Net (Loss) Income
																	on Membership
																	Interest
		2014			2013				2014 (a)				2013				2014				2013
	Quarter ended:
	31-Mar	$	4,390		$	3,533			$	(384	)	(a)	$	(59	)	(b)	$	(185	)		$	(18	)
	30-Jun	3,789			4,070				441			(a)	603				340				330
	30-Sep	4,412			4,255				1,225			(a)	729			(b)	771				490
	31-Dec	4,802			3,772				(105		)		405				(91		)		269
	____________________________
	(a)	In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.
	(b)	In the first and third quarter of 2013, Generation reclassified $5 million and $8 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.
Commonwealth Edison Co [Member]
Quarterly Financial Data [Line Items]
Quarterly Financial Information	The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating Income								Net (Loss) Income
		2014			2013				2014				2013				2014				2013
	Quarter ended:
	31-Mar	$	1,134		$	1,160			$	238			$	209			$	98			$	(81	)
	30-Jun	1,128			1,080				259			(a)	232				111				96
	30-Sep	1,222			1,156				288			(a)	278				126				126
	31-Dec	1,079			1,068				196				236				73				109
	____________________________
	(a)	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income.
PECO Energy Co [Member]
Quarterly Financial Data [Line Items]
Quarterly Financial Information	The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating Income								Net Income
																	on Common
																	Stock
		2014			2013				2014				2013				2014				2013
	Quarter ended:
	31-Mar	$	993		$	895			$	149			$	203			$	89			$	121
	30-Jun	656			672				134				138				84				72
	30-Sep	693			728				133				155				81				92
	31-Dec	750			805				156				168				98				102
Baltimore Gas and Electric Company [Member]
Quarterly Financial Data [Line Items]
Quarterly Financial Information	The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
		Operating Revenues							Operating								Net Income
									Income								attributable to
																	Common Shareholders
		2014			2013				2014				2013				2014				2013
	Quarter ended:
	31-Mar	$	1,054		$	880			$	169			$	163			$	85			$	77
	30-Jun	653			653				55				69				16				22
	30-Sep	697			737				102				114				46				50
	31-Dec	761			794				113				101				52				47

Significant_Accounting_Policie3

Significant Accounting Policies - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	100.00%
Percentage ownership of common stock	100.00%
Third Party interest in ComEd (less than $1 million)	$1,332,000,000	$15,000,000
Minimum expectation of tax position to be realized	50.00%
Commonwealth Edison Company [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	99.00%
Third Party interest in ComEd (less than $1 million)	1,000,000	1,000,000
CENG [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	50.01%
RITELine Illinois LLC [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Third Party interest in ComEd (less than $1 million)	1,000,000	1,000,000
Minority interest ownership percentage by parent	12.50%
Exelon Generation Co L L C [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Third Party interest in ComEd (less than $1 million)	1,333,000,000	17,000,000
Ownership interest upper bound	99.00%
Ownership interest	50.01%
Cost of spent nuclear fuel disposal per kWh of net nuclear generation	-0.001
Development costs expensed	$13,000,000	$10,000,000	$4,000,000
Commonwealth Edison Co [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	100.00%
Commonwealth Edison Co [Member] | RITELine Illinois LLC [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Percentage ownership of consolidated subsidiaries	75.00%
Third-party percentage interest in subsidiaries	25.00%
Minimum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	20.00%
Maximum [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Ownership interest	50.00%
Nuclear-Fuel Generating Facilities License Extension [Member] | Exelon Generation Co L L C [Member]
Significant Accounting Policies Additional Narrative Information [Line Items]
Useful life	20 years

Significant_Accounting_Policie4

Significant Accounting Policies - Summary of Capitalized Software Costs (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Capitalized Software [Line Items]
Net unamortized software costs	$596	[1]	$479	[1]
Amortization of capitalized software costs	186	[1],[2]	198	[1],[2]	208	[1],[2]
Exelon Generation Co L L C [Member]
Capitalized Software [Line Items]
Net unamortized software costs	193	[1]	129	[1]
Amortization of capitalized software costs	59	[1],[2]	67	[1],[2]	81	[1],[2]
Commonwealth Edison Co [Member]
Capitalized Software [Line Items]
Net unamortized software costs	133		101
Amortization of capitalized software costs	45		52		56
PECO Energy Co [Member]
Capitalized Software [Line Items]
Net unamortized software costs	84		71
Amortization of capitalized software costs	28		33		30
Baltimore Gas and Electric Company [Member]
Capitalized Software [Line Items]
Net unamortized software costs	163		155
Amortization of capitalized software costs	$43	[2]	$36	[2]	$32	[2]
[1]	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.
[2]	Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.

Significant_Accounting_Policie5

Significant Accounting Policies - Summary of Total Interest Incurred, Capitalized and Credits to AFUDC (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Capitalized Interest And AFUDC [Line Items]
Total interest incurred	$1,144	[1],[2],[3]	$1,423	[1],[2],[3]	$1,003	[1],[2],[3]
Capitalized interest	63	[1],[2]	54	[1],[2]	67	[1],[2]
Credits to AFUDC debt and equity	37	[1],[2]	35	[1],[2]	25	[1],[2]
Exelon Generation Co L L C [Member]
Capitalized Interest And AFUDC [Line Items]
Total interest incurred	419	[1],[2],[3]	411	[1],[2],[3]	368	[1],[2],[3]
Capitalized interest	63	[1],[2]	54	[1],[2]	67	[1],[2]
Credits to AFUDC debt and equity	0	[1],[2]	0	[1],[2]	0	[1],[2]
Commonwealth Edison Co [Member]
Capitalized Interest And AFUDC [Line Items]
Total interest incurred	323	[3]	584	[3]	310	[3]
Capitalized interest	0		0		0
Credits to AFUDC debt and equity	5		16		9
PECO Energy Co [Member]
Capitalized Interest And AFUDC [Line Items]
Total interest incurred	115	[3]	117	[3]	125	[3]
Capitalized interest	0		0		0
Credits to AFUDC debt and equity	8		6		6
Baltimore Gas and Electric Company [Member]
Capitalized Interest And AFUDC [Line Items]
Total interest incurred	118	[1],[3]	129	[1],[3]	149	[1],[3]
Capitalized interest	0	[1]	0	[1]	0	[1]
Credits to AFUDC debt and equity	$24	[1]	$13	[1]	$15	[1]
[1]	Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.
[2]	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.
[3]	Includes interest expense to affiliates.

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)	12 Months Ended	0 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Apr. 01, 2014	Dec. 31, 2013	Dec. 31, 2012
	VIE
Variable Interest Entity, Not Primary Beneficiary, Disclosures [Abstract]
Number of variable interest entities not consolidated by equity holders	6		8
Number of variable interest entities consolidated	6		4
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided	$75
Required purchases of power from CENG's nuclear plants not sold to third parties	85.00%
Purchase of nuclear output by EDF	49.99%
Guarantee obligations maximum exposure	9,402
Other Severance Charges [Member]
Consolidated Variable Interest Entity [Abstract]
Severance charges recorded	6
Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]
Consolidated Variable Interest Entity [Abstract]
Guarantee obligations maximum exposure		165
Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]
Consolidated Variable Interest Entity [Abstract]
Due to affiliate		245
Exelon Generation Co L L C [Member]
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided	5
Ownership Percentage Of Consolidated Variable Interest Entities	100.00%
Debt and Capital Lease Obligations	7,652		7,168
Wind project entities with noncontrolling equity interests	9
Noncontrolling equity interest ownership percentage held by third parties	1.00%
Number of projects with significant economic power	8
Ownership interests in project entities	99.00%
Ownership interest	50.01%
Required purchases of power from CENG's nuclear plants not sold to third parties	85.00%	85.00%
Severance charges recorded	3
Purchase of nuclear output by EDF		49.99%
Guarantee obligations maximum exposure	6,384
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]
Consolidated Variable Interest Entity [Abstract]
Due from affiliates	400	400
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]
Consolidated Variable Interest Entity [Abstract]
Due to affiliate		205
Exelon Generation Co L L C [Member] | Solar Project Limited Liability Companies [Member]
Consolidated Variable Interest Entity [Abstract]
Business Acquisitions, Megawatts Acquired	242
Ownership Percentage Of Consolidated Variable Interest Entities	100.00%
Debt and Capital Lease Obligations	642
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided	7	7
Remeasurement gain from derecognition of equity method investment		261
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member] | Equity Method Investment Variable Interest Entities [Member]
Consolidated Variable Interest Entity [Abstract]
Parental guarantee provided	637
Baltimore Gas and Electric Company [Member]
Consolidated Variable Interest Entity [Abstract]
Debt and Capital Lease Obligations			2,011
Guarantee obligations maximum exposure	265
Baltimore Gas and Electric Company [Member] | RSB Bond Co LLC [Member]
Consolidated Variable Interest Entity [Abstract]
Remittance of payments received from customers for rate stabilization to BondCo.	$85		$83	$85

Variable_Interest_Entities_Car

Variable Interest Entities - Carrying Amounts and Classification of Consolidated VIE Assets and Liabilities (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Variable Interest Entity [Line Items]
Current assets	$1,271	[1],[2]	$484	[1]
Noncurrent assets	7,580	[1],[2]	1,905	[1]
Total assets	8,851	[1],[2]	2,389	[1]
Current liabilities	611	[1],[2]	566	[1]
Noncurrent liabilities	2,730	[1],[2]	774	[1]
Total liabilities	3,341	[1],[2]	1,340	[1]
Assets	86,814	[3]	79,924	[3]
Liabilities	62,681	[3]	56,984	[3]
Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Assets	6,100
Liabilities	2,100
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Current assets	1,242	[2]	446
Noncurrent assets	7,566	[2]	1,884
Total assets	8,808	[2]	2,330
Current liabilities	526	[2]	481
Noncurrent liabilities	2,600	[2]	562
Total liabilities	3,126	[2]	1,043
Assets	45,348	[4]	41,232	[4]
Liabilities	31,297	[4]	28,490	[4]
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Current assets	21		28
Noncurrent assets	3		3
Total assets	24		31
Current liabilities	77		74
Noncurrent liabilities	120		195
Total liabilities	197		269
Assets	8,078	[5]	7,861	[5]
Liabilities	$5,325	[5]	$5,306	[5]
[1]	Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
[2]	Includes total assets of $6.1 billion and total liabilities of $2.1 billion due to the consolidation of CENG. See Note 5— Investment in Constellation Energy Nuclear Group, LLC for additional information.
[3]	Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[4]	Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[5]	BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

Variable_Interest_Entities_Ass

Variable Interest Entities - Assets and Liabilities of VIEs which Creditors or Beneficiaries have No Recourse (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
In Millions, unless otherwise specified
Variable Interest Entity [Line Items]
Cash and cash equivalents	$1,878		$1,609		$1,486	$1,016
Customer	3,482		2,981
Other	1,227		1,175
Mark-to-market derivative assets	1,279		727
Materials and supplies	1,024		829
Other current assets	865		652
Total current assets	12,097		10,137
Property, plant and equipment, net	52,087		47,330
Nuclear decommissioning trust funds	10,537		8,071
Goodwill	2,672		2,625
Mark-to-market derivative assets	773		607
Other noncurrent assets	1,160		964
Total deferred debits and other assets	22,630		22,457
Total assets	86,814	[1]	79,924	[1]
Long-term debt due within one year	1,802		1,509
Accounts payable	3,048		2,484
Accrued expenses	1,539		1,633
Mark-to-market derivative liabilities	234		159
Energy Marketing Contract Liabilities, Current	238		261
Other current liabilities	1,123		858
Total current liabilities	8,762		7,728
Long-term debt	19,362		17,623
Asset retirement obligations	7,295		5,194
Pension obligations	3,366		1,876
Energy Marketing Contract Liabilities, Noncurrent	211		266
Other noncurrent liabilities	2,147		2,540
Total deferred credits and other liabilities	33,909		30,985
Total liabilities	62,681	[1]	56,984	[1]
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	392		62
Restricted cash	117		80
Customer	297		260
Other	57		0
Mark-to-market derivative assets	171		21
Materials and supplies	172		0
Other current assets	33		34
Total current assets	1,239		457
Property, plant and equipment, net	4,638		1,171
Nuclear decommissioning trust funds	2,097		0
Goodwill	47		0
Mark-to-market derivative assets	44		0
Other noncurrent assets	95		127
Total deferred debits and other assets	6,921		1,298
Total assets	8,160		1,755
Long-term debt due within one year	87		85
Accounts payable	292		170
Accrued expenses	111		26
Mark-to-market derivative liabilities	24		29
Energy Marketing Contract Liabilities, Current	22		5
Other current liabilities	25		5
Total current liabilities	561		320
Long-term debt	212		298
Asset retirement obligations	1,763		0
Pension obligations	9	[2]	0	[2]
Energy Marketing Contract Liabilities, Noncurrent	51		28
Other noncurrent liabilities	127		12
Total deferred credits and other liabilities	2,162		338
Total liabilities	2,723		658
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	780		1,258		671	496
Restricted cash	158		71
Customer	2,295		1,689
Other	318		353
Mark-to-market derivative assets	1,276		727
Materials and supplies	847		671
Other current assets	658		491
Total current assets	7,638		6,439
Property, plant and equipment, net	22,945		20,111
Nuclear decommissioning trust funds	10,537		8,071
Goodwill	47		0
Mark-to-market derivative assets	771		600
Other noncurrent assets	731		645
Total deferred debits and other assets	14,765		14,682
Total assets	45,348	[3]	41,232	[3]
Long-term debt due within one year	58		561
Accounts payable	1,759		1,322
Accrued expenses	886		976
Mark-to-market derivative liabilities	214		142
Energy Marketing Contract Liabilities, Current	238		249
Other current liabilities	605		389
Total current liabilities	4,459		3,867
Long-term debt	6,709		5,645
Asset retirement obligations	7,146		5,047
Energy Marketing Contract Liabilities, Noncurrent	211		266
Other noncurrent liabilities	719		811
Total deferred credits and other liabilities	19,186		17,455
Total liabilities	31,297	[3]	28,490	[3]
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	392		62
Restricted cash	96		52
Customer	297		260
Other	57		0
Mark-to-market derivative assets	171		21
Materials and supplies	172		0
Other current assets	26		23
Total current assets	1,211		418
Property, plant and equipment, net	4,638		1,171
Nuclear decommissioning trust funds	2,097		0
Goodwill	47		0
Mark-to-market derivative assets	44		0
Other noncurrent assets	82		106
Total deferred debits and other assets	6,908		1,277
Total assets	8,119		1,695
Long-term debt due within one year	5		5
Accounts payable	292		170
Accrued expenses	108		22
Mark-to-market derivative liabilities	24		29
Energy Marketing Contract Liabilities, Current	22
Other current liabilities	25		5
Total current liabilities	476		236
Long-term debt	81		86
Asset retirement obligations	1,763		0
Pension obligations	9	[2]	0	[2]
Energy Marketing Contract Liabilities, Noncurrent	51		28
Other noncurrent liabilities	127		12
Total deferred credits and other liabilities	2,031		126
Total liabilities	2,507		362
Baltimore Gas and Electric Company [Member]
Variable Interest Entity [Line Items]
Cash and cash equivalents	64		31		89	49
Customer	390		480
Other	82		114
Materials and supplies	30		28
Other current assets	5		7
Total current assets	957		1,011
Property, plant and equipment, net	6,204		5,864
Other noncurrent assets	25		26
Total deferred debits and other assets	917		986
Total assets	8,078	[4]	7,861	[4]
Accounts payable	215		270
Accrued expenses	131		111
Other current liabilities	51		35
Total current liabilities	846		827
Long-term debt	1,867		1,941
Asset retirement obligations	17		19
Other noncurrent liabilities	60		67
Total deferred credits and other liabilities	2,354		2,280
Total liabilities	5,325	[4]	5,306	[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	21		28
Customer	0		0
Other	0		0
Mark-to-market derivative assets	0		0
Materials and supplies	0		0
Other current assets	0		0
Total current assets	21		28
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 deferred debits and other assets	3		3
Total assets	24		31
Long-term debt due within one year	75		70
Accounts payable	0		0
Accrued expenses	2		4
Mark-to-market derivative liabilities	0		0
Energy Marketing Contract Liabilities, Current	0		0
Other current liabilities	0		0
Total current liabilities	77		74
Long-term debt	120		195
Asset retirement obligations	0		0
Pension obligations	0	[2]	0	[2]
Energy Marketing Contract Liabilities, Noncurrent	0		0
Other noncurrent liabilities	0		0
Total deferred credits and other liabilities	120		195
Total liabilities	$197		$269
[1]	Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	Includes the CNEG Retail Gas’ pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generation’s balance sheet. See Note 16—Retirement Benefits for additional details
[3]	Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[4]	BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

Variable_Interest_Entities_Sum

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Variable Interest Entity [Line Items]
Total assets	$597	[1]	$460	[1]
Total liabilities	286	[1]	140	[1]
Our ownership interest	9	[1]	86	[1]
Other ownership interests	302	[1]	234	[1]
Pledged assets for Zion Station decommissioning	319		458
Exelon Generation Co L L C [Member]
Variable Interest Entity [Line Items]
Pledged assets for Zion Station decommissioning	319		458
Payable To Thirdparty To Decommission Nuclear Plant Funded By Pledged Assets	292	[2]	414	[2]
Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	506	[1]	128	[1]
Total liabilities	237	[1]	17	[1]
Our ownership interest	0	[1]	0	[1]
Other ownership interests	269	[1]	111	[1]
Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Total assets	91	[1]	332	[1]
Total liabilities	49	[1]	123	[1]
Our ownership interest	9	[1]	86	[1]
Other ownership interests	33	[1]	123	[1]
Investments [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	13		74
Investments [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	0		7
Investments [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	13		67
Contract Intangible Asset [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	9		9
Contract Intangible Asset [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	9		9
Contract Intangible Asset [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	0		0
Payment Guarantee [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	3		5
Payment Guarantee [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	0		0
Payment Guarantee [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	3		5
Asset Held In Trust Noncurrent [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	27	[3]	44	[3]
Asset Held In Trust Noncurrent [Member] | Commercial Agreement Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	27	[3]	44	[3]
Asset Held In Trust Noncurrent [Member] | Equity Method Investment Variable Interest Entities [Member]
Variable Interest Entity [Line Items]
Our maximum exposure to loss	$0	[3]	$0	[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]	Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
[3]	These items represent amounts on Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets pledged for Zion Station decommissioning includes gross pledged assets of $319 million and $458 million as of December 31, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $292 million and $414 million as of December 31, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.

Regulatory_Matters_Narrative_D

Regulatory Matters - Narrative (Details) (USD $)	1 Months Ended		12 Months Ended		0 Months Ended							1 Months Ended		3 Months Ended	9 Months Ended	12 Months Ended		0 Months Ended					1 Months Ended	0 Months Ended						1 Months Ended	12 Months Ended	60 Months Ended	65 Months Ended	0 Months Ended	1 Months Ended	3 Months Ended	0 Months Ended
	Jan. 31, 2014	Sep. 30, 2008	Dec. 31, 2014	Dec. 31, 2013	Dec. 11, 2014	Apr. 16, 2014	Dec. 19, 2013	Jun. 30, 2013	Apr. 29, 2013	Dec. 19, 2012	Jul. 31, 2012	Apr. 30, 2014	Apr. 30, 2013	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2012	Dec. 31, 2011	Dec. 02, 2013	Mar. 29, 2013	Mar. 15, 2013	Dec. 05, 2012	Aug. 09, 2011	Sep. 30, 2012	Dec. 08, 2014	Oct. 17, 2014	Aug. 23, 2014	Dec. 13, 2013	Feb. 27, 2013	Feb. 22, 2013	Aug. 31, 2010	Dec. 31, 2007	Nov. 30, 2010	Nov. 30, 2005	Apr. 12, 2012	Mar. 31, 2011	Dec. 31, 2014	Jan. 13, 2015	Mar. 31, 2013	Sep. 18, 2014	Apr. 01, 2014	Mar. 31, 2014	Oct. 31, 2013	Apr. 01, 2013	Dec. 20, 2012	Jun. 02, 2011	Aug. 15, 2013	Jun. 19, 2013	Dec. 16, 2010	Jun. 01, 2009	Sep. 15, 2014	Aug. 21, 2014	Jul. 02, 2014	Apr. 28, 2014	Apr. 27, 2014	Feb. 26, 2014	Aug. 23, 2013	Feb. 28, 2010	Jun. 03, 2014
			V	MW														V			MWh									smart_meter																	smart_meter
																		mi
Regulatory Matters Additional Narrative Information [Line Items]
Revenue reduction	$8,000,000
Electric revenues increase order		274,000,000
Substation kilovolt			500,000
Near zero emissions coal fueled generation plant				166
Parent company pension OPEB regulatory assets noncurrent			3,256,000,000																																	3,256,000,000
Noncurrent regulatory assets			6,076,000,000	5,910,000,000																																6,076,000,000
Regulatory liabilities			310,000,000	327,000,000																																310,000,000
Business Combination, Integration Related Costs			19,000,000	28,000,000
Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory liabilities			25,000,000	53,000,000																																25,000,000
Under Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			11,000,000	9,000,000																																11,000,000
Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			159,000,000	148,000,000																																159,000,000
Non-severance Merger Integration Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets				4,000,000
Amortization period			P5Y
Merger Integration Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			5
Noncurrent regulatory assets			6,000,000	9,000,000																																6,000,000
Regulatory asset recovery, period one																																						4,000,000
Regulatory asset recovery, period two																																						4,000,000
Electric Generation Related Regulatory Asset [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			20,000,000	30,000,000																																20,000,000
Deferred Storm Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			2,000,000	3,000,000																																2,000,000
Severance Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			P5Y
Net regulatory assets																35,000,000
Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			120,000,000	285,000,000																																120,000,000
AMI Expenses [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			ten
Noncurrent regulatory assets			271,000,000	159,000,000																																271,000,000
Asset Retirement Obligations [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			115,000,000	102,000,000																																115,000,000
Commonwealth Edison Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Additional revenue requirement allowed by updated government order			88,000,000	35,000,000	232,000,000	269,000,000	341,000,000		353,000,000	73,000,000		22,000,000	68,000,000
Current year revenue adjustment			160,000,000	160,000,000								36,000,000	38,000,000			80,000,000
Prior year revenue adjustment			72,000,000									14,000,000	30,000,000			-181,000,000	-7,000,000
Weighted average debt and equity return					7.06%		6.94%																															8.91%		8.62%	8.70%		8.70%	7.54%
Rate of return on common equity			9.25%				8.72%			9.81%				11.50%
Annual revenue requirement reduction								14,000,000
Contribution to technology innovation trust											15,000,000
Subsequent contribution to technology innovation trust											4,000,000
Utility annual customer assistance											10,000,000
Smart meters installed			550,000
Rate of return on common equity electric distribution		10.30%
Estimated refund obligation to customers																																													37,000,000
Collections under rider AMP			24,000,000																																	24,000,000			9,500,000			14,600,000
Purchased accounts receivables for PORCB			139,000,000																																	139,000,000
Term of contract			20 years
Annual energy savings requirement			0.20%																																	0.20%
Demand response peak demand reduction			2.00%																																	2.00%
Low income sector consumption reduction targets Act 129 Phase II			0.10%
Renewable energy procurement			2.00%																																	2.00%
Noncurrent regulatory assets			852,000,000	933,000,000																																852,000,000
Common equity component cap															55.00%
Regulatory liabilities			125,000,000	170,000,000																																125,000,000
Under over recovered distribution service costs				377,000,000
Customer refundable fees			3,000,000	37,000,000																																3,000,000
Customer refundable fees, interest			1,000,000	1,000,000																																1,000,000
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Under over recovered distribution service costs			286,000,000
Cost recovery for significant one-time events			85,000,000	86,000,000
Commonwealth Edison Co [Member] | Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Renewable energy resources cumulatively increase			10.00%
Commonwealth Edison Co [Member] | Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Renewable energy resources cumulatively increase			25.00%
Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory liabilities			25,000,000	45,000,000																																25,000,000
Commonwealth Edison Co [Member] | Energy Related Derivative [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Term of contract			20 years
Commonwealth Edison Co [Member] | FutureGen Industry Alliance [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Term of contract				20 years
Commonwealth Edison Co [Member] | Northern Illinois Project [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Length of transmission line																		60
Substation kilovolt																		345,000
Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			7,000,000	6,000,000																																7,000,000
Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
Commonwealth Edison Co [Member] | Merger Integration Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets			7,000,000	6,000,000																																7,000,000
Noncurrent regulatory assets			0	0																																0
Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
Commonwealth Edison Co [Member] | Deferred Storm Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
Commonwealth Edison Co [Member] | Transmission Rate Formula [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net regulatory assets			21,000,000	17,000,000																																21,000,000
Commonwealth Edison Co [Member] | Severance Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net regulatory assets																16,000,000
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			120,000,000	285,000,000																																120,000,000
Regulatory assets due to deferred storm costs			66,000,000	58,000,000																																66,000,000
Commonwealth Edison Co [Member] | AMI Expenses [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			81,000,000	35,000,000																																81,000,000
Commonwealth Edison Co [Member] | Asset Retirement Obligations [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net regulatory asset			371,000,000	463,000,000																																371,000,000
Noncurrent regulatory assets			73,000,000	67,000,000																																73,000,000
Commonwealth Edison Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Electric Transmission Costs Under-Recovery			3,000,000																																	3,000,000
Commonwealth Edison Company [Member] | Renewable Energy Program [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			16,000,000	9,000,000																																16,000,000
Commonwealth Edison Company [Member] | Under-Recovered Electric Supply Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Electric Transmission Costs Under-Recovery			4,000,000	35,000,000																																4,000,000
Commonwealth Edison Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			19,000,000																																	19,000,000
Commonwealth Edison Company [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets			33,000,000	58,000,000																																33,000,000
Electric Transmission Costs Under-Recovery			22,000,000	17,000,000																																22,000,000
PECO Energy Co [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Low income sector consumption reduction targets Act 129 Phase II																					4.50%
Increase in electric delivery service revenue resulting from rate case settlement or order.																																																225,000,000
Increase in gas delivery service revenue resulting from rate case settlement or order.																																																20,000,000
Electric distribution tax repairs																						171,000,000
Gas distribution tax repairs refund																							54,000,000
Smart meters initial phase deployment			1,600,000																																	1,600,000
Estimated number of smart meters to be installed			1,700,000																																	1,700,000											600,000
Projected investment in smart meters			583,000,000																																	583,000,000
Projected investment in smart grid infrastructure			155,000,000																																	155,000,000
Total smart grid smart meter investment grant awarded			200,000,000																																	200,000,000
Total smart meter spend on investment			540,000,000																																	540,000,000
Total smart grid spend on investment			119,000,000																																	119,000,000
Smart grid investment grant awarded			60,000,000																																	60,000,000
Smart grid sub recipient investment			4,000,000																																	4,000,000
Smart meter investment grant awarded			140,000,000																																	140,000,000
Carrying value of smart meters excluding DOE reimbursements			17,000,000																																	17,000,000
DOE reimbursements use for original meter installment			16,000,000																																	16,000,000
Depreciation related to original meters			2,000,000
Vendor refund																																														12,000,000
Cost recoveries sought under direct load control program																			12,000,000
Cumulative consumption reduction targets																					1,125,852
Public sector maximum consumption reduction targets Act 129 Phase II																					10.00%
Proposed funding Of direct load control program costs																				10,000,000
Total alternative energy credits purchased annually			452,000
Solar tier 1 alternative energy credits purchased annually			8,000
Noncurrent regulatory assets			1,529,000,000	1,448,000,000																																1,529,000,000
Regulatory liabilities			90,000,000	106,000,000																																90,000,000
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Annual energy savings requirement																																																	3.00%
Demand response peak demand reduction																																																	4.50%
PECO Energy Co [Member] | OverRecoveredNaturalGasSupply [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			16,000,000	16,000,000																																16,000,000
PECO Energy Co [Member] | DSP Program costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			39,000,000	34,000,000																																39,000,000
PECO Energy Co [Member] | Over-Recovered Electric Transmission Cost [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			3,000,000	8,000,000																																3,000,000
PECO Energy Co [Member] | Minimum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Percentage Tier I alternative energy resources																	3.50%
Percentage Tier II alternative energy resources																	6.20%
PECO Energy Co [Member] | Maximum [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Low income sector consumption reduction targets Act 129 Phase II																					2.00%
Percentage Tier I alternative energy resources																	8.00%
Percentage Tier II alternative energy resources																	10.00%
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Maximum civil penalty under Act 129																					20,000,000
PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory liabilities			0	8,000,000																																0
PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
PECO Energy Co [Member] | Merger Integration Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
PECO Energy Co [Member] | Deferred Storm Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
PECO Energy Co [Member] | AMI Expenses [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			P10Y
Noncurrent regulatory assets			62,000,000	58,000,000																																62,000,000
PECO Energy Co [Member] | Asset Retirement Obligations [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			26,000,000	25,000,000																																26,000,000
Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Weighted average debt and equity return																																																					8.53%	8.35%
Rate of return on common equity															11.30%
Increase in electric delivery service revenue resulting from rate case settlement or order.				34,000,000
Increase in gas delivery service revenue resulting from rate case settlement or order.				12,000,000
Estimated number of smart meters to be installed																														2,000,000
Requested increase in electric revenues																									22,000,000				81,000,000																					99,000,000
Requested increase in gas revenues																									38,000,000				32,000,000																							68,000,000
Annual depreciation expense decrease regulated property																									20,000,000
Adjustment to electric revenues increase requested																																																								83,000,000
Public utilities, requested rate increase (decrease), amount																										24,000,000
Requested rate of return on common equity																											9.75%		9.75%
Rate of return common equity gas distribution																											9.60%		9.60%
Total projected smart meter smart grid spend																														480,000,000
Reimbursements received from the DOE																														200,000,000
Noncurrent regulatory assets			510,000,000	524,000,000																																510,000,000
Upfront fee																																																							75
Recurring fee																																																							11
Gross transmission revenue requirement			9,000,000
Transmission revenue true up			5,000,000
Net transmission revenue requirement			14,000,000
Rate of return on common equity in federal energy regulatory committee complaint																								8.80%				8.70%
Customer refund liability			14,000,000																																	14,000,000															13,000,000
Regulatory liabilities			44,000,000	48,000,000																																44,000,000
Smart grid incremental cost			11,000,000
Site contingency, recovery from third party of environmental remediation cost																																1,000,000	5,000,000
Deferred costs, noncurrent																																			16,000,000			8,000,000
Rate cap imposed on public utility subsidiary			15.00%
Deferred purchased power costs																															306,000,000
Environmental costs recognized, recovery credited to expense			65,000,000	66,000,000
Baltimore Gas and Electric Company [Member] | OverRecoveredNaturalGasSupply [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			7,000,000	11,000,000																																7,000,000
Baltimore Gas and Electric Company [Member] | FERC Transmission Complaint [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Public utilities, approved return on equity, percentage																												10.80%
Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory liabilities			0	0																																0
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Electric Revenue [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			7,000,000																																	7,000,000
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Gas Revenue [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities			12,000,000	9,000,000																																12,000,000
Baltimore Gas and Electric Company [Member] | Under-Recovered Electric Revenue Decoupling [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory Liabilities				7,000,000
Baltimore Gas and Electric Company [Member] | Waldorf Project [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Capacity of natural gas fired combined cycle generation plant (in MW)																																		700
Initial term of proposed contract																																		20 years
Baltimore Gas and Electric Company [Member] | Under Recovered Electric Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets			10,000,000																																	10,000,000
Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets			15,000,000	4,000,000																																15,000,000
Noncurrent regulatory assets			4,000,000	3,000,000																																4,000,000
Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			P5Y
Noncurrent regulatory assets			159,000,000	148,000,000																																159,000,000
Baltimore Gas and Electric Company [Member] | Comprehensive Rate Order [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets																																			19,000,000
Baltimore Gas and Electric Company [Member] | Non-severance Merger Integration Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets																8,000,000
Increase (decrease) in regulatory asset																6,000,000
Baltimore Gas and Electric Company [Member] | Merger Integration Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets			4,000,000	3,000,000																																4,000,000
Noncurrent regulatory assets			6,000,000	9,000,000																																6,000,000
Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets			28,000,000	37,000,000																																28,000,000
Noncurrent regulatory assets			20,000,000	30,000,000																																20,000,000
Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets																																																									16,000,000
Amortization period			P5Y																																5
Noncurrent regulatory assets			2,000,000	3,000,000																																2,000,000
Baltimore Gas and Electric Company [Member] | Transmission Rate Formula [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Net regulatory assets				1,000,000
Baltimore Gas and Electric Company [Member] | Severance Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory assets																20,000,000
Net regulatory assets																19,000,000
Baltimore Gas and Electric Company [Member] | Pension and Other Postretirement Benefits [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			P12Y
Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			0	0																																0
Baltimore Gas and Electric Company [Member] | AMI Expenses [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Amortization period			P10Y
Noncurrent regulatory assets			128,000,000	66,000,000																																128,000,000
Baltimore Gas and Electric Company [Member] | Asset Retirement Obligations [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Noncurrent regulatory assets			16,000,000	10,000,000																																16,000,000
Exelon Generation Co L L C [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Minimum purchase obligation																																																										25,000,000
Maximum purchase obligation																																																										35,000,000
License costs			39,000,000
Business Combination, Integration Related Costs																																				19,000,000
Commonwealth Edison and Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Regulatory liabilities			88,000,000																																	88,000,000
Scenario, Forecast [Member] | Baltimore Gas and Electric Company [Member]
Regulatory Matters Additional Narrative Information [Line Items]
Revenue reduction																																					($11,000,000)

Regulatory_Matters_Estimated_C

Regulatory Matters - Estimated Commitments related to PJM Agreements (Details) (Construction Expansion Plans [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Commonwealth Edison Co [Member]
Other Commitments [Line Items]
Total	$335
2015	150
2016	172
2017	5
2018	4
2019	4
PECO Energy Co [Member]
Other Commitments [Line Items]
Total	100
2015	32
2016	31
2017	25
2018	8
2019	4
Baltimore Gas and Electric Company [Member]
Other Commitments [Line Items]
Total	351
2015	77
2016	104
2017	77
2018	57
2019	$36

Regulatory_Matters_Schedule_of

Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Feb. 28, 2010
In Millions, unless otherwise specified
Regulatory Assets [Line Items]
Current regulatory assets	$847		$760
Noncurrent regulatory assets	6,076		5,910
Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Current regulatory assets	247		221
Noncurrent regulatory assets	3,009		2,794
Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Current regulatory assets	6		10
Noncurrent regulatory assets	1,536		1,459
AMI Expenses [Member]
Regulatory Assets [Line Items]
Current regulatory assets	25		5
Noncurrent regulatory assets	271		159
AMI Meter Events [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			5
Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	251		178
Noncurrent regulatory assets	120		285
Debt Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	8		12
Noncurrent regulatory assets	49		56
Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Current regulatory assets	7		0
Noncurrent regulatory assets	183		219
Fair Value Of Supply Contract [Member]
Regulatory Assets [Line Items]
Current regulatory assets	4		12
Noncurrent regulatory assets	8		0
Severance [Member]
Regulatory Assets [Line Items]
Current regulatory assets			16
Noncurrent regulatory assets			12
Asset Retirement Obligations [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1		1
Noncurrent regulatory assets	115		102
MGP Remediation Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	36		40
Noncurrent regulatory assets	221		212
RTO Startup Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets			2
Noncurrent regulatory assets			0
Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	67		48
Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Current regulatory assets	20		17
Noncurrent regulatory assets	187		176
Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	37		53
Noncurrent regulatory assets	11		9
Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1		3
Noncurrent regulatory assets	2		3
Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Current regulatory assets	10		13
Noncurrent regulatory assets	20		30
Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Current regulatory assets	75		71
Noncurrent regulatory assets	85		154
Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	89		73
Noncurrent regulatory assets	159		148
Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	2		2
Noncurrent regulatory assets	6		9
Conservation Voltage Reductio [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1
Noncurrent regulatory assets	1
Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Current regulatory assets	7
Noncurrent regulatory assets	0
Other Assets [Member]
Regulatory Assets [Line Items]
Current regulatory assets	20	[1]	31	[1]
Noncurrent regulatory assets	26	[1]	30	[1]
Commonwealth Edison Co [Member]
Regulatory Assets [Line Items]
Current regulatory assets	349		329
Noncurrent regulatory assets	852		933
Commonwealth Edison Co [Member] | Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		2
Noncurrent regulatory assets	64		65
Commonwealth Edison Co [Member] | AMI Expenses [Member]
Regulatory Assets [Line Items]
Current regulatory assets	10		5
Noncurrent regulatory assets	81		35
Commonwealth Edison Co [Member] | AMI Meter Events [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
Commonwealth Edison Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	251		178
Noncurrent regulatory assets	120		285
Commonwealth Edison Co [Member] | Debt Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	6		9
Noncurrent regulatory assets	47		53
Commonwealth Edison Co [Member] | Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Fair Value Of Supply Contract [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
Commonwealth Edison Co [Member] | Severance [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		12
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Asset Retirement Obligations [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1		1
Noncurrent regulatory assets	73		67
Commonwealth Edison Co [Member] | MGP Remediation Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	30		33
Noncurrent regulatory assets	189		178
Commonwealth Edison Co [Member] | RTO Startup Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets			2
Noncurrent regulatory assets			0
Commonwealth Edison Co [Member] | Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	67		48
Commonwealth Edison Co [Member] | Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Current regulatory assets	20		17
Noncurrent regulatory assets	187		176
Commonwealth Edison Co [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	26		52
Noncurrent regulatory assets	7		6
Commonwealth Edison Co [Member] | Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Commonwealth Edison Co [Member] | Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Regulatory assets	7		6
Commonwealth Edison Co [Member] | Conservation Voltage Reductio [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0
Noncurrent regulatory assets	0
Commonwealth Edison Co [Member] | Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Current regulatory assets
Noncurrent regulatory assets
Commonwealth Edison Co [Member] | Other Assets [Member]
Regulatory Assets [Line Items]
Current regulatory assets	5	[1]	18	[1]
Noncurrent regulatory assets	17	[1]	20	[1]
Commonwealth Edison Co [Member] | Purchase of Receivable Program [Member]
Regulatory Assets [Line Items]
Regulatory assets	14		27
Commonwealth Edison Company [Member]
Regulatory Assets [Line Items]
Electric Transmission Costs Under-Recovery	3
Commonwealth Edison Company [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	33		58
Electric Transmission Costs Under-Recovery	22		17
Commonwealth Edison Company [Member] | Under-Recovered Electric Supply Costs [Member]
Regulatory Assets [Line Items]
Electric Transmission Costs Under-Recovery	4		35
Commonwealth Edison Company [Member] | Over Recovered Electric Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	19
PECO Energy Co [Member]
Regulatory Assets [Line Items]
Current regulatory assets	29		17
Noncurrent regulatory assets	1,529		1,448
PECO Energy Co [Member] | Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	1,400		1,317
PECO Energy Co [Member] | AMI Expenses [Member]
Regulatory Assets [Line Items]
Current regulatory assets	15		0
Noncurrent regulatory assets	62		58
PECO Energy Co [Member] | AMI Meter Events [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			5
PECO Energy Co [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Debt Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	2		3
Noncurrent regulatory assets	2		3
PECO Energy Co [Member] | Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Fair Value Of Supply Contract [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
PECO Energy Co [Member] | Severance [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
PECO Energy Co [Member] | Asset Retirement Obligations [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	26		25
PECO Energy Co [Member] | MGP Remediation Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	6		6
Noncurrent regulatory assets	31		33
PECO Energy Co [Member] | RTO Startup Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
PECO Energy Co [Member] | Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
PECO Energy Co [Member] | Conservation Voltage Reductio [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0
Noncurrent regulatory assets	0
PECO Energy Co [Member] | Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0
Noncurrent regulatory assets	0
PECO Energy Co [Member] | Other Assets [Member]
Regulatory Assets [Line Items]
Current regulatory assets	6	[1]	8	[1]
Noncurrent regulatory assets	8	[1]	7	[1]
Baltimore Gas and Electric Company [Member]
Regulatory Assets [Line Items]
Current regulatory assets	214		181
Noncurrent regulatory assets	510		524
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefits [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Baltimore Gas and Electric Company [Member] | Deferred Income Taxes [Member]
Regulatory Assets [Line Items]
Current regulatory assets	6		8
Noncurrent regulatory assets	72		77
Baltimore Gas and Electric Company [Member] | AMI Expenses [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	128		66
Baltimore Gas and Electric Company [Member] | AMI Meter Events [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
Baltimore Gas and Electric Company [Member] | Under Recovered Distribution Service Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Baltimore Gas and Electric Company [Member] | Debt Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1		1
Noncurrent regulatory assets	8		8
Baltimore Gas and Electric Company [Member] | Fair Value Of Long Term Debt [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Baltimore Gas and Electric Company [Member] | Fair Value Of Supply Contract [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
Baltimore Gas and Electric Company [Member] | Severance [Member]
Regulatory Assets [Line Items]
Current regulatory assets	4		4
Noncurrent regulatory assets	8		12
Baltimore Gas and Electric Company [Member] | Asset Retirement Obligations [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	16		10
Baltimore Gas and Electric Company [Member] | MGP Remediation Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		1
Noncurrent regulatory assets	1		1
Regulatory assets	1		1
Baltimore Gas and Electric Company [Member] | RTO Startup Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
Baltimore Gas and Electric Company [Member] | Under Recovered Uncollectible Accounts Expense [Member]
Regulatory Assets [Line Items]
Current regulatory assets			0
Noncurrent regulatory assets			0
Baltimore Gas and Electric Company [Member] | Renewable Energy And Associated REC [Member]
Regulatory Assets [Line Items]
Current regulatory assets	0		0
Noncurrent regulatory assets	0		0
Baltimore Gas and Electric Company [Member] | Under Recovered Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	11		1
Noncurrent regulatory assets	4		3
Regulatory assets	15		4
Baltimore Gas and Electric Company [Member] | Under Recovered Electric Energy And Transmission Costs [Member]
Regulatory Assets [Line Items]
Regulatory assets	10
Baltimore Gas and Electric Company [Member] | Deferred Storm Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1		3
Noncurrent regulatory assets	2		3
Regulatory assets					16
Baltimore Gas and Electric Company [Member] | Electric Generation Related Regulatory Asset [Member]
Regulatory Assets [Line Items]
Current regulatory assets	10		13
Noncurrent regulatory assets	20		30
Regulatory assets	28		37
Baltimore Gas and Electric Company [Member] | Rate Stabilization Deferral [Member]
Regulatory Assets [Line Items]
Current regulatory assets	75		71
Noncurrent regulatory assets	85		154
Baltimore Gas and Electric Company [Member] | Energy Efficiency And Demand Response Programs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	89		73
Noncurrent regulatory assets	159		148
Baltimore Gas and Electric Company [Member] | Merger Integration Costs [Member]
Regulatory Assets [Line Items]
Current regulatory assets	2		2
Noncurrent regulatory assets	6		9
Regulatory assets	4		3
Baltimore Gas and Electric Company [Member] | Conservation Voltage Reductio [Member]
Regulatory Assets [Line Items]
Current regulatory assets	1
Noncurrent regulatory assets	1
Baltimore Gas and Electric Company [Member] | Under Recovered Decoupling Revenue [Member]
Regulatory Assets [Line Items]
Current regulatory assets	7
Noncurrent regulatory assets	0
Baltimore Gas and Electric Company [Member] | Other Assets [Member]
Regulatory Assets [Line Items]
Current regulatory assets	7	[1]	4	[1]
Noncurrent regulatory assets	0	[1]	3	[1]
Baltimore Gas and Electric Company [Member] | Purchase of Receivable Program [Member]
Regulatory Assets [Line Items]
Regulatory assets	$7		$0
[1]	For ComEd and BGE, includes Purchase of Receivable Program regulatory assets. As of December 31, 2014, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $14 million and $7 million, respectively. As of December 31, 2013, ComEd and BGE had a regulatory asset related to the Purchase of Receivable Program of $27 million and $0 million, respectively.

Regulatory_Matters_Schedule_of1

Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Regulatory Liabilities [Line Items]
Regulatory liabilities	$310	$327
Noncurrent regulatory liabilities	4,550	4,388
Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	51	2
Noncurrent regulatory liabilities	37	43
Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	2,879	2,740
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	118	99
Noncurrent regulatory liabilities	1,448	1,423
Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	25	53
Noncurrent regulatory liabilities	2	0
Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	1
Noncurrent regulatory liabilities	10	10
Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	32	21
Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	8	20
Noncurrent regulatory liabilities	94	114
Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	20	8
Noncurrent regulatory liabilities	29	37
Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	68	78
Noncurrent regulatory liabilities	16	0
Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	2	8
Noncurrent regulatory liabilities	0	0
Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	38
Noncurrent regulatory liabilities	0	0
Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	12	16
Noncurrent regulatory liabilities	0	0
Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	4
Noncurrent regulatory liabilities	3	0
Commonwealth Edison Co [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	125	170
Noncurrent regulatory liabilities	3,655	3,512
Commonwealth Edison Co [Member] | Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	2,389	2,293
Commonwealth Edison Co [Member] | Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	94	78
Noncurrent regulatory liabilities	1,249	1,219
Commonwealth Edison Co [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	25	45
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	9
Noncurrent regulatory liabilities	16	0
Commonwealth Edison Co [Member] | Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	38
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Commonwealth Edison Co [Member] | Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	1	0
PECO Energy Co [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	90	106
Noncurrent regulatory liabilities	657	629
PECO Energy Co [Member] | Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
PECO Energy Co [Member] | Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	490	447
PECO Energy Co [Member] | Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
PECO Energy Co [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	8
Noncurrent regulatory liabilities	2	0
PECO Energy Co [Member] | Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	1
Noncurrent regulatory liabilities	10	10
PECO Energy Co [Member] | Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	32	21
PECO Energy Co [Member] | Electric Transmission And Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	8	20
Noncurrent regulatory liabilities	94	114
PECO Energy Co [Member] | Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	20	8
Noncurrent regulatory liabilities	29	37
PECO Energy Co [Member] | Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	58	58
Noncurrent regulatory liabilities	0	0
PECO Energy Co [Member] | Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	2	8
Noncurrent regulatory liabilities	0	0
PECO Energy Co [Member] | Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
PECO Energy Co [Member] | Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
PECO Energy Co [Member] | Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	2	3
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	44	48
Noncurrent regulatory liabilities	200	204
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Nuclear Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	24	21
Noncurrent regulatory liabilities	199	204
Baltimore Gas and Electric Company [Member] | Energy Efficiency Demand Response Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Dlc Program Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Energy Efficiency Phase [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent 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
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Gas Distribution Tax Repairs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0
Noncurrent regulatory liabilities	0
Baltimore Gas and Electric Company [Member] | Over Recovered Energy And Transmission Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	7	11
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Over-Recovered Universal Service Fund Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Revenue Subject to Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	0	0
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Over Recovered Decoupling Revenue [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	12	16
Noncurrent regulatory liabilities	0	0
Baltimore Gas and Electric Company [Member] | Regulatory Liabilities Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	1	0
Noncurrent regulatory liabilities	1	0
Renewable Energy Program [Member] | Commonwealth Edison Company [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	16	9
Over Recovered Electric Energy And Transmission Costs [Member] | Commonwealth Edison Company [Member]
Regulatory Liabilities [Line Items]
Regulatory Liabilities	$19

Regulatory_Matters_Purchase_of

Regulatory Matters - Purchase of Receivables Programs (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Purchase Of Receivables [Line Items]
Purchased receivables	$290	[1]	$263	[1]
Allowance for uncollectible accounts	-42	[2]	-30	[2]
Purchased receivables, net	248		233
Commonwealth Edison Co [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	139	[1]	105	[1]
Allowance for uncollectible accounts	-21	[2]	-16	[2]
Purchased receivables, net	118		89
PECO Energy Co [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	76	[1]	72	[1]
Allowance for uncollectible accounts	-8	[2]	-7	[2]
Purchased receivables, net	68		65
Baltimore Gas and Electric Company [Member]
Purchase Of Receivables [Line Items]
Purchased receivables	75	[1]	86	[1]
Allowance for uncollectible accounts	-13	[2]	-7	[2]
Purchased receivables, net	$62		$79
[1]	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.
[2]	For ComEd and BGE, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the incremental uncollectible accounts expense is recovered through its Purchase of Receivables with Consolidated Billing (PORCB) tariff.

Mergers_Acquisitions_and_Dispo2

Mergers, Acquisitions and Dispositions - Narrative (Details) (USD $)	0 Months Ended		3 Months Ended										12 Months Ended						0 Months Ended		2 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Jun. 11, 2014	Mar. 20, 2013	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2014	Nov. 01, 2014	Dec. 31, 2014	31-May-14	Jun. 30, 2012	Jul. 26, 2013	Dec. 27, 2013	Dec. 12, 2014	30-May-12	Jan. 14, 2015	Jul. 18, 2014	Nov. 30, 2012	Feb. 28, 2012
																								MW	MW	MW
Business Acquisition [Line Items]
Other noncurrent assets			$1,160,000,000					$964,000,000					$1,160,000,000		$964,000,000				$1,160,000,000		$1,160,000,000
Business Combination, Integration Related Costs													19,000,000		28,000,000
Equity security units	57.5
Bridge loan	3,200,000,000																					7,200,000,000
Revenues			7,255,000,000		6,912,000,000	6,024,000,000	7,237,000,000	6,163,000,000	6,502,000,000	6,141,000,000	6,082,000,000		27,429,000,000	[1]	24,888,000,000	[1]	23,489,000,000	[1]
Comprehensive Income (Loss), Net of Tax, Attributable to Parent													1,176,000,000		2,456,000,000		854,000,000
Net income			18,000,000	[2]	993,000,000	522,000,000	90,000,000	495,000,000	738,000,000	490,000,000	-4,000,000	[3]	1,820,000,000		1,729,000,000		1,171,000,000
Merger and integration related costs													44,000,000				141,000,000	[4]
Generating assets net book value			1,800,000,000										1,800,000,000						1,800,000,000		1,800,000,000
Expected pre-tax proceeds													1,800,000,000
Expected after-tax proceeds													1,400,000,000
Construction costs																							66,000,000
Construction time frame		20 years
Loss contingency accrual			44,000,000										44,000,000						44,000,000		44,000,000
Maximum loss contingency			105,000,000										105,000,000						105,000,000		105,000,000
Estimated future period for payment													20 years
Change in capital expenditures not paid													220,000,000		-38,000,000		160,000,000
Operating And Maintenance Expense [Member]
Business Acquisition [Line Items]
Change in capital expenditures not paid													185,000,000		24,000,000
Development costs expensed													3,000,000		6,000,000
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Other noncurrent assets			731,000,000					645,000,000					731,000,000		645,000,000				731,000,000		731,000,000
Business Combination, Integration Related Costs			19,000,000
Revenues			4,802,000,000		4,412,000,000	3,789,000,000	4,390,000,000	3,772,000,000	4,255,000,000	4,070,000,000	3,533,000,000		17,393,000,000		15,630,000,000		14,437,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent													769,000,000		761,000,000		156,000,000
Net income			-91,000,000		771,000,000	340,000,000	-185,000,000	269,000,000	490,000,000	330,000,000	-18,000,000		1,019,000,000		1,060,000,000		558,000,000
Merger and integration related costs													44,000,000				32,000,000	[4]
Expected period of completion													10 years
Loss contingency accrual			44,000,000										44,000,000						44,000,000		44,000,000
Capacity of energy construction project			150										150						150		150
Change in capital expenditures not paid													-61,000,000	[5]	-107,000,000	[6]	103,000,000	[7]
Development costs expensed													13,000,000		10,000,000		4,000,000
Exelon Generation Co L L C [Member] | Perryman Construction [Member]
Business Acquisition [Line Items]
Capacity of energy construction project																								120
Exelon Generation Co L L C [Member] | Fourmile Wind Project [Member]
Business Acquisition [Line Items]
Capacity of energy construction project			40										40						40		40				40
Exelon Generation Co L L C [Member] | Fair Wind Project [Member]
Business Acquisition [Line Items]
Capacity of energy construction project			30										30						30		30					30
Baltimore Gas and Electric Company [Member]
Business Acquisition [Line Items]
Other noncurrent assets			25,000,000					26,000,000					25,000,000		26,000,000				25,000,000		25,000,000
Revenues			761,000,000		697,000,000	653,000,000	1,054,000,000	794,000,000	737,000,000	653,000,000	880,000,000		3,165,000,000		3,065,000,000		2,735,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent													211,000,000		210,000,000		4,000,000
Net income			52,000,000		46,000,000	16,000,000	85,000,000	47,000,000	50,000,000	22,000,000	77,000,000		211,000,000		210,000,000		4,000,000
Merger and integration related costs													0				27,000,000	[4]
Maximum loss contingency																											1,700,000
Change in capital expenditures not paid													25,000,000		-48,000,000		-4,000,000
Regulatory assets transfer changes											8,000,000						272,000,000
Commonwealth Edison Co [Member]
Business Acquisition [Line Items]
Other noncurrent assets			271,000,000					291,000,000					271,000,000		291,000,000				271,000,000		271,000,000
Revenues			1,079,000,000		1,222,000,000	1,128,000,000	1,134,000,000	1,068,000,000	1,156,000,000	1,080,000,000	1,160,000,000		4,564,000,000		4,464,000,000		5,443,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent													408,000,000		249,000,000		380,000,000
Net income			73,000,000		126,000,000	111,000,000	98,000,000	109,000,000	126,000,000	96,000,000	-81,000,000		408,000,000		249,000,000		379,000,000
Merger and integration related costs													0				0	[4]
Change in capital expenditures not paid													78,000,000		-8,000,000		15,000,000
PECO Energy Co [Member]
Business Acquisition [Line Items]
Other noncurrent assets			34,000,000					38,000,000					34,000,000		38,000,000				34,000,000		34,000,000
Revenues			750,000,000		693,000,000	656,000,000	993,000,000	805,000,000	728,000,000	672,000,000	895,000,000		3,094,000,000		3,100,000,000		3,186,000,000
Comprehensive Income (Loss), Net of Tax, Attributable to Parent													352,000,000		395,000,000		382,000,000
Net income			98,000,000		81,000,000	84,000,000	89,000,000	102,000,000	92,000,000	72,000,000	121,000,000		352,000,000		395,000,000		381,000,000
Merger and integration related costs													0				0	[4]
Change in capital expenditures not paid													0		13,000,000		26,000,000
Minimum [Member]
Business Acquisition [Line Items]
Construction costs			95,000,000										95,000,000						95,000,000		95,000,000
Development of new generation cost			600,000,000										600,000,000						600,000,000		600,000,000
Expected new generation (in MW)													285
Maximum [Member]
Business Acquisition [Line Items]
Construction costs			120,000,000										120,000,000						120,000,000		120,000,000
Development of new generation cost			650,000,000										650,000,000						650,000,000		650,000,000
Expected new generation (in MW)													300
Subsequent Event [Member]
Business Acquisition [Line Items]
Aggregate value of customer rate credit programs																												62,000,000
Aggregate value of energy efficiency programs																												15,000,000
Pepco Holdings [Member]
Business Acquisition [Line Items]
Share price	$35																												$27.25
Other noncurrent assets			126,000,000										126,000,000						126,000,000		126,000,000
Other long-term investments																													18,000,000
Other long-term investments, maximum																													180,000,000
Total acquisition costs																													7,200,000,000
Proposed customer benefit package																													100,000,000
Business Acquisition, Transaction Costs			179,000,000										179,000,000						179,000,000		179,000,000
Business Combination, Integration Related Costs													48,000,000
Business Combination, Acquisition Related Costs													131,000,000
Expected debt issuance													3,500,000,000
Cash funding from non-core asset sale			1,000,000,000										1,000,000,000						1,000,000,000		1,000,000,000
Equity security units	23
Subordinated junior notes	1,200,000,000
Pepco Holdings [Member] | Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Capacity of energy construction project			125										125						125		125
Pepco Holdings [Member] | Bridge Loan [Member]
Business Acquisition [Line Items]
Line of credit facility, maximum borrowing capacity	7,200,000,000
Pepco Holdings [Member] | Minimum [Member]
Business Acquisition [Line Items]
Business exit costs													259,000,000
Pepco Holdings [Member] | Maximum [Member]
Business Acquisition [Line Items]
Business exit costs													293,000,000
Intergrys Energy Group Inc [Member] | Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Total consideration transferred																				332,000,000
Payments to acquire businesses													319,000,000
Liabilities incurred in acquisition																			13,000,000
Bargain purchase gain (after-tax)																				28,000,000
Revenues																					386,000,000
Net income																					-42,000,000
Derivative, Loss on Derivative																				108,000,000
Merger and integration related costs																					7,000,000
Constellation Energy Group Acquisition [Member]
Business Acquisition [Line Items]
Business Combination, Integration Related Costs													22,000,000		142,000,000		804,000,000
Estimated direct investment in the State of Maryland																															1,000,000,000
Proceeds assets held for sale																														371,000,000
Regulatory assets transfer changes															17,000,000		58,000,000
Constellation Energy Group Acquisition [Member] | Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Business Combination, Integration Related Costs															106,000,000		340,000,000
Constellation Energy Group Acquisition [Member] | Baltimore Gas and Electric Company [Member]
Business Acquisition [Line Items]
Business Combination, Integration Related Costs															6,000,000		182,000,000
Revenues															3,065,000,000		2,091,000,000
Net income															210,000,000		-31,000,000
Regulatory assets transfer changes															6,000,000		22,000,000
Constellation Energy Group Acquisition [Member] | Commonwealth Edison Co [Member]
Business Acquisition [Line Items]
Business Combination, Integration Related Costs															16,000,000		41,000,000
Regulatory assets transfer changes															11,000,000		36,000,000
Constellation Energy Group Acquisition [Member] | PECO Energy Co [Member]
Business Acquisition [Line Items]
Business Combination, Integration Related Costs															$9,000,000		$17,000,000
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[3]	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
[4]	Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments.
[5]	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.
[6]	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.
[7]	Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley.

Mergers_Acquisitions_and_Dispo3

Mergers, Acquisitions and Dispositions - Summary of Integrys Energy Group Acquisition (Details) (Exelon Generation Co L L C [Member], Intergrys Energy Group Inc [Member], USD $)	0 Months Ended
In Millions, unless otherwise specified	Nov. 01, 2014	Nov. 01, 2014
Exelon Generation Co L L C [Member] | Intergrys Energy Group Inc [Member]
Business Acquisition [Line Items]
Total consideration transferred	$332
Working capital assets	389	389
Mark-to-market derivative assets	185	185
Unamortized energy contracts	115	115
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	48	48
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	-195	-195
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Derivative Liabilities	-57	-57
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities	-109	-109
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Deferred Tax Liabilities Noncurrent	-16	-16
Total net assets	360	360
Bargain purchase gain (after-tax)	$28

Mergers_Acquisitions_and_Dispo4

Mergers, Acquisitions and Dispositions - Costs Recognized after Closing of Merger (Details) (USD $)	12 Months Ended
	Dec. 31, 2012		Jun. 30, 2012
Business Acquisition [Line Items]
BGE rate credit of $100 per residential customer	$113,000,000	[1]
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers	114,000,000
Contribution for renewable energy, energy efficiency or related projects in Baltimore	2,000,000
Charitable contributions at $7 million per year for 10 years	70,000,000
State funding for offshore wind development projects	32,000,000
Miscellaneous tax benefits	-2,000,000
Total	329,000,000
Rate credit per residential customer (in usd per customer)	100
Charitable contributions, per year	7,000,000
Period for charitable contributions	10 years
Construction costs			66,000,000
Baltimore Gas and Electric Company [Member]
Business Acquisition [Line Items]
BGE rate credit of $100 per residential customer	113,000,000	[1]
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers	0
Contribution for renewable energy, energy efficiency or related projects in Baltimore	0
Charitable contributions at $7 million per year for 10 years	28,000,000
State funding for offshore wind development projects	0
Miscellaneous tax benefits	-2,000,000
Total	139,000,000
Rate credit per residential customer (in usd per customer)	100
Charitable contributions, per year	7,000,000
Period for charitable contributions	10 years
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
BGE rate credit of $100 per residential customer	0	[1]
Customer investment fund to invest in energy efficiency and low-income energy assistance to BGE customers	0
Contribution for renewable energy, energy efficiency or related projects in Baltimore	0
Charitable contributions at $7 million per year for 10 years	35,000,000
State funding for offshore wind development projects	0
Miscellaneous tax benefits	0
Total	35,000,000
Rate credit per residential customer (in usd per customer)	100
Charitable contributions, per year	$7,000,000
Period for charitable contributions	10 years
[1]	Exelon made a $66 million equity contribution to BGE in the second quarter of 2012 to fund the after-tax amount of the rate credit as directed in the MDPSC order approving the merger transaction.

Mergers_Acquisitions_and_Dispo5

Mergers, Acquisitions and Dispositions - Purchase Price Allocation of Merger with Constellation (Details) (Constellation Energy Group LLC [Member], USD $)	Dec. 31, 2012
In Millions, unless otherwise specified
Business Acquisition [Line Items]
Current assets	$4,936
Property, plant and equipment	9,342
Unamortized energy contracts	3,218
Other intangibles, trade name and retail relationships	457
Investment in affiliates	1,942
Asset retirement obligation	740
Other assets	2,265
Total assets	22,900
Current liabilities	3,408
Unamortized energy contract liabilities	1,722
Long-term debt, including current maturities	5,632
Noncontrolling interest	90
Other liabilities	4,683
Total liabilities	15,535
Total net assets	7,365
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Current assets	3,638
Property, plant and equipment	4,054
Unamortized energy contracts	3,218
Other intangibles, trade name and retail relationships	457
Investment in affiliates	1,942
Asset retirement obligation	0
Other assets	1,266
Total assets	14,575
Current liabilities	2,804
Unamortized energy contract liabilities	1,512
Long-term debt, including current maturities	2,972
Noncontrolling interest	90
Other liabilities	1,933
Total liabilities	9,311
Total net assets	$5,264

Mergers_Acquisitions_and_Dispo6

Mergers, Acquisitions and Dispositions - Summary of Pro-forma Impact of the Merger (Details) (USD $)	12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Total revenues	$26,700	$30,712
Net income attributable to Exelon	2,092	974
Basic Earnings Per Share (in usd per share)	$2,560,000	$1,150,000
Diluted Earnings Per Share (in usd per share)	$2,550,000	$1,140,000
Non-recurring costs		236
Exelon Generation Co L L C [Member]
Business Acquisition [Line Items]
Total revenues	17,013	19,494
Net income attributable to Exelon	1,205	324
Non-recurring costs		$203

Mergers_Acquisitions_and_Dispo7

Mergers, Acquisitions and Dispositions - Summary of Asset Divestitures (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Long Lived Assets Held-for-sale [Line Items]
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$437	$13	($7)
Fore River [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	100.00%
Net Generation Capacity	726,000,000
West Valley [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	100.00%
Net Generation Capacity	185,000,000
Keystone [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	41.98%
Net Generation Capacity	714,000,000
Conemaugh [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	31.28%
Net Generation Capacity	532,000,000
Safe Harbor [Member]
Long Lived Assets Held-for-sale [Line Items]
Percent Owned	66.70%
Net Generation Capacity	278,000,000
Quail Run [Member]
Long Lived Assets Held-for-sale [Line Items]
Gain (Loss) on Sale of Assets and Asset Impairment Charges	412
Percent Owned	100.00%
Net Generation Capacity	488,000,000
Exelon Generation Co L L C [Member]
Long Lived Assets Held-for-sale [Line Items]
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$437	$13	($7)

Mergers_Acquisitions_and_Dispo8

Mergers, Acquisitions and Dispositions - Summary of Major Classes of Assets and Liabilities Held for Sale (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Significant Acquisitions and Disposals [Line Items]
Total assets held for sale	$147		$14
Accrued expenses	1,539		1,633
Other current liabilities	1,123		858
Electricity Generation Plant, Non-Nuclear [Member]
Significant Acquisitions and Disposals [Line Items]
Property, plant and equipment, net	143	[1]
Inventory	4
Total assets held for sale	147
Accrued expenses	1
Other current liabilities	4
Total liabilities held for sale	5	[2]
Asset impairment charges	$50
[1]	The total aggregate book value of property, plant and equipment is net of a $50 million pre-tax impairment loss recorded within Operating and maintenance expense on Exelon’s and Generation’s Statements of Operations and Comprehensive Income. See Note 8 — Impairment of Long-Lived Assets for further information.
[2]	Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Investment_in_Constellation_En2

Investment in Constellation Energy Nuclear Group, LLC - Narrative (Details) (USD $)	0 Months Ended	3 Months Ended									12 Months Ended
In Millions, unless otherwise specified	Apr. 01, 2014	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Purchase of nuclear output by EDF											49.99%
Guarantee obligations maximum exposure		$9,402									$9,402
Revenues		7,255	6,912	6,024	7,237	6,163		6,502	6,141	6,082	27,429	[1]	24,888	[1]	23,489	[1]
Investment in CENG		0				1,925					0		1,925
Accumulated other comprehensive loss, net		-2,684				-2,040	[2]				-2,684		-2,040	[2]	-2,767	[2]
Required purchases of power from CENG's nuclear plants not sold to third parties											85.00%
Operating revenues from affiliates											23		70		48
Parental guarantee provided		75									75
Business Combination, Integration Related Costs											19		28
Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Accumulated other comprehensive loss, net	1,500
Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]
Schedule of Equity Method Investments [Line Items]
Due to affiliate	245
Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]
Schedule of Equity Method Investments [Line Items]
Guarantee obligations maximum exposure	165
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Ownership interest		50.01%									50.01%
Cash distribution paid to member											645		625		1,626
Purchase of nuclear output by EDF	49.99%
Guarantee obligations maximum exposure		6,384									6,384
Total equity investment earnings (losses) - CENG					19								9
Revenues		4,802	4,412	3,789	4,390	3,772		4,255	4,070	3,533	17,393		15,630		14,437
Investment in CENG		0				1,925					0		1,925
Accumulated other comprehensive loss, net		-36				214	[2]				-36		214	[2]	513	[2]
Allocation of federal tax benefit under tax sharing agreement					77	26							26
Required purchases of power from CENG's nuclear plants not sold to third parties	85.00%										85.00%
Subsequent purchases of power from CENG's nuclear plants not sold to third parties	50.01%
Operating revenues from affiliates											779		1,423		1,702
Parental guarantee provided		5									5
Business Combination, Integration Related Costs		19
Exelon Generation Co L L C [Member] | Variable Interest Entity, Primary Beneficiary [Member]
Schedule of Equity Method Investments [Line Items]
Remeasurement gain from derecognition of equity method investment	261
Business combination, step acquisition, equity interest in acquiree, fair value	136
Business acquisition, preexisting relationship, gain (loss) recognized	132
Parental guarantee provided	7	7									7
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Revenues					17						218		56
Investment in CENG					1,900
Accumulated other comprehensive loss, net					116
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Due from affiliates	400	400									400
Interest rate on loan to CENG	5.25%
Allocation of federal tax benefit under tax sharing agreement	152
Reduction to net income attributable to noncontrolling interest											13
Net Income (Loss) Attributable to Parent											407
Business Combination, Integration Related Costs											26
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member] | Payment Guarantee [Member]
Schedule of Equity Method Investments [Line Items]
Due to affiliate	205
Exelon Generation Co L L C [Member] | EDFI [Member] | Constellation Energy Nuclear Group [Member]
Schedule of Equity Method Investments [Line Items]
Operating revenues from affiliates											137
Electricite De France LLC [Member]
Schedule of Equity Method Investments [Line Items]
Required purchases of power from CENG's nuclear plants not sold to third parties	15.00%
Subsequent purchases of power from CENG's nuclear plants not sold to third parties	49.99%
Electricite De France LLC [Member] | Constellation Energy Nuclear Group [Member] | Financial Guarantee [Member]
Schedule of Equity Method Investments [Line Items]
Guarantee obligations maximum exposure	145
Constellation Energy Group LLC [Member]
Schedule of Equity Method Investments [Line Items]
Interest rate on distribution	8.50%
Constellation Energy Group LLC [Member] | EDFI [Member]
Schedule of Equity Method Investments [Line Items]
Cash distribution paid to member	$400
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Investment_in_Constellation_En3

Investment in Constellation Energy Nuclear Group, LLC - Schedule of Assets and Liabilities of CENG (Details) (Exelon Generation Co L L C [Member], Constellation Energy Nuclear Group [Member], USD $)	Apr. 01, 2014
In Millions, unless otherwise specified
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group [Member]
Business Acquisition [Line Items]
Current assets	$499
Nuclear decommissioning trust fund	1,955
Property, plant and equipment	3,017
Nuclear fuel	482
Other assets	10
Total assets	5,963
Current liabilities	237
Asset retirement obligation	1,760
Pension and other employee benefit obligations	281
Unamortized energy contract liabilities	171
Other liabilities	114
Total liabilities	2,563
Total net assets	$3,400

Accounts_Receivable_Schedule_o

Accounts Receivable - Schedule of Estimated Unbilled Revenues (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	$1,381		$1,151
Allowance for uncollectible accounts	-311	[1]	-272	[1]
Exelon Generation Co L L C [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	823	[2]	584	[2]
Allowance for uncollectible accounts	-60	[1]	-57	[1]
Commonwealth Edison Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	204		201
Allowance for uncollectible accounts	-84	[1]	-62	[1]
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	140		161
Allowance for uncollectible accounts	-100	[1],[3]	-107	[1],[3]
Current financing receivable allowance for credit losses	7		8
Baltimore Gas and Electric Company [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	214		205
Allowance for uncollectible accounts	-67	[1],[4]	-46	[1],[4]
Charged to Costs and Expenses	$19
[1]	Includes the allowance for uncollectible accounts on customer and other accounts receivable.
[2]	Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.
[3]	Includes an allowance for uncollectible accounts of $7 million and $8 million at December 31, 2014 and 2013, respectively, related to PECO’s current installment plan receivables described below.
[4]	At December 31, 2014, as explained in Note 1—Significant Accounting Policies, BGE estimated the allowance for uncollectible accounts on customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in a $19 million pre-tax charge to BGE's provision for uncollectible accounts expense for the year ended December 31, 2014, which is included in Operating and maintenance expense on BGE's Consolidated Statements of Operations and Comprehensive Income.

Accounts_Receivable_Narrative_

Accounts Receivable - Narrative (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	$15	$19
PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	15	18
Risk Level, Low [Member] | PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables uncollectible accounts reserve	1	1
Risk Level, Medium [Member] | PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	3	4
Risk Level, High [Member] | PECO Energy Co [Member]
Accounts, Notes, Loans and Financing Receivable [Line Items]
Installment plan receivables	$11	$13

Property_Plant_and_Equipment_S

Property, Plant and Equipment - Summary of Property, Plant and Equipment (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	$66,829		$61,043
Less: accumulated depreciation	14,742	[1]	13,713	[1]
Property, plant and equipment, net	52,087		47,330
Nuclear fuel - work in progress	1,003		947
Buildings under capital lease	15		23
Original cost basis for buildings	52		59
Accumulated depreciation for buildings	37		36
Accumulated amortization of nuclear fuel	2,673		2,371
Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	30,157		28,123
Electric Transmission and Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	90 years
Electric Transmission and Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	22,911		20,420
Electric Generation Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	56 years
Electric Generation Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	1 year
Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	3,505		3,296
Gas Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	90 years
Gas Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	1,169		1,101
Common Electric And Gas T And D Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years
Common Electric And Gas T And D Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	5,947	[2]	5,196	[2]
Nuclear Fuel [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	8 years	[2]
Nuclear Fuel [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	1 year	[2]
Public Utilities Property Plant And Equipment Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	2,167		1,890
Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	973	[3]	1,017	[3]
Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years	[3]
Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years	[3]
Exelon Generation Co L L C [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	30,557		27,145
Less: accumulated depreciation	7,612	[4]	7,034	[4]
Property, plant and equipment, net	22,945		20,111
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	22,911		20,420
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	56 years
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	1 year
Exelon Generation Co L L C [Member] | Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	5,947	[2]	5,196	[2]
Exelon Generation Co L L C [Member] | Nuclear Fuel [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	8 years	[2]
Exelon Generation Co L L C [Member] | Nuclear Fuel [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	1 year	[2]
Exelon Generation Co L L C [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	1,404		1,129
Exelon Generation Co L L C [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	295	[5]	400	[5]
Exelon Generation Co L L C [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	31 years	[5]
Exelon Generation Co L L C [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	6 years	[5]
Commonwealth Edison Co [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	19,225		17,850
Less: accumulated depreciation	3,432		3,184
Property, plant and equipment, net	15,793		14,666
Buildings under capital lease			8
Original cost basis for buildings	8
Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	18,884		17,334
Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	80 years
Commonwealth Edison Co [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Commonwealth Edison Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	276		456
Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	65	[6]	60	[6]
Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years	[6]
Commonwealth Edison Co [Member] | Other Capitalized Property Plant and Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	39 years	[6]
PECO Energy Co [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	9,718		9,319
Less: accumulated depreciation	2,917		2,935
Property, plant and equipment, net	6,801		6,384
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	6,886		6,669
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	65 years
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
PECO Energy Co [Member] | Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	2,039		1,932
PECO Energy Co [Member] | Gas Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	70 years
PECO Energy Co [Member] | Gas Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	618		600
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
PECO Energy Co [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	154		101
PECO Energy Co [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	50 years	[7]
Total property, plant and equipment	21	[7]	17	[7]
Baltimore Gas and Electric Company [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	9,072		8,566
Less: accumulated depreciation	2,868		2,702
Property, plant and equipment, net	6,204		5,864
Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	6,339		6,100
Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	90 years
Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	1,761		1,660
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	90 years
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	623		578
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	40 years
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Baltimore Gas and Electric Company [Member] | Public Utilities Property Plant And Equipment Construction Work In Progress [Member]
Property, Plant and Equipment [Line Items]
Total property, plant and equipment	317		196
Baltimore Gas and Electric Company [Member] | Other Capitalized Property Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years	[7]
Total property, plant and equipment	$32	[7]	$32	[7]
[1]	Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.
[2]	Includes nuclear fuel that is in the fabrication and installation phase of $1,003 million and $947 million at December 31, 2014 and 2013, respectively.
[3]	Includes Generation’s buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively. Includes land held for future use and non utility property at ComEd, PECO, and BGE of $57 million, $21 million, and $32 million, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities at Generation.
[4]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,673 million and $2,371 million as of December 31, 2014 and 2013, respectively.
[5]	Includes buildings under capital lease with a net carrying value of $15 million and $23 million at December 31, 2014 and 2013, respectively. The original cost basis of the buildings was $52 million and $59 million, and total accumulated amortization was $37 million and $36 million, as of December 31, 2014 and 2013, respectively. These balances also include capitalized acquisition, development and exploration costs of $242 million related to oil and gas production activities.
[6]	Includes buildings under capital lease with a net carrying value at both of December 31, 2014 and 2013, of $8 million. The original cost basis of the buildings was $8 million and total accumulated amortization was immaterial as of December 31, 2014 and 2013, respectively.
[7]	Represents land held for future use and non utility property.

Property_Plant_and_Equipment_A

Property, Plant and Equipment - Annual Depreciation Provisions as Percentage of Average Service Life (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.93%	2.91%	2.76%
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.50%	3.35%	3.15%
Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.13%	2.06%	2.03%
Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	7.32%	7.53%	7.61%
PECO Energy Co [Member] | Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.55%	2.73%	2.51%
PECO Energy Co [Member] | Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	1.84%	1.79%	1.77%
PECO Energy Co [Member] | Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	5.16%	6.65%	7.54%
Baltimore Gas and Electric Company [Member] | Electric Transmission and Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.96%	2.91%	2.92%
Baltimore Gas and Electric Company [Member] | Gas Distribution Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	2.47%	2.36%	2.33%
Baltimore Gas and Electric Company [Member] | Common Electric And Gas T And D Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	9.49%	8.45%	7.68%

Property_Plant_and_Equipment_N

Property, Plant and Equipment - Narrative (Details)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.50%	3.35%	3.15%
Exelon Generation Co L L C [Member] | Electric Generation Equipment [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.50%	3.35%	3.15%
Commonwealth Edison Co [Member]
Property, Plant and Equipment [Line Items]
Annual depreciation rate	3.05%	2.97%	2.79%

Impairment_of_Longlived_Assets1

Impairment of Long-lived Assets - Narrative (Details) (USD $)	0 Months Ended	12 Months Ended						0 Months Ended	3 Months Ended
	Feb. 26, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		31-May-14	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2000	Oct. 31, 2000
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Impairment charges		$24,000,000		$14,000,000
Interest costs incurred		1,144,000,000	[1],[2],[3]	1,423,000,000	[1],[2],[3]	1,003,000,000	[1],[2],[3]
Estimated residual value of leased assets		685,000,000		1,465,000,000						685,000,000		1,600,000,000
Capital lease net investment in direct financing leases prepayments received											1,200,000,000
Proceeds from termination of direct financing lease investment	335,000,000	335,000,000		0		0
Capital leases net investment in direct financing leases writeoff	336,000,000
Pre Tax Loss		1,000,000
Exelon Generation Co L L C [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Carrying amount of long lived assets to be written down		1,000,000,000		75,000,000				151,000,000		1,000,000,000
Fair value of impaired assets		556,000,000		32,000,000				65,000,000		556,000,000
Impairment charges		450,000,000		43,000,000				86,000,000
Interest costs incurred		419,000,000	[1],[2],[3]	411,000,000	[1],[2],[3]	368,000,000	[1],[2],[3]
Baltimore Gas and Electric Company [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Regulatory assets transfer changes						272,000,000			8,000,000
Interest costs incurred		118,000,000	[1],[3]	129,000,000	[1],[3]	149,000,000	[1],[3]
Constellation Energy Group LLC [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Carrying amount of long lived assets to be written down		163,000,000								163,000,000
Fair value of impaired assets		39,000,000								39,000,000
Impairment charges										124,000,000
Operating And Maintenance Expense [Member] | Exelon Generation Co L L C [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Utilities operating expense, impairments				111,000,000
Interest Expense [Member] | Exelon Generation Co L L C [Member]
Capital Leases Net Investment In Direct Financing Leases [Line Items]
Interest costs incurred		$8,000,000
[1]	Exelon activity for the year ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the year ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012. BGE activity represents the activity for the year ended December 31, 2012.
[2]	On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of operations beginning April 1, 2014.
[3]	Includes interest expense to affiliates.

Impairment_of_Longlived_Assets2

Impairment of Long-lived Assets - Components of Net Investment in Long-term Leases (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Oct. 31, 2000
In Millions, unless otherwise specified
Impairment or Disposal of Tangible Assets Disclosure [Abstract]
Estimated residual value of leased assets	$685	$1,465	$1,600
Less: unearned income	324	767
Net investment in long-term leases	$361	$698

Jointly_Owned_Electric_Utility2

Jointly Owned Electric Utility Plant - Ownership Interests in Jointly Owned Electric Plants and Transmission Facilities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Jointly Owned Utility Plant Footnote [Abstract]
Substation capacity	500,000
Salem [Member]
Jointly Owned Utility Plant Footnote [Abstract]
Substation capacity	500,000
Conemaugh [Member]
Jointly Owned Utility Plant Footnote [Abstract]
Substation capacity	500,000
Pennsylvania [Member]
Jointly Owned Utility Plant Footnote [Abstract]
Miles of transmission voltage lines	127
Transmission line capacity	500,000
Delaware And New Jersey [Member]
Jointly Owned Utility Plant Footnote [Abstract]
Miles of transmission voltage lines	131
Substation capacity	500,000
Exelon Generation Co L L C [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	44.24%
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Quad Cities [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	Generation
Ownership interest	75.00%
Plant	$995	[1]	$941	[2]
Accumulated depreciation	266	[1]	226	[2]
Construction work in progress	15		27
Jointly Owned Utility Plant Footnote [Abstract]
Plant	995	[1]	941	[2]
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Peach Bottom [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	Generation
Ownership interest	50.00%
Plant	1,095	[1]	883	[2]
Accumulated depreciation	343	[1]	326	[2]
Construction work in progress	133		174
Jointly Owned Utility Plant Footnote [Abstract]
Plant	1,095	[1]	883	[2]
Exelon Generation Co L L C [Member] | Nuclear Generation [Member] | Salem [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	PSEG Nuclear	[3]
Ownership interest	42.59%	[3]
Plant	531	[2],[3]	501	[2],[3]
Accumulated depreciation	150	[2],[3]	134	[2],[3]
Construction work in progress	29	[3]	24	[3]
Jointly Owned Utility Plant Footnote [Abstract]
Plant	531	[2],[3]	501	[2],[3]
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Salem [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Plant	3		3
Jointly Owned Utility Plant Footnote [Abstract]
Plant	3		3
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Keystone [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	GenOn	[2]
Ownership interest	0.00%	[2]
Plant	0	[1],[2]	725	[1],[2]
Accumulated depreciation	0	[1],[2]	268	[1],[2]
Construction work in progress	0	[2]	6	[2]
Jointly Owned Utility Plant Footnote [Abstract]
Plant	0	[1],[2]	725	[1],[2]
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Conemaugh [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	GenOn	[2]
Ownership interest	0.00%	[2]
Plant	0	[1],[2]	399	[1],[2]
Accumulated depreciation	0	[1],[2]	220	[1],[2]
Construction work in progress	0	[2]	121	[2]
Jointly Owned Utility Plant Footnote [Abstract]
Plant	0	[1],[2]	399	[1],[2]
Exelon Generation Co L L C [Member] | Fossil Fuel Generation [Member] | Wyman [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	FP&L
Ownership interest	5.89%
Plant	3	[1],[2]	3	[1],[2]
Accumulated depreciation	3	[1],[2]	3	[1],[2]
Construction work in progress	0		0
Jointly Owned Utility Plant Footnote [Abstract]
Plant	3	[1],[2]	3	[1],[2]
Exelon Generation Co L L C [Member] | Other Service [Member] | Other Locations [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator		[1]
Ownership interest	44.24%	[1]
Plant	2	[1],[2]	2	[1],[2]
Accumulated depreciation	1	[1],[2]	1	[1],[2]
Construction work in progress	0	[1]	0	[1]
Jointly Owned Utility Plant Footnote [Abstract]
Plant	2	[1],[2]	2	[1],[2]
PECO Energy Co [Member] | Salem [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.55%
PECO Energy Co [Member] | Conemaugh [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	20.70%
PECO Energy Co [Member] | Pennsylvania [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	22.00%
PECO Energy Co [Member] | Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.55%
PECO Energy Co [Member] | Electric Transmission [Member] | Pennsylvania [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	First Energy	[4]
Plant	14	[2],[4]	14	[2],[4]
Accumulated depreciation	7	[2],[4]	7	[2],[4]
Construction work in progress	0	[4]	0	[4]
Jointly Owned Utility Plant Footnote [Abstract]
Plant	14	[2],[4]	14	[2],[4]
PECO Energy Co [Member] | Electric Transmission [Member] | Delaware And New Jersey [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Operator	PSEG	[5]
Ownership interest	42.55%	[5]
Plant	64	[2],[5]	64	[2],[5]
Accumulated depreciation	34	[2],[5]	34	[2],[5]
Construction work in progress	0	[5]	0	[5]
Jointly Owned Utility Plant Footnote [Abstract]
Plant	$64	[2],[5]	$64	[2],[5]
Baltimore Gas and Electric Company [Member] | Conemaugh [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	10.56%
Baltimore Gas and Electric Company [Member] | Pennsylvania [Member]
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	7.00%
[1]	Excludes asset retirement costs.
[2]	As of December 31, 2014, Generation sold its ownership interest in Keystone and Conemaugh. At December 31, 2013, Generation held 41.98% and 31.28% ownership interest in Keystone and Conemaugh, respectively. See Note 4—Mergers, Acquisitions, and Dispositions for additional information.
[3]	Generation also owns a proportionate share in the fossil fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at December 31, 2014 and 2013.
[4]	PECO owns a 42.55% share in 131 miles of 500kV lines located in Delaware and New Jersey as well as a 42.55% share in a 500kV substation immediately outside of the Salem nuclear generating station in New Jersey which supplies power to the 500kV lines including, but not limited to, the lines noted above.
[5]	Generation has a 44.24% ownership interest in assets located at Merrill Creek Reservoir located in New Jersey.

Intangible_Assets_Schedule_of_

Intangible Assets - Schedule of Goodwill (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Goodwill [Roll Forward]
Goodwill, beginning balance	$2,625
Goodwill from business combination	47
Goodwill, ending balance	2,672
Commonwealth Edison Co [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	2,625
Goodwill from business combination	0
Goodwill, ending balance	2,625
Exelon Generation Co L L C [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance			0
Goodwill, ending balance	47		0
Goodwill Gross [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	4,608
Goodwill from business combination	47
Goodwill, ending balance	4,655
Goodwill Gross [Member] | Commonwealth Edison Co [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	4,608	[1]
Goodwill from business combination	0
Goodwill, ending balance	4,608	[1]
Goodwill Gross [Member] | Exelon Generation Co L L C [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	0
Goodwill from business combination	47
Goodwill, ending balance	47
Goodwill Accumulated Impairment Losses [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	1,983
Goodwill from business combination	0
Goodwill, ending balance	1,983
Goodwill Accumulated Impairment Losses [Member] | Commonwealth Edison Co [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	1,983
Goodwill from business combination	0
Goodwill, ending balance	1,983
Goodwill Accumulated Impairment Losses [Member] | Exelon Generation Co L L C [Member]
Goodwill [Roll Forward]
Goodwill, beginning balance	0
Goodwill from business combination	47
Goodwill, ending balance	$47
[1]	Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other non-impairment-related changes as allowed under previous authoritative guidance.

Intangible_Assets_Narrative_De

Intangible Assets - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Goodwill [Line Items]
Amortization of Intangible Assets	$179	[1]	$478	[1]	$1,150	[1]
Finite lived intangible assets gross	2,489
Commonwealth Edison Co [Member]
Goodwill [Line Items]
Amortization of Intangible Assets	7		7		7
Current alternative or renewable energy credits	4		3
Exelon Generation Co L L C [Member]
Goodwill [Line Items]
Amortization of Intangible Assets	179	[1]	550	[1]	1,145	[1]
Current alternative or renewable energy credits	191		158
Noncurrent alternative or renewable energy credits	44
PECO Energy Co [Member]
Goodwill [Line Items]
Amortization of Intangible Assets	0	[2]	0	[2]	0	[2]
Current alternative or renewable energy credits	13		19
Noncurrent alternative or renewable energy credits			5
Unamortized Energy Contracts [Member]
Goodwill [Line Items]
Amortization of Intangible Assets	135	[3],[4]	430	[3],[4]	1,110	[3],[4]
Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]
Goodwill [Line Items]
Amortization of Intangible Assets	135	[3],[4]	507	[3],[4]	1,110	[2]
Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member]
Goodwill [Line Items]
Finite lived intangible assets gross	1,499
Constellation Energy Group LLC [Member] | Trade Names [Member]
Goodwill [Line Items]
Useful life	10 years
Finite lived intangible assets gross	$243
[1]	At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income
[2]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[3]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.
[4]	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.

Intangible_Assets_Schedule_of_1

Intangible Assets - Schedule of Other Intangible Assets (Details) (USD $)	12 Months Ended		1 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Feb. 28, 2003	Dec. 31, 2010	Sep. 30, 2011
				MW	MW
Finite-Lived Intangible Assets [Line Items]
Gross	2,489
Accumulated Amortization	-1,751
Net	738
2015	66
Finite-Lived Intangible Assets, Amortization Expense, Year Two	39
2017	40
2018	69
2019	67
Other miscellaneous unamortized energy contracts	26
Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	10 years
Commonwealth Edison Co [Member]
Finite-Lived Intangible Assets [Line Items]
Chicago payment made to city			60
Period for payment			10 years
City of Chicago payment made to 3rd party			-2
City of Chicago payment received			32
Reduction of amortization expense			-2
Commonwealth Edison Co [Member] | Intangible Asset Nineteen Ninety Nine Chicago Settlement Agreement [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	21 years 9 months 18 days	[1],[2]
Gross	100	[1]
Accumulated Amortization	-79	[1]
Net	21	[1]
2015	3	[1]
Finite-Lived Intangible Assets, Amortization Expense, Year Two	3	[1]
2017	4	[1]
2018	4	[1]
2019	4	[1]
Commonwealth Edison Co [Member] | Intangible Asset Two Thousand Three Chicago Settlement Agreement [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	17 years 10 months 24 days	[2],[3]
Gross	62	[3]
Accumulated Amortization	-40	[3]
Net	22	[3]
2015	4	[3]
Finite-Lived Intangible Assets, Amortization Expense, Year Two	4	[3]
2017	3	[3]
2018	3	[3]
2019	3	[3]
Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
2015	4
Finite-Lived Intangible Assets, Amortization Expense, Year Two	3
2017	0
2018	2
2019	2
Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Wind turbine supply megawatt				735
Exelon Wind Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	18 years	[2],[4],[5]
Gross	224	[4],[5]
Accumulated Amortization	-55	[4],[5]
Net	169
2015	14	[4],[5]
Finite-Lived Intangible Assets, Amortization Expense, Year Two	14	[4],[5]
2017	14	[4],[5]
2018	14	[4],[5]
2019	14	[4],[5]
Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Wind turbine supply megawatt					230
Antelope Valley Acquisition [Member] | Exelon Generation Co L L C [Member] | Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	25 years	[2],[4],[6]
Gross	190	[4],[6]
Accumulated Amortization	-12	[4],[6]
Net	178
2015	8	[4],[6]
Finite-Lived Intangible Assets, Amortization Expense, Year Two	8	[4],[6]
2017	8	[4],[6]
2018	8	[4],[6]
2019	8	[4],[6]
Constellation Energy Group LLC [Member] | Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	1 year 5 months 24 days
Gross	1,499
Accumulated Amortization	-1,451
Net	48
2015	19
Finite-Lived Intangible Assets, Amortization Expense, Year Two	-31
2017	-21
2018	11
2019	8
Constellation Energy Group LLC [Member] | Trade Names [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	10 years
Gross	243
Accumulated Amortization	-79
Net	164
2015	23
Finite-Lived Intangible Assets, Amortization Expense, Year Two	23
2017	23
2018	23
2019	23
Constellation Energy Group LLC [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	12 years 4 months 24 days
Gross	214
Accumulated Amortization	-58
Net	156
2015	18
Finite-Lived Intangible Assets, Amortization Expense, Year Two	18
2017	18
2018	18
2019	17
CENG [Member] | Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	1 year 8 months 12 days
Gross	-97
Accumulated Amortization	29
Net	-68
2015	-20
Finite-Lived Intangible Assets, Amortization Expense, Year Two	-11
2017	-15
2018	-18
2019	-15
Integrys [Member] | Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	2 years 4 months 24 days
Gross	6
Accumulated Amortization	-5
Net	1
2015	-8
Finite-Lived Intangible Assets, Amortization Expense, Year Two	6
2017	1
2018	1
2019	0
Integrys [Member] | Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Weighted-average amortization period	10 years
Gross	48
Accumulated Amortization	-1
Net	47
2015	5
Finite-Lived Intangible Assets, Amortization Expense, Year Two	5
2017	5
2018	5
2019	5
[1]	In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 230 MW solar project under development in northern Los Angeles County, CA from First Solar, Inc.
[2]	See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.
[3]	See Note 4—Mergers, Acquisitions, and Dispositions for further information on these acquisitions.
[4]	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.
[5]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.
[6]	In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735MWs of installed, operating wind capacity located in eight states.

Intangible_Assets_Summary_of_A

Intangible Assets - Summary of Amortization Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	$179	[1]	$478	[1]	$1,150	[1]
Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	179	[1]	550	[1]	1,145	[1]
Commonwealth Edison Co [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	7		7		7
Unamortized Energy Contracts [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	135	[2],[3]	430	[2],[3]	1,110	[2],[3]
Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]
Finite-Lived Intangible Assets [Line Items]
Intangible asset amortization expense	$135	[2],[3]	$507	[2],[3]	$1,110	[4]
[1]	At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement of Operations and Comprehensive Income
[2]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.
[3]	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.
[4]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

Fair_Value_of_Financial_Assets2

Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at the Carrying Amount (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	$460		$341
Long-term debt (including amounts due within one year)	441		384
Long-term debt to financing trusts	648		648
Long-term debt to financing trusts	648		648
Spent Nuclear Fuel Obligation, Noncurrent	1,021		1,021
Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	463		344
Long-term debt to financing trusts	648		648
Debt and Capital Lease Obligations	21,164		19,132
Spent Nuclear Fuel Obligation, Noncurrent	1,021		1,021
Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	463		344
Long-term debt (including amounts due within one year)	22,936		19,751
Long-term debt to financing trusts	648		631
SNF obligation	833		790
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	3
Long-term debt (including amounts due within one year)	1,208
Long-term debt to financing trusts	0
SNF obligation	0
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	448
Long-term debt (including amounts due within one year)	20,417
Long-term debt to financing trusts	0
SNF obligation	833
Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	12
Long-term debt (including amounts due within one year)	1,311
Long-term debt to financing trusts	648
SNF obligation	0
Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	36		22
Long-term debt (including amounts due within one year)	146		166
Long-term debt to financing trusts	943		1,523
Debt and Capital Lease Obligations	7,652		7,168
Spent Nuclear Fuel Obligation, Noncurrent	1,021		1,021
Exelon Generation Co L L C [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	36		22
Debt and Capital Lease Obligations	8,266		7,729
Spent Nuclear Fuel Obligation, Noncurrent	1,021		1,021
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	36		22
Long-term debt (including amounts due within one year)	8,822		7,648
SNF obligation	833		790
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	0
Long-term debt (including amounts due within one year)	0
SNF obligation	0
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	24
Long-term debt (including amounts due within one year)	7,511
SNF obligation	833
Exelon Generation Co L L C [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	12
Long-term debt (including amounts due within one year)	1,311
SNF obligation	0
Commonwealth Edison Co [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	304		184
Long-term debt to financing trusts	206		206
Debt and Capital Lease Obligations	5,698		5,058
Commonwealth Edison Co [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	304		184
Long-term debt to financing trusts	206		206
Debt and Capital Lease Obligations	5,958		5,675
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	304		184
Long-term debt (including amounts due within one year)	6,788		6,255
Long-term debt to financing trusts	213		202
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	0
Long-term debt (including amounts due within one year)	0
Long-term debt to financing trusts	0
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	304
Long-term debt (including amounts due within one year)	6,788
Long-term debt to financing trusts	0
Commonwealth Edison Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	0
Long-term debt (including amounts due within one year)	0
Long-term debt to financing trusts	213
PECO Energy Co [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt to financing trusts	184	[1]	184	[1]
Debt and Capital Lease Obligations	2,246		1,947
Long-term debt to financing trusts	184		184
PECO Energy Co [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt to financing trusts	184		184
Debt and Capital Lease Obligations	2,246		2,197
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt (including amounts due within one year)	2,537		2,358
Long-term debt to financing trusts	199		180
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt (including amounts due within one year)	0
Long-term debt to financing trusts	0
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt (including amounts due within one year)	2,537
Long-term debt to financing trusts	0
PECO Energy Co [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term debt (including amounts due within one year)	0
Long-term debt to financing trusts	199
Baltimore Gas and Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	120		135
Long-term debt to financing trusts	258		258
Debt and Capital Lease Obligations			2,011
Baltimore Gas and Electric Company [Member] | Reported Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term Debt	123		138
Long-term debt to financing trusts	258
Debt and Capital Lease Obligations	1,942
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	123		138
Long-term debt (including amounts due within one year)	2,178		2,148
Long-term debt to financing trusts	236		249
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	3
Long-term debt (including amounts due within one year)	0
Long-term debt to financing trusts	0
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	120
Long-term debt (including amounts due within one year)	2,178
Long-term debt to financing trusts	0
Baltimore Gas and Electric Company [Member] | Estimate of Fair Value Measurement [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Short-term liabilities	0
Long-term debt (including amounts due within one year)	0
Long-term debt to financing trusts	$236
[1]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.

Fair_Value_of_Financial_Assets3

Fair Value of Financial Assets and Liabilities - Fair Value Measurement of Assets and Liabilities, Recurring and Nonrecurring (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	$1,119	[1]	$1,230	[1]
Rabbi trust investments subtotal				[2]
Other investments	5		15
Total assets	14,081		11,162
Deferred compensation obligation	-107		-114
Total liabilities	-744		-573
Total net assets	13,337		10,589
Cash surrender value of life insurance investments excluded from Rabbi Trust investments			35
Mark-to-market derivative liabilities (noncurrent liabilities)	403		300
Mark-to-market derivative liabilities (current liabilities)	234		159
Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	31
Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-41
Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	13
Mark-to-market derivative liabilities (noncurrent liabilities)	289		285
Mark-to-market derivative liabilities (current liabilities)	235		158
Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-103
Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	27
Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-23
Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	245		459
Equity	4,630		3,913
Foreign	612		249
Equity funds subtotal	5,242		4,162
Corporate debt securities	2,262		1,784
U.S. Treasury and agencies	996		882
Foreign governments	95		87
State and municipal debt	438		294
Other	511		75
Fixed income subtotal	4,302		3,122
Middle market lending	366		314
Private equity	83		5
Real estate	3
Other	301		14
Nuclear decommissioning trust fund investments subtotal	10,542	[3]	8,076	[3]
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments	-5
Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15		26
Equity	7		16
Corporate debt securities	89		227
U.S. Treasury and agencies	8		49
State and municipal debt	10		20
Other	3
Fixed income subtotal	110		296
Middle market lending	184		112
Other			1
Pledged assets for Zion Station decommissioning subtotal	316	[4]	451	[4]
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments	3		7
Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1	[2]	2	[2]
Mutual funds	46	[2],[5]	54	[2],[5]
Rabbi trust investments subtotal	47	[2]	56	[2]
Deferred compensation obligation	-45		-53
Supplemental executive retirement plan fair value	1		1
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	11		32
Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	6,813		3,960
Proprietary trading	512		1,761
Effect of netting and allocation of collateral received/(paid)	5,296	[6]	4,424	[6]
Commodity derivative subtotal	2,029		1,297
Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-48		-32
Interest rate and foreign currency derivative			-69
Interest rate and foreign currency derivatives subtotal	-23		-37
Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-6,694		-3,020
Proprietary trading	-532		-1,703
Effect of netting and allocation of collateral received/(paid)	-6,702	[6]	-4,280	[6]
Commodity derivative subtotal	-524		-443
Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-54		-32
Interest rate and foreign currency derivative	0		-48
Interest rate and foreign currency derivatives subtotal	-113		-16
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1,119	[1]	1,230	[1]
Other investments	2		0
Total assets	5,305		4,533
Deferred compensation obligation	0		0
Total liabilities	-9		1
Total net assets	5,296		4,534
Collateral received from counterparties, net of collateral paid to counterparties	434		6
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fair Value, Inputs, Level 1 [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Fair Value, Inputs, Level 1 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	18
Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-14
Fair Value, Inputs, Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	208		459
Equity	2,423		1,642
Foreign	612		249
Equity funds subtotal	3,035		1,891
Corporate debt securities	0		0
U.S. Treasury and agencies	996		882
Foreign governments	0		0
State and municipal debt	0		0
Other	0		0
Fixed income subtotal	996		882
Middle market lending	0		0
Private equity	0		0
Real estate	0
Other	0		0
Nuclear decommissioning trust fund investments subtotal	4,239	[3]	3,232	[3]
Fair Value, Inputs, Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Equity	6		16
Corporate debt securities	0		0
U.S. Treasury and agencies	5		45
State and municipal debt	0		0
Other	0
Fixed income subtotal	5		45
Middle market lending	0		0
Other			0
Pledged assets for Zion Station decommissioning subtotal	11	[4]	61	[4]
Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	1	[2]	2	[2]
Mutual funds	46	[2],[5]	54	[2],[5]
Rabbi trust investments subtotal	47	[2]	56	[2]
Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	1,667		493
Proprietary trading	201		324
Effect of netting and allocation of collateral received/(paid)	1,982	[6]	863	[6]
Commodity derivative subtotal	-114		-46
Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-17		-30
Interest rate and foreign currency derivative			-30
Interest rate and foreign currency derivatives subtotal	-1		0
Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-2,241		-540
Proprietary trading	-195		-328
Effect of netting and allocation of collateral received/(paid)	-2,416	[6]	-869	[6]
Commodity derivative subtotal	-20		1
Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-25		-31
Interest rate and foreign currency derivative	0		-31
Interest rate and foreign currency derivatives subtotal	11		0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[1]
Other investments	0		0
Total assets	6,747		5,575
Deferred compensation obligation	-107		-114
Total liabilities	-427		-269
Total net assets	6,320		5,306
Collateral received from counterparties, net of collateral paid to counterparties	800		-124
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	31
Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-41
Fair Value, Inputs, Level 2 [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	13
Fair Value, Inputs, Level 2 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-103
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	9
Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-9
Fair Value, Inputs, Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	37		0
Equity	2,207		2,271
Foreign	0		0
Equity funds subtotal	2,207		2,271
Corporate debt securities	2,023		1,753
U.S. Treasury and agencies	0		0
Foreign governments	95		87
State and municipal debt	438		294
Other	511		75
Fixed income subtotal	3,067		2,209
Middle market lending	0		0
Private equity	0		0
Real estate	0
Other	301		14
Nuclear decommissioning trust fund investments subtotal	5,612	[3]	4,494	[3]
Fair Value, Inputs, Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15		26
Equity	1		0
Corporate debt securities	89		227
U.S. Treasury and agencies	3		4
State and municipal debt	10		20
Other	3
Fixed income subtotal	105		251
Middle market lending	0		0
Other			1
Pledged assets for Zion Station decommissioning subtotal	121	[4]	278	[4]
Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[2]	0	[2]
Mutual funds	0	[2],[5]	0	[2],[5]
Rabbi trust investments subtotal	0	[2]	0	[2]
Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	3,465		2,582
Proprietary trading	284		1,315
Effect of netting and allocation of collateral received/(paid)	2,757	[6]	3,131	[6]
Commodity derivative subtotal	992		766
Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-31		-2
Interest rate and foreign currency derivative			-39
Interest rate and foreign currency derivatives subtotal	-22		-37
Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-3,458		-1,890
Proprietary trading	-295		-1,256
Effect of netting and allocation of collateral received/(paid)	-3,557	[6]	-3,007	[6]
Commodity derivative subtotal	-196		-139
Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-29		-1
Interest rate and foreign currency derivative	0		-17
Interest rate and foreign currency derivatives subtotal	-124		-16
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[1]
Other investments	3		15
Total assets	2,029		1,054
Deferred compensation obligation	0		0
Total liabilities	-308		-305
Total net assets	1,721		749
Collateral received from counterparties, net of collateral paid to counterparties	172		-26
Mark-to-market derivative liabilities (noncurrent liabilities)			176
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fair Value, Inputs, Level 3 [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Equity	0		0
Foreign	0		0
Equity funds subtotal	0		0
Corporate debt securities	239		31
U.S. Treasury and agencies	0		0
Foreign governments	0		0
State and municipal debt	0		0
Other	0		0
Fixed income subtotal	239		31
Middle market lending	366		314
Private equity	83		5
Real estate	3
Other	0		0
Nuclear decommissioning trust fund investments subtotal	691	[3]	350	[3]
Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Equity	0		0
Corporate debt securities	0		0
U.S. Treasury and agencies	0		0
State and municipal debt	0		0
Other	0
Fixed income subtotal	0		0
Middle market lending	184		112
Other			0
Pledged assets for Zion Station decommissioning subtotal	184	[4]	112	[4]
Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[2]	0	[2]
Mutual funds	0	[2],[5]	0	[2],[5]
Rabbi trust investments subtotal	0	[2]	0	[2]
Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	1,681		885
Proprietary trading	27		122
Effect of netting and allocation of collateral received/(paid)	557	[6]	430	[6]
Commodity derivative subtotal	1,151		577
Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	0		0
Interest rate and foreign currency derivative			0
Interest rate and foreign currency derivatives subtotal	0		0
Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-995		-590
Proprietary trading	-42		-119
Effect of netting and allocation of collateral received/(paid)	-729	[6]	-404	[6]
Commodity derivative subtotal	-308		-305
Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	0		0
Interest rate and foreign currency derivative	0		0
Interest rate and foreign currency derivatives subtotal	0		0
Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	405	[1]	1,006	[1]
Other investments	3		15
Total assets	13,329		10,888
Derivative liabilities	-293	[7]	-210	[7]
Deferred compensation obligation	-31		-29
Total liabilities	-350		-291
Total net assets	12,979		10,597
Mark-to-market derivative liabilities (noncurrent liabilities)	105		120
Mark-to-market derivative liabilities (current liabilities)	214		142
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	8
Mark-to-market derivative liabilities (noncurrent liabilities)	1,540		804
Mark-to-market derivative liabilities (current liabilities)	4,947		2,023
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-12
Exelon Generation Co L L C [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	12
Mark-to-market derivative liabilities (noncurrent liabilities)	102	[8]	109	[9]
Mark-to-market derivative liabilities (current liabilities)	215	[8]	141	[9]
Exelon Generation Co L L C [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-2
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	27
Mark-to-market derivative liabilities (current liabilities)	2
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-23
Exelon Generation Co L L C [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	245		459
Equity	4,630		3,913
Foreign	612		249
Equity funds subtotal	5,242		4,162
Corporate debt securities	2,262		1,784
U.S. Treasury and agencies	996		882
Foreign governments	95		87
State and municipal debt	438		294
Other	511		75
Fixed income subtotal	4,302		3,122
Middle market lending	366		314
Private equity	83		5
Real estate	3
Other	301		14
Nuclear decommissioning trust fund investments subtotal	10,542	[3]	8,076	[3]
Exelon Generation Co L L C [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15		26
Equity	7		16
Corporate debt securities	89		227
U.S. Treasury and agencies	8		49
State and municipal debt	10		20
Other	3
Fixed income subtotal	110		296
Middle market lending	184		112
Other			1
Pledged assets for Zion Station decommissioning subtotal	316	[4]	451	[4]
Exelon Generation Co L L C [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[2]	0	[2]
Mutual funds	16	[2],[5]	13	[2],[5]
Rabbi trust investments subtotal	16	[2]	13	[2]
Cash surrender value of life insurance investments excluded from Rabbi Trust investments			10
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	6,813		3,960
Proprietary trading	512		1,761
Effect of netting and allocation of collateral received/(paid)	5,296	[6]	4,424	[6]
Commodity derivative subtotal	2,029		1,297
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-29		-32
Interest rate and foreign currency derivative			-62
Interest rate and foreign currency derivatives subtotal	-18		-30
Exelon Generation Co L L C [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-6,487		-2,827
Proprietary trading	-532		-1,703
Effect of netting and allocation of collateral received/(paid)	-6,702	[6]	-4,280	[6]
Commodity derivative subtotal	-317		-250
Exelon Generation Co L L C [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-35		-32
Interest rate and foreign currency derivative	0		-44
Interest rate and foreign currency derivatives subtotal	-2		-12
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	405	[1]	1,006	[1]
Other investments	0		0
Total assets	4,558		4,266
Deferred compensation obligation	0		0
Total liabilities	-9		1
Total net assets	4,549		4,267
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	18
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-14
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	208		459
Equity	2,423		1,642
Foreign	612		249
Equity funds subtotal	3,035		1,891
Corporate debt securities	0		0
U.S. Treasury and agencies	996		882
Foreign governments	0		0
State and municipal debt	0		0
Other	0		0
Fixed income subtotal	996		882
Middle market lending	0		0
Private equity	0		0
Real estate	0
Other	0		0
Nuclear decommissioning trust fund investments subtotal	4,239	[3]	3,232	[3]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Equity	6		16
Corporate debt securities	0		0
U.S. Treasury and agencies	5		45
State and municipal debt	0		0
Other	0
Fixed income subtotal	5		45
Middle market lending	0		0
Other			0
Pledged assets for Zion Station decommissioning subtotal	11	[4]	61	[4]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[2]	0	[2]
Mutual funds	16	[2],[5]	13	[2],[5]
Rabbi trust investments subtotal	16	[2]	13	[2]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	1,667		493
Proprietary trading	201		324
Effect of netting and allocation of collateral received/(paid)	1,982	[6]	863	[6]
Commodity derivative subtotal	-114		-46
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-17		-30
Interest rate and foreign currency derivative			-30
Interest rate and foreign currency derivatives subtotal	-1		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-2,241		-540
Proprietary trading	-195		-328
Effect of netting and allocation of collateral received/(paid)	-2,416	[6]	-869	[6]
Commodity derivative subtotal	-20		1
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 1 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-25		-31
Interest rate and foreign currency derivative	0		-31
Interest rate and foreign currency derivatives subtotal	11		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[1]
Other investments	0		0
Total assets	6,742		5,568
Deferred compensation obligation	-31		-29
Total liabilities	-240		-180
Total net assets	6,502		5,388
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	8
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-12
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	12
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-2
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	9
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	-9
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	37		0
Equity	2,207		2,271
Foreign	0		0
Equity funds subtotal	2,207		2,271
Corporate debt securities	2,023		1,753
U.S. Treasury and agencies	0		0
Foreign governments	95		87
State and municipal debt	438		294
Other	511		75
Fixed income subtotal	3,067		2,209
Middle market lending	0		0
Private equity	0		0
Real estate	0
Other	301		14
Nuclear decommissioning trust fund investments subtotal	5,612	[3]	4,494	[3]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	15		26
Equity	1		0
Corporate debt securities	89		227
U.S. Treasury and agencies	3		4
State and municipal debt	10		20
Other	3
Fixed income subtotal	105		251
Middle market lending	0		0
Other			1
Pledged assets for Zion Station decommissioning subtotal	121	[4]	278	[4]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[2]	0	[2]
Mutual funds	0	[2],[5]	0	[2],[5]
Rabbi trust investments subtotal	0	[2]	0	[2]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	3,465		2,582
Proprietary trading	284		1,315
Effect of netting and allocation of collateral received/(paid)	2,757	[6]	3,131	[6]
Commodity derivative subtotal	992		766
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-12		-2
Interest rate and foreign currency derivative			-32
Interest rate and foreign currency derivatives subtotal	-17		-30
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-3,458		-1,890
Proprietary trading	-295		-1,256
Effect of netting and allocation of collateral received/(paid)	-3,557	[6]	-3,007	[6]
Commodity derivative subtotal	-196		-139
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 2 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	-10		-1
Interest rate and foreign currency derivative	0		-13
Interest rate and foreign currency derivatives subtotal	-13		-12
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[1]	0	[1]
Other investments	3		15
Total assets	2,029		1,054
Deferred compensation obligation	0		0
Total liabilities	-101		-112
Total net assets	1,928		942
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Designated as Hedging Instrument [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Swap [Member] | Derivative Financial Instruments, Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Equity	0		0
Foreign	0		0
Equity funds subtotal	0		0
Corporate debt securities	239		31
U.S. Treasury and agencies	0		0
Foreign governments	0		0
State and municipal debt	0		0
Other	0		0
Fixed income subtotal	239		31
Middle market lending	366		314
Private equity	83		5
Real estate	3
Other	0		0
Nuclear decommissioning trust fund investments subtotal	691	[3]	350	[3]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Equity	0		0
Corporate debt securities	0		0
U.S. Treasury and agencies	0		0
State and municipal debt	0		0
Other	0
Fixed income subtotal	0		0
Middle market lending	184		112
Other			0
Pledged assets for Zion Station decommissioning subtotal	184	[4]	112	[4]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0	[2]	0	[2]
Mutual funds	0	[2],[5]	0	[2],[5]
Rabbi trust investments subtotal	0	[2]	0	[2]
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	1,681		885
Proprietary trading	27		122
Effect of netting and allocation of collateral received/(paid)	557	[6]	430	[6]
Commodity derivative subtotal	1,151		577
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Assets [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	0		0
Interest rate and foreign currency derivative			0
Interest rate and foreign currency derivatives subtotal	0		0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Commodity Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Economic hedges	-788		-397
Proprietary trading	-42		-119
Effect of netting and allocation of collateral received/(paid)	-729	[6]	-404	[6]
Commodity derivative subtotal	-101		-112
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Interest Rate Mark To Market Derivative Liabilities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Effect of netting and allocation of collateral received/(paid)	0		0
Interest rate and foreign currency derivative	0		0
Interest rate and foreign currency derivatives subtotal	0		0
Commonwealth Edison Co [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	25		0
Commodity derivative subtotal	-207	[10]	-193	[10]
Total assets	25		5
Deferred compensation obligation	-8		-8
Total liabilities	-215		-201
Total net assets	-190		-196
Mark-to-market derivative liabilities (noncurrent liabilities)	187		176
Mark-to-market derivative liabilities (current liabilities)	20		17
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mark-to-market derivative liabilities (noncurrent liabilities)	187	[11]	176	[11]
Mark-to-market derivative liabilities (current liabilities)	20	[11]	17	[11]
Commonwealth Edison Co [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	5	[12]
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	25		0
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	25		5
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	25		5
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	5	[12]
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	0		0
Deferred compensation obligation	-8		-8
Total liabilities	-8		-8
Total net assets	-8		-8
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	0	[12]
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Commodity derivative subtotal	-207	[10]	-193	[10]
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	-207		-193
Total net assets	-207		-193
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	0	[12]
PECO Energy Co [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	12		175
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	21		184
Deferred compensation obligation	-15		-17
Total liabilities	-15		-17
Total net assets	6		167
Mark-to-market derivative liabilities (noncurrent liabilities)	14
PECO Energy Co [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	9	[12]	9	[12]
PECO Energy Co [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	12		175
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	21		184
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	21		184
PECO Energy Co [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	9	[12]	9	[12]
PECO Energy Co [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	0		0
Deferred compensation obligation	-15		-17
Total liabilities	-15		-17
Total net assets	-15		-17
PECO Energy Co [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	0	[12]
PECO Energy Co [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		0
PECO Energy Co [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	0	[12]
Baltimore Gas and Electric Company [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	103		31
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	108		37
Deferred compensation obligation	-5		-6
Total liabilities	-5		-6
Total net assets	103		31
Baltimore Gas and Electric Company [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	5	[12]	6	[12]
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	103		31
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	108		37
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	108		37
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 1 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	5	[12]	6	[12]
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	0		0
Deferred compensation obligation	-5		-6
Total liabilities	-5		-6
Total net assets	-5		-6
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 2 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	0	[12]	0	[12]
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash equivalents	0		0
Commodity derivative subtotal	0	[10]	0	[10]
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		0
Baltimore Gas and Electric Company [Member] | Fair Value, Inputs, Level 3 [Member] | Rabbi Trust Investments [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Mutual funds	$0	[12]	$0	[12]
[1]	Excludes certain cash equivalents considered to be held-to-maturity and not reported at fair value.
[2]	The mutual funds held by the Rabbi trusts at Exelon Consolidated include $45 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2014, and $53 million related to deferred compensation and $1 million related to a Supplemental Executive Retirement Plan at December 31, 2013.
[3]	Excludes net liabilities of $5 million at both December 31, 2014 and 2013. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[4]	Excludes net assets of $3 million and $7 million at December 31, 2014 and 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.
[5]	Excludes $35 million and $32 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Exelon Consolidated. Excludes $11 million and $10 million of cash surrender value of life insurance investment at December 31, 2014 and 2013, respectively, at Generation.
[6]	Includes collateral postings (received) to/from counterparties. Collateral posted (received) to/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. Collateral posted (received) to/from counterparties, net of collateral paid to counterparties, totaled $6 million, $(124) million and $(26) million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2013.
[7]	(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.
[8]	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.
[9]	Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.
[10]	The Level 3 balance includes the current and noncurrent liability of $20 million and $187 million, respectively, at December 31, 2014, and $17 million and $176 million, respectively, at December 31, 2013, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[11]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
[12]	At PECO, excludes $14 million of the cash surrender value of life insurance investments at both December 31, 2014 and 2013

Fair_Value_of_Financial_Assets4

Fair Value of Financial Assets and Liabilities - Fair Value Reconciliation of Level 3 Assets and Liabilities Measured on a Recurring Basis (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Ending balance
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	749		656
Included in net income	532		-42
Included in other comprehensive income			2
Included in noncurrent payables to affiliates			0
Included in payable for Zion Station decommissioning	-2		0
Included in regulatory assets/liabilities	0	[1]	-118	[1]
Change in collateral	198		7
Purchases	598		297
Sales	-80		-86
Settlements	-64		-18
Transfers into Level 3 - (Asset) / Liability	7		-87
Transfers out of Level 3 - (Asset) / Liability	-207		-36
Ending balance	1,721		749
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	644		168
Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	350
Included in net income	6
Included in payable for Zion Station decommissioning	0
Change in collateral	0
Purchases	400		203
Sales	-15		-28
Settlements	-64		-18
Transfers into Level 3 - (Asset) / Liability	0		0
Transfers out of Level 3 - (Asset) / Liability	0		0
Ending balance	691		350
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	4		1
Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	112
Purchases			62
Sales	-50		-39
Settlements	0		0
Transfers into Level 3 - (Asset) / Liability	0		0
Transfers out of Level 3 - (Asset) / Liability	0		0
Ending balance	184		112
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	0		0
Fair Value, Inputs, Level 3 [Member] | Derivative [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	465
Purchases	76	[2]	28
Sales	-7		-11
Settlements	0		0
Transfers into Level 3 - (Asset) / Liability	7		-86	[1]
Transfers out of Level 3 - (Asset) / Liability	-201		-35
Ending balance	1,050		465
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	640		156
Fair Value, Inputs, Level 3 [Member] | Other Investments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	15
Included in noncurrent payables to affiliates			-8
Included in regulatory assets/liabilities			-218
Purchases	2		4
Sales	-8		-8
Settlements	0		0
Transfers into Level 3 - (Asset) / Liability	0		-1
Transfers out of Level 3 - (Asset) / Liability	-6		-1
Ending balance	3		15
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	0		0
Exelon Generation Co L L C [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Settlements			-215
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts	114		-207
Increase (Decrease) in Fair Value of Interest Rate Fair Value Hedging Instruments			11
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Settlements	-1		7
Exelon Generation Co L L C [Member] | Derivative [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Cash	34
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	942		949
Included in net income	532		-49
Included in other comprehensive income			-217
Included in noncurrent payables to affiliates			8
Included in payable for Zion Station decommissioning	-2		0
Included in regulatory assets/liabilities			0	[1]
Change in collateral	198		7
Purchases	598		297
Sales	-80		-86
Settlements	-64		-18
Transfers into Level 3 - (Asset) / Liability	7		-87
Transfers out of Level 3 - (Asset) / Liability	-207		-36
Ending balance	1,928		942
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	644		157
Decrease in Fair Value Adjustment	13		133
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance			183
Included in net income			2
Included in other comprehensive income			0
Included in noncurrent payables to affiliates	14
Included in payable for Zion Station decommissioning			0
Change in collateral			0
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Pledged Assets For Zion Station Decommissioning [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance			89
Included in net income	0		0
Included in other comprehensive income			0
Included in noncurrent payables to affiliates			0
Included in payable for Zion Station decommissioning	-2		0
Included in regulatory assets/liabilities	0	[1]	0	[1]
Change in collateral	0		0
Purchases	120
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Derivative [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance			660
Included in net income	526		-51	[3],[4]
Included in other comprehensive income			-219	[3]
Included in noncurrent payables to affiliates			0
Included in payable for Zion Station decommissioning	0		0
Included in regulatory assets/liabilities	0	[1]	0	[1]
Change in collateral	198		7
Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Other Investments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance			17
Included in net income	0		0
Included in other comprehensive income			2
Included in noncurrent payables to affiliates			0
Included in payable for Zion Station decommissioning	0		0
Included in regulatory assets/liabilities	0	[1]	0	[1]
Change in collateral	0		0
Commonwealth Edison Co [Member] | Fair Value, Inputs, Level 3 [Member] | Other Investments [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	-193	[3],[5]	-293	[3],[5]
Included in net income	0	[3]	0	[3],[5]
Included in other comprehensive income			0	[3],[5]
Included in noncurrent payables to affiliates			0	[3],[5]
Included in payable for Zion Station decommissioning	0	[3]	0	[3],[5]
Included in regulatory assets/liabilities	-14	[1],[3]	100	[1],[3],[5]
Change in collateral	0	[3]	0	[3],[5]
Purchases	0	[3]	0	[3],[5]
Sales	0	[3]	0	[3],[5]
Settlements	0	[3]	0	[3],[5]
Transfers into Level 3 - (Asset) / Liability	0	[3]	0	[3],[5]
Transfers out of Level 3 - (Asset) / Liability	0	[3]	0	[3],[5]
Ending balance	-207	[3]	-193	[3],[5]
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities	0	[3]	0	[3],[5]
Consolidation, Eliminations [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Purchases			0
Sales			0
Settlements			0
Transfers into Level 3 - (Asset) / Liability			0
Transfers out of Level 3 - (Asset) / Liability			0
Consolidation, Eliminations [Member] | Exelon Generation Co L L C [Member] | Fair Value, Inputs, Level 3 [Member] | Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Included in net income			7
Included in other comprehensive income			219
Included in noncurrent payables to affiliates	-14
Included in payable for Zion Station decommissioning			0
Included in regulatory assets/liabilities	14
Change in collateral			$0
[1]	Includes an increase of transfers into Level 3 arising from reductions in market liquidity, which resulted in less observable contract tenures in various locations.
[2]	Includes $34 million of fair value from contracts acquired as a result of the Integrys acquisition.
[3]	Includes $13 million and $133 million of decreases in fair value and $1 million and $(7) million of realized gains (losses) due to settlements associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the years ended December 31, 2014 and 2013, respectively.
[4]	Includes the reclassification of $114 million and $207 million of realized gains due to the settlement of derivative contracts for the years ended December 31, 2014 and 2013, respectively.
[5]	Includes $11 million of decreases in fair value and realized gains due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the year ended December 31, 2013. All items eliminate upon consolidation in Exelon’s Consolidated Financial Statements.

Fair_Value_of_Financial_Assets5

Fair Value of Financial Assets and Liabilities - Narrative (Details) (USD $)	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward Power Basis	$2.75
Forward Gas Basis	$0.34

Fair_Value_of_Financial_Assets6

Fair Value of Financial Assets and Liabilities - Fair Value Assets and Liabilities Measure on Recurring Basis Gain Loss Included in Earnings (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Operating Revenue [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains (losses) included in income	$614		($152)
Change in the unrealized gains (losses) relating to assets and liabilities held	663		40
Purchased Fuel and Electric [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains (losses) included in income	-88		108
Change in the unrealized gains (losses) relating to assets and liabilities held	-23		127
Other, net [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains (losses) included in income	6	[1]	2	[1]
Change in the unrealized gains (losses) relating to assets and liabilities held	4	[1]	1	[1]
Exelon Generation Co L L C [Member] | Operating Revenue [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains (losses) included in income	614		-158
Change in the unrealized gains (losses) relating to assets and liabilities held	663		30
Exelon Generation Co L L C [Member] | Purchased Fuel and Electric [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains (losses) included in income	-88		107
Change in the unrealized gains (losses) relating to assets and liabilities held	-23		126
Exelon Generation Co L L C [Member] | Other, net [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Total gains (losses) included in income	6	[1]	2	[1]
Change in the unrealized gains (losses) relating to assets and liabilities held	$4	[1]	$1	[1]
[1]	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.

Fair_Value_of_Financial_Assets7

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash collateral excluded	172,000,000		26,000,000
Exelon Generation Co L L C [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, fair value	293,000,000	[1]	210,000,000	[1]
Exelon Generation Co L L C [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, fair value	-15,000,000	[2],[3]	3,000,000	[2],[4]
Exelon Generation Co L L C [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, fair value	893,000,000	[2],[3]	488,000,000	[2],[4]
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward power price assets	15	[2],[5]	10	[2]
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward power price assets	15	[2],[5]	8	[2]
Forward gas price assets	1.52	[2],[5]	2.98	[6]
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward power price assets	117	[2],[5]	176	[2],[6]
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Proprietary Trading [Member] | Fair Value, Inputs, Level 3 [Member] | All Regions excluding New England [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward power price assets	76
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward power price assets	120	[2],[5]	176	[2],[6]
Forward gas price assets	14.02	[2],[5]	16.63	[6]
Exelon Generation Co L L C [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member] | All Regions excluding New England [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward power price assets	97		100
Forward gas price assets	8.14		5.7
Exelon Generation Co L L C [Member] | Option Model Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Volatility percentage	8.00%	[2]	15.00%
Exelon Generation Co L L C [Member] | Option Model Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Volatility percentage	257.00%	[2]	142.00%
Commonwealth Edison Co [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, fair value	-207,000,000	[3]	-193,000,000	[4]
Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Minimum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward heat rate	8.00%	[7]	8.00%	[7]
Marketability Reserve	3.50%		3.50%
Renewable factor	86.00%		84.00%
Commonwealth Edison Co [Member] | Income Approach Valuation Technique [Member] | Maximum [Member] | Derivative [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward heat rate	9.00%	[7]	9.00%	[7]
Marketability Reserve	8.00%		8.00%
Renewable factor	126.00%		128.00%
[1]	(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
[2]	The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
[3]	The fair values do not include cash collateral held on level three positions of $172 million as of December 31, 2014.
[4]	The fair values do not include cash collateral held on level three positions of $26 million as of December 31, 2013
[5]	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.
[6]	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 $100 and $5.70, respectively.
[7]	Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Narrative (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
		MWh		MWh		MWh
Derivative [Line Items]
Gain Loss On Interest Rate Swap Treasury Rate Lock Net Of Tax		$20		$5
Estimated percentage of natural gas purchases hedged		30.00%
Derivative, notional amount		1,491		2,651
Pre-tax net income impact associated with a hypothetical 10% increase in interest rates - exclusive upper bound		8
Ineffective portion recognized in income		18		2
Notional amount of interest rate swaps acquired from merger		1,900
Mark-to-market derivative liabilities		403		300
Mark-to-market derivative liabilities		234		159
Fair value of interest rate swaps from merger acquiree		150
Cash collateral held		69
Letters of credit held		16
Net Asset Liability Position After Contractual Right Of Offset		-90
Credit Derivative, Collateral Held Directly or by Third Parties Monetary Amount		2
PHI Merger [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities		100
Interest Rate Swap [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities		28
Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional amount of preissuance interest rate cash flow hedge derivatives		3,070
Reclassification out of Accumulated Other Comprehensive Income [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Notional amount of preissuance interest rate cash flow hedge derivatives		26
Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Hedges [Member] | Operating Revenue One [Member]
Derivative [Line Items]
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income		195		464		747
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]
Derivative [Line Items]
Derivative, notional amount		1,450		1,275
Increase in notional amount of derivative instruments		100
Increase in notional amount of derivative instruments		75
Derivative asset		29		26
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Notional amount of preissuance interest rate cash flow hedge derivatives		400
Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member]
Derivative [Line Items]
Derivative, notional amount		505
Interest Rate Swap [Member] | Derivative [Member]
Derivative [Line Items]
Derivative, notional amount		1,450
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Notional amount of preissuance interest rate cash flow hedge derivatives		400
Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | ExGen Texas Power [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities		8
Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Net receivable from electric utility		40
Credit exposure under off system sales		8
Incremental collateral for loss of investment grade credit rating		79
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Proprietary trading activities volume		10,571,000		8,762,000		12,958,000
Hypothetical increase in interest rates associated with variable-rate debt		50.00%
Unrealized gain (loss) on interest rate cash flow hedges, pretax, accumulated other comprehensive income (loss)	21
Mark-to-market derivative liabilities		105		120
Mark-to-market derivative liabilities		214		142
Derivative, collateral, right to reclaim cash		8		10
Expected reclassification from accumulated other comprehensive income to results of operations		2
Letters of credit posted		672		364
Cash collateral held		77		206
Letters of credit held		24		34
Cash collateral posted				72
Incremental collateral for loss of investment grade credit rating		2,400		2,000
Net Asset Liability Position After Contractual Right Of Offset		16
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Notional amount of preissuance interest rate cash flow hedge derivatives		770
Derivative asset		6,813		3,960
Mark-to-market derivative liabilities		1,540		804
Mark-to-market derivative liabilities		4,947		2,023
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Antelope Valle [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
DOE interest rate swap		485
Exelon Generation Co L L C [Member] | Designated as Hedging Instrument [Member] | Other Solar Projects [Member]
Derivative [Line Items]
Notional amounts on forward starting interest rate swaps		26
Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member]
Derivative [Line Items]
Cash flow hedge activity impact on pre-tax net income based on reclassification adjustment from accumulated other comprehensive income		195		683		1,368
Exelon Generation Co L L C [Member] | Total Cash Flow Hedges [Member] | Operating Revenue One [Member]
Derivative [Line Items]
Net unrealized pre-tax gain (loss) on effective cash flow hedges						5
Exelon Generation Co L L C [Member] | Derivative [Member]
Derivative [Line Items]
Derivative, collateral, right to reclaim cash		1,497
Exelon Generation Co L L C [Member] | Derivative [Member] | Other Solar Projects [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities		3
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities		2
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Fair Value Hedging [Member]
Derivative [Line Items]
Derivative, notional amount				550
Interest rate swaps previously held by acquiree		550
Derivative asset		7		23
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Derivative [Member]
Derivative [Line Items]
Derivative, notional amount		550
Exelon Generation Co L L C [Member] | Interest Rate Contract [Member]
Derivative [Line Items]
Derivative, notional amount		126
Exelon Generation Co L L C [Member] | Interest Rate Contract [Member] | Designated as Hedging Instrument [Member] | Cash Flow Hedging [Member]
Derivative [Line Items]
Increase in notional amount of derivative instruments		213
Notional amount of interest rate swaps acquired from merger		26
Exelon Generation Co L L C [Member] | Foreign Exchange Contract [Member]
Derivative [Line Items]
Derivative, notional amount		349
Commonwealth Edison Co [Member]
Derivative [Line Items]
Term of contract		20 years
Mark-to-market derivative liabilities		187		176
Mark-to-market derivative liabilities		20		17
Net receivable from electric utility		43
Cash collateral held		19
Commonwealth Edison Co [Member] | Designated as Hedging Instrument [Member]
Derivative [Line Items]
Derivative asset		0	[1]	0
Mark-to-market derivative liabilities		187	[1]	176	[1]
Mark-to-market derivative liabilities		20	[1]	17	[1]
PECO Energy Co [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities		14
Net receivable from electric utility		29
Credit exposure under natural gas supply and management agreements		8
Incremental collateral for loss of investment grade credit rating		$36
Minimum [Member]
Derivative [Line Items]
Expected generation hedged in next twelve months		93.00%
Expected generation hedged in year two		61.00%
Expected generation hedged in year three		31.00%
Minimum [Member] | Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged		10.00%
Maximum [Member]
Derivative [Line Items]
Expected generation hedged in next twelve months		96.00%
Expected generation hedged in year two		64.00%
Expected generation hedged in year three		34.00%
Maximum [Member] | Baltimore Gas and Electric Company [Member]
Derivative [Line Items]
Estimated percentage of natural gas purchases hedged		20.00%
[1]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative_Financial_Instrumen3

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Interest Rate Swap [Member] | Derivative [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	$15		($1)
Mark-to-market derivative assets (noncurrent assets)	8		38
Total mark-to-market derivative assets	23		37
Mark-to-market derivative liabilities (current liabilities)	1		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-114		-15
Total mark-to-market derivative liabilities	-113		-16
Interest Rate Derivative Fair Value Of Derivative Net	-90		21
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	12		-1
Mark-to-market derivative assets (noncurrent assets)	6		31
Total mark-to-market derivative assets	18		30
Mark-to-market derivative liabilities (current liabilities)	1		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-3		-11
Total mark-to-market derivative liabilities	-2		-12
Interest Rate Derivative Fair Value Of Derivative Net	16		18
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Derivative [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	7		3
Mark-to-market derivative assets (noncurrent assets)	5		3
Total mark-to-market derivative assets	12		6
Mark-to-market derivative liabilities (current liabilities)	-2		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	0		-1
Total mark-to-market derivative liabilities	-2		-2
Interest Rate Derivative Fair Value Of Derivative Net	10		4
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Proprietary Trading [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	20	[1]	15	[1]
Mark-to-market derivative assets (noncurrent assets)	7	[1]	15	[1]
Total mark-to-market derivative assets	27	[1]	30	[1]
Mark-to-market derivative liabilities (current liabilities)	-14	[1]	-18	[1]
Mark-to-market derivative liabilities (noncurrent liabilities)	-9	[1]	-13	[1]
Total mark-to-market derivative liabilities	-23	[1]	-31	[1]
Interest Rate Derivative Fair Value Of Derivative Net	4	[1]	-1	[1]
Interest Rate Swap [Member] | Exelon Generation Co L L C [Member] | Collateral And Netting [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	-22	[2]	-19	[2]
Mark-to-market derivative assets (noncurrent assets)	-7	[2]	-13	[2]
Total mark-to-market derivative assets	-29	[2]	-32	[2]
Mark-to-market derivative liabilities (current liabilities)	25	[2]	19	[2]
Mark-to-market derivative liabilities (noncurrent liabilities)	10	[2]	13	[2]
Total mark-to-market derivative liabilities	35	[2]	32	[2]
Interest Rate Derivative Fair Value Of Derivative Net	6	[2]	0	[2]
Other Segments [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	3
Mark-to-market derivative assets (noncurrent assets)	2
Total mark-to-market derivative assets	5
Mark-to-market derivative liabilities (current liabilities)	0
Mark-to-market derivative liabilities (noncurrent liabilities)	-111
Total mark-to-market derivative liabilities	-111
Interest Rate Derivative Fair Value Of Derivative Net	-106
Other Segments [Member] | Interest Rate Swap [Member] | Derivative [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0
Mark-to-market derivative assets (noncurrent assets)	1
Total mark-to-market derivative assets	1
Mark-to-market derivative liabilities (current liabilities)	0
Mark-to-market derivative liabilities (noncurrent liabilities)	-101
Total mark-to-market derivative liabilities	-101
Interest Rate Derivative Fair Value Of Derivative Net	-100
Other Segments [Member] | Interest Rate Swap [Member] | Collateral And Netting [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0	[2]
Mark-to-market derivative assets (noncurrent assets)	-19	[2]
Total mark-to-market derivative assets	-19	[2]
Mark-to-market derivative liabilities (current liabilities)	0	[2]
Mark-to-market derivative liabilities (noncurrent liabilities)	19	[2]
Total mark-to-market derivative liabilities	19	[2]
Interest Rate Derivative Fair Value Of Derivative Net	0	[2]
Designated as Hedging Instrument [Member] | Interest Rate Swap [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	7		0
Mark-to-market derivative assets (noncurrent assets)	1		26
Total mark-to-market derivative assets	8		26
Mark-to-market derivative liabilities (current liabilities)	-8		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-4		-10
Total mark-to-market derivative liabilities	-12		-11
Interest Rate Derivative Fair Value Of Derivative Net	-4		15
Designated as Hedging Instrument [Member] | Other Segments [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities (current liabilities)	0
Designated as Hedging Instrument [Member] | Other Segments [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	3		0
Mark-to-market derivative assets (noncurrent assets)	20		7
Total mark-to-market derivative assets	23		7
Mark-to-market derivative liabilities (current liabilities)			0
Mark-to-market derivative liabilities (noncurrent liabilities)	-29		-4
Total mark-to-market derivative liabilities	-29		-4
Interest Rate Derivative Fair Value Of Derivative Net	($6)		$3
[1]	Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of benefiting from shifts or changes in market interest rates.
[2]	Represents the netting of fair value balances with the same counterparty and any associated cash collateral.

Derivative_Financial_Instrumen4

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Gain (Loss) from Components Excluded from Assessment of Fair Value Hedge Effectiveness, Net	$4		$2
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member]
Derivative [Line Items]
Gain (Loss) on Swaps/Borrowings	15		-3		-1
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Gain (Loss) on Swaps/Borrowings	3		-24		-9
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Gain (Loss) on Swaps/Borrowings	2	[1]	-6	[1]	0	[1]
Designated as Hedging Instrument [Member] | Interest Expense [Member] | Fair Value Hedging [Member] | Exelon Generation Co L L C [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Gain (Loss) on Swaps/Borrowings	-16	[1]	-15	[1]	-6	[1]
Gain (Loss) on Fair Value Hedges Recognized in Earnings	$17		$16
[1]	For the years ended December 31, 2014 and 2013, the loss on Generation swaps included $(17) million and $16 million realized in earnings, respectively, with $4 million and $2 million excluded from hedge effectiveness testing, respectively.

Derivative_Financial_Instrumen5

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	$1,279		$727
Mark-to-market derivative assets (noncurrent assets)	773		607
Mark-to-market derivative liabilities (current liabilities)	-234		-159
Mark-to-market derivative liabilities (noncurrent liabilities)	-403		-300
Noncurrent Liability Interest Rate Swap AVSR			0
Total cash collateral received net of cash collateral posted			144
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,276		727
Mark-to-market derivative assets (noncurrent assets)	771		600
Mark-to-market derivative liabilities (current liabilities)	-214		-142
Mark-to-market derivative liabilities (noncurrent liabilities)	-105		-120
Commonwealth Edison Co [Member]
Derivative [Line Items]
Mark-to-market derivative liabilities (current liabilities)	-20		-17
Mark-to-market derivative liabilities (noncurrent liabilities)	-187		-176
Proprietary Trading [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	456		1,476
Mark-to-market derivative assets (noncurrent assets)	56		285
Total mark-to-market derivative assets	512		1,761
Mark-to-market derivative liabilities (current liabilities)	-468		-1,410
Mark-to-market derivative liabilities (noncurrent liabilities)	-64		-293
Total mark-to-market derivative liabilities	-532		-1,703
Total mark-to-market derivative net assets (liabilities)	-20		58
Collateral And Netting [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	-4,184	[1]	-3,364	[1]
Mark-to-market derivative assets (noncurrent assets)	-1,112	[1]	-1,060	[1]
Total mark-to-market derivative assets	-5,296	[1]	-4,424	[1]
Mark-to-market derivative liabilities (current liabilities)	5,200	[1]	3,292	[1]
Mark-to-market derivative liabilities (noncurrent liabilities)	1,502	[1]	988	[1]
Total mark-to-market derivative liabilities	6,702	[1]	4,280	[1]
Total mark-to-market derivative net assets (liabilities)	1,406	[1]	-144	[1]
Derivative [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,264		728
Mark-to-market derivative assets (noncurrent assets)	765		569
Total mark-to-market derivative assets	2,029		1,297
Mark-to-market derivative liabilities (current liabilities)	-235		-158
Mark-to-market derivative liabilities (noncurrent liabilities)	-289		-285
Total mark-to-market derivative liabilities	-524		-443
Total mark-to-market derivative net assets (liabilities)	1,505		854
Derivative [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	1,264	[2]	728	[3]
Mark-to-market derivative assets (noncurrent assets)	765	[2]	569	[3]
Total mark-to-market derivative assets	2,029	[2]	1,297	[3]
Mark-to-market derivative liabilities (current liabilities)	-215	[2]	-141	[3]
Mark-to-market derivative liabilities (noncurrent liabilities)	-102	[2]	-109	[3]
Total mark-to-market derivative liabilities	-317	[2]	-250	[3]
Total mark-to-market derivative net assets (liabilities)	1,712	[2]	1,047	[3]
Designated as Hedging Instrument [Member] | Exelon Generation Co L L C [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	4,992		2,616
Mark-to-market derivative assets (noncurrent assets)	1,821		1,344
Total mark-to-market derivative assets	6,813		3,960
Mark-to-market derivative liabilities (current liabilities)	-4,947		-2,023
Mark-to-market derivative liabilities (noncurrent liabilities)	-1,540		-804
Total mark-to-market derivative liabilities	-6,487		-2,827
Total mark-to-market derivative net assets (liabilities)	326		1,133
Current assets collateral offset	-416		-84
Noncurrent assets collateral offset	-171		-72
Current liabilities collateral offset	-599		-12
Collateral Amount Offset Against Fair Value Of Derivative Current Noncurrent Liability	-220
Total cash collateral received net of cash collateral posted	1,406
Designated as Hedging Instrument [Member] | Commonwealth Edison Co [Member]
Derivative [Line Items]
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets (noncurrent assets)	0	[4]	0	[4]
Total mark-to-market derivative assets	0	[4]	0
Mark-to-market derivative liabilities (current liabilities)	-20	[4]	-17	[4]
Mark-to-market derivative liabilities (noncurrent liabilities)	-187	[4]	-176	[4]
Total mark-to-market derivative liabilities	-207	[4]	-193	[4]
Total mark-to-market derivative net assets (liabilities)	($207)	[4]	($193)	[4]
[1]	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
[2]	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]	Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively. Current liabilities are shown net of collateral of $(12) million. Collateral related to noncurrent liabilities was $0 million. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at December 31, 2013.
[4]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative_Financial_Instrumen6

Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Ineffective portion recognized in income	$18	$2
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract			133
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	78	270
Net gains (losses) related to interest rate swaps and treasury rate locks	20	5
Net gain (loss) related to effective portion of changes in fair value of treasury rate locks	15	15
Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Reclassifications from accumulated OCI to net income	16,614	14,207	12,735
Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Accumulated OCI derivative gain - Beginning Balance	120	368
Effective portion of changes in fair value	-31	29
Accumulated OCI derivative gain - Ending Balance	-28	120
Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Accumulated OCI derivative gain - Beginning Balance	119	532
Effective portion of changes in fair value	0	0
Accumulated OCI derivative gain - Ending Balance	2	119
Operating Revenue One [Member] | Energy Related Hedges [Member] | Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Net gain (loss) of reclassifications from accumulated OCI to net income related to the settlements of swap contract		133
Operating Revenue One [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Reclassifications from accumulated OCI to net income	-117	-277
Operating Revenue One [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Reclassifications from accumulated OCI to net income	-117	-413
Purchased PowerOne [Member] | Total Cash Flow Hedges [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Ineffective portion recognized in income		0
Purchased PowerOne [Member] | Total Cash Flow Hedges [Member] | Exelon Generation Co L L C [Member]
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]
Ineffective portion recognized in income		$0

Derivative_Financial_Instrumen7

Derivative Financial Instruments - Summary of Economic Hedges (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Change in fair value of commodity positions	($92)	($5)	$6
Reclassification to realized at settlement	-2	-1	-3
Net mark-to market gains (losses)	-693	507	533
Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	-607	460	-241
Reclassification to realized at settlement		53	771
Net mark-to market gains (losses)		513	530
Operating Revenue [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	0	7	7
Intersegment Eliminations [Member] | Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	-6	-94
Reclassification to realized at settlement	0	13	101
Net mark-to market gains (losses)	0	7	7
Intersegment Eliminations [Member] | Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Interest Rate Swap [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	-94	-6	3
Interest Rate Swap [Member] | Intersegment Eliminations [Member] | Operating Revenue [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	0	0	0
Other Segments [Member] | Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	0	0	0
Other Segments [Member] | Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	-100	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	-100	0	0
Other Segments [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	-100	0	0
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Change in fair value of commodity positions	-607	466	-147
Reclassification to realized at settlement	8	40	670
Net mark-to market gains (losses)	-599	506	523
Exelon Generation Co L L C [Member] | Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	0	0	0
Exelon Generation Co L L C [Member] | Purchased Power [Member]
Derivative [Line Items]
Change in fair value of commodity positions	8	-5	6
Reclassification to realized at settlement	-2	-1	-3
Net mark-to market gains (losses)	-593	500	526
Exelon Generation Co L L C [Member] | Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	-413	286	-362
Reclassification to realized at settlement	231	-64	432
Net mark-to market gains (losses)	-182	222	70
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in fair value of commodity positions	-194	180	215
Reclassification to realized at settlement	-223	104	238
Net mark-to market gains (losses)	-417	284	453
Exelon Generation Co L L C [Member] | Operating Revenue [Member]
Derivative [Line Items]
Change in fair value of commodity positions	10	-1	0
Reclassification to realized at settlement	-2	-1	-3
Net mark-to market gains (losses)	-174	220	67
Exelon Generation Co L L C [Member] | Purchased Power And Fuel [Member]
Derivative [Line Items]
Change in fair value of commodity positions	0	0	0
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	-417	284	453
Exelon Generation Co L L C [Member] | Interest Expense [Member]
Derivative [Line Items]
Change in fair value of commodity positions	-2	-4	6
Reclassification to realized at settlement	0	0	0
Net mark-to market gains (losses)	-2	-4	6
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Purchased Power [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	6	-6	3
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Operating Revenue [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	8	-2	-3
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Purchased Power And Fuel [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	0	0	0
Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Interest Expense [Member]
Derivative [Line Items]
Net mark-to market gains (losses)	($2)	($4)	$6

Derivative_Financial_Instrumen8

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative [Line Items]
Change in fair value	$1	$1	$1
Reclassification to realized at settlement	3	-3	0
Net mark-to-market gains (losses)	-26	-39	96
Operating Revenue [Member]
Derivative [Line Items]
Change in fair value	-1	-22	-13
Reclassification to realized at settlement	-29	-15	108
Net mark-to-market gains (losses)	-30	-37	95
Interest Rate Swap [Member] | Operating Revenue [Member]
Derivative [Line Items]
Net mark-to-market gains (losses)	$4	($2)	$1

Derivative_Financial_Instrumen9

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) (Exelon Generation Co L L C [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Total Exposure Before Credit Collateral [Member]
Derivative [Line Items]
Investment grade	$1,629
Non-investment grade	49
Internally rated—investment grade	479
Internally rated—non-investment grade	60
Total	2,217
Credit Collateral [Member]
Derivative [Line Items]
Investment grade	62
Non-investment grade	19
Internally rated—investment grade	0
Internally rated—non-investment grade	4
Total	85
Net Exposure [Member]
Derivative [Line Items]
Investment grade	1,567
Non-investment grade	30
Internally rated—investment grade	479
Internally rated—non-investment grade	56
Total	2,132
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	1
Non-investment grade	0
Internally rated—investment grade	0
Internally rated—non-investment grade	0
Total	1
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]
Derivative [Line Items]
Investment grade	452
Non-investment grade	0
Internally rated—investment grade	0
Internally rated—non-investment grade	0
Total	$452

Recovered_Sheet2

Derivative Financial Instruments - Net Credit Exposure by Type of Counterparty (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Derivative [Line Items]
Cash collateral held	$69
Letters of credit held	16
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Cash collateral held	77	206
Letters of credit held	24	34
Exelon Generation Co L L C [Member] | Net Exposure [Member]
Derivative [Line Items]
Financial institutions	295
Investor-owned utilities, marketers, power producers	958
Energy cooperatives and municipalities	862
Other	17
Total	$2,132

Recovered_Sheet3

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) (Exelon Generation Co L L C [Member], USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Exelon Generation Co L L C [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Gross Liability	($1,433)	[1]	($1,056)	[1]
Offsetting Fair Value of In-the-Money Contracts Under Master Netting Arrangements	1,140	[2]	846	[2]
Derivative liabilities, fair value	($293)	[3]	($210)	[3]
[1]	(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting agreements.
[2]	(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
[3]	(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Debt_and_Credit_Agreements_Com

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		30-May-14		Mar. 28, 2014
Commercial Paper [Member]
Short-term Debt [Line Items]
Maximum Program Size	$8,300,000,000	[1],[2]	$8,300,000,000	[1],[2]
Outstanding commercial paper	424,000,000		319,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	8,500,000,000	[3]
Exelon Corporate [Member]
Short-term Debt [Line Items]
Average Interest Rate on Commercial Paper Borrowings	0.53%		0.35%
Exelon Corporate [Member] | Commercial Paper [Member]
Short-term Debt [Line Items]
Maximum Program Size			500,000,000	[1],[2]
Outstanding commercial paper	0		0
Average Interest Rate on Commercial Paper Borrowings	0.00%		0.27%
Exelon Corporate [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	500,000,000	[3]			500,000,000	[1],[2]
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Bilateral letters of credit	200,000,000
Exelon Generation Co L L C [Member] | Commercial Paper [Member]
Short-term Debt [Line Items]
Maximum Program Size	5,600,000,000	[1],[2]	5,600,000,000	[1],[2]
Outstanding commercial paper	0		0
Average Interest Rate on Commercial Paper Borrowings	0.32%		0.32%
Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	5,800,000,000	[3]			5,300,000,000	[2]
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Average Interest Rate on Commercial Paper Borrowings	0.50%		0.37%
Commonwealth Edison Co [Member] | Commercial Paper [Member]
Short-term Debt [Line Items]
Maximum Program Size			1,000,000,000	[1],[2]
Outstanding commercial paper	304,000,000		184,000,000
Average Interest Rate on Commercial Paper Borrowings	0.33%		0.40%
Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	1,000,000,000	[3]					1,000,000,000	[1],[2]
PECO Energy Co [Member] | Commercial Paper [Member]
Short-term Debt [Line Items]
Maximum Program Size			600,000,000	[1],[2]
Outstanding commercial paper	0		0
PECO Energy Co [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	600,000,000	[3]			600,000,000	[1],[2]
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Average Interest Rate on Commercial Paper Borrowings	0.61%		0.31%
Baltimore Gas and Electric Company [Member] | Commercial Paper [Member]
Short-term Debt [Line Items]
Maximum Program Size			600,000,000	[1],[2]	600,000,000	[1],[2]
Outstanding commercial paper	120,000,000		135,000,000
Average Interest Rate on Commercial Paper Borrowings	0.29%		0.31%
Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	$600,000,000	[3]
[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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
[2]	aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.
[3]	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below

Debt_and_Credit_Agreements_Sum

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) (USD $)	Dec. 31, 2014		30-May-14		Mar. 28, 2014
Short-term Debt [Line Items]
Facility draws	$0
Outstanding letters of credit	1,190,000,000	[1]
Actual available capacity	7,310,000,000
To Support Additional Commercial Paper	6,771,000,000	[2]
Exelon Corporate [Member]
Short-term Debt [Line Items]
Facility draws	0
Outstanding letters of credit	6,000,000	[1]
Actual available capacity	494,000,000
To Support Additional Commercial Paper	494,000,000	[2]
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Facility draws	0
Outstanding letters of credit	1,181,000,000	[1]
Actual available capacity	4,619,000,000
To Support Additional Commercial Paper	4,504,000,000	[2]
Credit facility agreements with minority and community banks	50,000,000
Letters of credit	9,000,000
Bilateral letters of credit	200,000,000
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Facility draws	0
Outstanding letters of credit	2,000,000	[1]
Actual available capacity	998,000,000
To Support Additional Commercial Paper	694,000,000	[2]
Credit facility agreements with minority and community banks	34,000,000
Letters of credit	16,000,000
PECO Energy Co [Member]
Short-term Debt [Line Items]
Facility draws	0
Outstanding letters of credit	1,000,000	[1]
Actual available capacity	599,000,000
To Support Additional Commercial Paper	599,000,000	[2]
Credit facility agreements with minority and community banks	34,000,000
Letters of credit	21,000,000
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Facility draws	0
Outstanding letters of credit	0	[1]
Actual available capacity	600,000,000
To Support Additional Commercial Paper	480,000,000	[2]
Credit facility agreements with minority and community banks	5,000,000
Letters of credit	1,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Maximum Program Size	8,500,000,000	[3]
Revolving Credit Facility [Member] | Exelon Corporate [Member]
Short-term Debt [Line Items]
Maximum Program Size	500,000,000	[3]	500,000,000	[4],[5]
Revolving Credit Facility [Member] | Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Maximum Program Size	5,800,000,000	[3]	5,300,000,000	[5]
Revolving Credit Facility [Member] | Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Maximum Program Size	1,000,000,000	[3]			1,000,000,000	[4],[5]
Revolving Credit Facility [Member] | PECO Energy Co [Member]
Short-term Debt [Line Items]
Maximum Program Size	600,000,000	[3]	600,000,000	[4],[5]
Revolving Credit Facility [Member] | Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Maximum Program Size	$600,000,000	[3]
[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
[2]	Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program.
[3]	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below
[4]	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
[5]	aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.

Debt_and_Credit_Agreements_Sum1

Debt and Credit Agreements - Summary of Short-term Borrowing Activities (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Commonwealth Edison Co [Member]
Short-term Debt [Line Items]
Average borrowings	$415	$203	$110
Maximum borrowings outstanding	597	446	366
Average interest rates, computed on a daily basis	0.33%	0.40%	0.50%
Average interest rates at year end	0.50%	0.37%
Exelon Corporate [Member]
Short-term Debt [Line Items]
Average borrowings	571	254	199
Maximum borrowings outstanding	1,164	682	505
Average interest rates, computed on a daily basis	0.32%	0.37%	0.48%
Average interest rates at year end	0.53%	0.35%
Exelon Generation Co L L C [Member]
Short-term Debt [Line Items]
Average borrowings	93	42	4
Maximum borrowings outstanding	552	291	165
Average interest rates, computed on a daily basis	0.32%	0.32%	0.45%
Baltimore Gas and Electric Company [Member]
Short-term Debt [Line Items]
Average borrowings	64	35	6
Maximum borrowings outstanding	$180	$135	$76
Average interest rates, computed on a daily basis	0.29%	0.31%	0.43%
Average interest rates at year end	0.61%	0.31%

Debt_and_Credit_Agreements_Nar

Debt and Credit Agreements - Narrative (Details) (USD $)

1 Months Ended

3 Months Ended

0 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

Jun. 30, 2014

Jun. 30, 2014

Sep. 30, 2013

Dec. 31, 2014

Jan. 13, 2015

Jul. 31, 2011

Sep. 30, 2012

Jun. 11, 2014

31-May-14

Dec. 31, 2013

30-May-14

Mar. 28, 2014

Sep. 18, 2014

Feb. 06, 2014

Oct. 24, 2014

MW

MW

MW

Debt Instrument [Line Items]

Outstanding letters of credit

$1,190,000,000

[1]

Bridge loan

3,200,000,000

7,200,000,000

Long-term debt, gross

20,756,000,000

18,760,000,000

Equity units issued

23,000,000

Underwriting fee

60,000,000

35,000,000

Equity units, annual distribution rate

6.50%

Forward contract, payment rate

4.00%

Long-term debt

131,000,000

131,000,000

21,404,000,000

Collateral amount of debt

2,700,000,000

Outstanding borrowings/facility draws

0

Debt Continental Project [Member]

Debt Instrument [Line Items]

Generation capacity of portfolio

667

Designated as Hedging Instrument [Member]

Debt Instrument [Line Items]

Notional amount of preissuance interest rate cash flow hedge derivatives

3,070,000,000

Long Term Debt Issuances [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

2.50%

2.50%

Senior Notes [Member]

Debt Instrument [Line Items]

Long-term debt, gross

7,071,000,000

7,571,000,000

Junior Subordinated Debt [Member]

Debt Instrument [Line Items]

Long-term debt, gross

1,150,000,000

1,150,000,000

1,150,000,000

0

Convertible Debt Securities [Member]

Debt Instrument [Line Items]

Conversion price

$50

$50

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 adders for LIBOR-based borrowings

0.00165

Equity units, share price

$43.75

Common shares, issuable at maturity

1.1429

Minimum [Member]

Debt Instrument [Line Items]

Equity units, share price

$35

Common shares, issuable at maturity

1.4286

Revolving Credit Facility [Member] | Parent [Member]

Debt Instrument [Line Items]

Line of credit facility, cumulative committed amount

315,000,000

Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

8,500,000,000

[2]

Bridge Loan [Member]

Debt Instrument [Line Items]

Interest expense, short-term borrowings

31,000,000

Commonwealth Edison Co [Member]

Debt Instrument [Line Items]

Additional amounts available upon request under current credit facilities

500,000,000

Outstanding letters of credit

2,000,000

[1]

Basis points adders for prime-based borrowings

0.08%

Basis points adders for LIBOR-based borrowings

0.01075

Long-term debt, gross

5,977,000,000

5,694,000,000

Interest rate on long-term debt

6.35%

[3]

Long-term debt

6,183,000,000

Outstanding borrowings/facility draws

0

Commonwealth Edison Co [Member] | Letter of Credit [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

500,000,000

[4]

Commonwealth Edison Co [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

1,000,000,000

[2]

1,000,000,000

[4],[5]

Exelon Corporate [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

6,000,000

[1]

Basis points adders for prime-based borrowings

0.28%

Basis points adders for LIBOR-based borrowings

0.01275

Long-term debt, gross

3,808,000,000

2,658,000,000

Long-term debt

3,808,000,000

Outstanding borrowings/facility draws

0

Exelon Corporate [Member] | Senior Notes [Member] | Subsequent Event [Member] | Fixed Rate Note, 4.55% Due 2015 [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

4.55%

Redemption of debt

550,000,000

Exelon Corporate [Member] | Junior Subordinated Debt [Member]

Debt Instrument [Line Items]

Long-term debt, gross

1,150,000,000

0

Exelon Corporate [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

500,000,000

[2]

500,000,000

[4],[5]

Exelon Generation Co L L C [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

1,181,000,000

[1]

Basis points adders for prime-based borrowings

0.28%

Basis points adders for LIBOR-based borrowings

0.01275

Long-term debt, gross

8,134,000,000

7,552,000,000

Long-term debt

8,134,000,000

Outstanding borrowings/facility draws

0

Exelon Generation Co L L C [Member] | Debt Continental Project [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

6.00%

Principal amount of debt

613,000,000

Exelon Generation Co L L C [Member] | Continetal Wind [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

131,000,000

Outstanding letters of credit

47,000,000

Aggregate bank commitments under unsecured revolving credit facilities

10,000,000

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

Debt Instrument [Line Items]

Notional amount of preissuance interest rate cash flow hedge derivatives

770,000,000

Exelon Generation Co L L C [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member] | Debt Continental Project [Member]

Debt Instrument [Line Items]

Non-recourse debt, interest rate swap

350,000,000

Gain from exchange offer

26,000,000

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

Debt Instrument [Line Items]

Non-recourse debt, interest rate swap

505,000,000

Exelon Generation Co L L C [Member] | ExgenRenewablesI425June62021[Member] | Interest Rate Swap [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

2.03%

Non-recourse debt, interest rate swap

240,000,000

Exelon Generation Co L L C [Member] | Sacramento PV Energy [Member]

Debt Instrument [Line Items]

Non-recourse debt, interest rate swap

30,000,000

Generation capacity of portfolio

30

Outstanding borrowings/facility draws

35,000,000

Exelon Generation Co L L C [Member] | Constellation Solar Horizons Financing [Member]

Debt Instrument [Line Items]

Non-recourse debt, interest rate swap

29,000,000

Non-recourse debt, commitment

38,000,000

Generation capacity of portfolio

16

Outstanding borrowings/facility draws

34,000,000

Non-recourse debt, hedge percentage

75.00%

Exelon Generation Co L L C [Member] | Denver International Airport [Member]

Debt Instrument [Line Items]

Outstanding borrowings/facility draws

7,000,000

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

Debt Instrument [Line Items]

Outstanding borrowings/facility draws

10,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member]

Debt Instrument [Line Items]

Long-term debt, gross

5,771,000,000

6,271,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member] | ExGen Texas Power [Member]

Debt Instrument [Line Items]

Principal amount of debt

675,000,000

Exelon Generation Co L L C [Member] | Senior Notes [Member] | ExGen Texas Power [Member] | London Interbank Offered Rate (LIBOR) [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

4.75%

Exelon Generation Co L L C [Member] | Senior Notes [Member] | Subsequent Event [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

2.95%

Principal amount of debt

750,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Continetal Wind [Member]

Debt Instrument [Line Items]

Non-recourse debt

592,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExGen Texas Power [Member]

Debt Instrument [Line Items]

Non-recourse debt

673,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | ExgenRenewablesI425June62021[Member]

Debt Instrument [Line Items]

Non-recourse debt

282,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

156,000,000

Non-recourse debt

557,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Sacramento PV Energy [Member]

Debt Instrument [Line Items]

Non-recourse debt

41,000,000

Non-recourse debt, hedge percentage

75.00%

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Denver International Airport [Member]

Debt Instrument [Line Items]

Non-recourse debt

7,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Holyoke [Member]

Debt Instrument [Line Items]

Non-recourse debt

10,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Upstream Gas Property [Member]

Debt Instrument [Line Items]

Non-recourse debt, commitment

110,000,000

Non-recourse debt, commitment increase available

500,000,000

Outstanding borrowings/facility draws

77,000,000

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Long Term Debt Issuances [Member] | ExGen Texas Power [Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

2.34%

Exelon Generation Co L L C [Member] | Non Recourse Debt [Member] | Long Term Debt Issuances [Member] | ExgenRenewablesI425June62021[Member]

Debt Instrument [Line Items]

Interest rate on long-term debt

4.25%

Long-term debt

300,000,000

Exelon Generation Co L L C [Member] | DOE Financing Project [Member] | DOE Project Financing, 3.092% January 2, 2037 [Member]

Debt Instrument [Line Items]

Non-recourse debt, interest rate swap

485,000,000

Non-recourse debt, commitment

646,000,000

Exelon Generation Co L L C [Member] | Sumitomo Bank [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

100,000,000

Exelon Generation Co L L C [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

5,800,000,000

[2]

5,300,000,000

[4]

PECO Energy Co [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

1,000,000

[1]

Basis points adders for prime-based borrowings

0.00%

Basis points adders for LIBOR-based borrowings

0.009

Long-term debt, gross

2,250,000,000

2,200,000,000

Long-term debt

2,434,000,000

Outstanding borrowings/facility draws

0

PECO Energy Co [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

600,000,000

[2]

600,000,000

[4],[5]

Baltimore Gas and Electric Company [Member]

Debt Instrument [Line Items]

Outstanding letters of credit

0

[1]

Basis points adders for prime-based borrowings

0.00%

Basis points adders for LIBOR-based borrowings

0.01

Long-term debt, gross

1,945,000,000

2,015,000,000

Long-term debt

2,203,000,000

Outstanding borrowings/facility draws

0

Baltimore Gas and Electric Company [Member] | Revolving Credit Facility [Member]

Debt Instrument [Line Items]

Line of credit facility, maximum borrowing capacity

600,000,000

[2]

Cash Flow Hedging [Member] | Interest Rate Swap [Member] | Designated as Hedging Instrument [Member]

Debt Instrument [Line Items]

Notional amount of preissuance interest rate cash flow hedge derivatives

400,000,000

Reclassification out of Accumulated Other Comprehensive Income [Member] | Cash Flow Hedging [Member] | Designated as Hedging Instrument [Member]

Debt Instrument [Line Items]

Notional amount of preissuance interest rate cash flow hedge derivatives

$26,000,000

[1]

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

[2]

Excludes additional credit facility agreements for Generation, ComEd, PECO 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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below

[3]

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

[4]

aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.

[5]

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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.

Debt_and_Credit_Agreements_Sum2

Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Nov. 24, 2014	Jan. 09, 2015
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	$1,190	[1]
Credit facility threshold	2.50 to 1
Credit facility threshold	2.5
Exelon Generation Co L L C [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	1,181	[1]
Credit facility threshold	3.00 to 1
Credit facility threshold	3
Commonwealth Edison Co [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	2	[1]
Credit facility threshold	2.00 to 1
Credit facility threshold	2
PECO Energy Co [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	1	[1]
Credit facility threshold	2.00 to 1
Credit facility threshold	2
Baltimore Gas and Electric Company [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount	0	[1]
Credit facility threshold	2.00 to 1
Credit facility threshold	2
citibank Bank [Member] | Exelon Generation Co L L C [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount			25
CIBC Bank [Member] | Exelon Generation Co L L C [Member]
Line of Credit Facility [Line Items]
Letters of Credit Outstanding, Amount				$75
[1]	Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.

Debt_and_Credit_Agreements_Sum3

Debt and Credit Agreements - Summary of Interest Coverage Ratios (Details)	Dec. 31, 2014
Debt Instrument [Line Items]
Interest coverage ratio	919.00%
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Interest coverage ratio	1235.00%
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Interest coverage ratio	703.00%
PECO Energy Co [Member]
Debt Instrument [Line Items]
Interest coverage ratio	872.00%
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Interest coverage ratio	928.00%

Debt_and_Credit_Agreements_Sum4

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Jun. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Gross	$20,756,000,000			$18,760,000,000
Unamortized debt discount and premium, net	-37,000,000			-19,000,000
Long-term debt (including amounts due within one year)	441,000,000			384,000,000
Fair value hedge carrying value adjustment, net	4,000,000			7,000,000
Long-term debt due within one year	-1,802,000,000			-1,509,000,000
Long-term debt	19,362,000,000			17,623,000,000
Long-term debt to financing trusts	648,000,000			648,000,000
Total long-term debt to financing trusts	648,000,000	[1]		648,000,000	[1]
ComEd Financing Three Affiliate [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	6.35%	[1]
Long-term debt to financing trusts	206,000,000	[1]		206,000,000	[1]
PECO Trust Three Affiliate [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	7.38%	[1]
Long-term debt to financing trusts	81,000,000	[1]		81,000,000	[1]
PECO Trust Four Affiliate [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	5.75%	[1]
Long-term debt to financing trusts	103,000,000	[1]		103,000,000	[1]
BGE Trust Member [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	6.20%	[1]
Long-term debt to financing trusts	258,000,000	[1]		258,000,000	[1]
Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Maximum interest rate on long-term debt	6.50%
Long-term Debt, Gross	1,150,000,000		1,150,000,000	0
Secured Debt [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	1.20%	[2],[3]
Maximum interest rate on long-term debt	6.45%	[2],[3]
Long-term Debt, Gross	8,079,000,000	[2],[3]		7,746,000,000	[2],[3]
Unsecured Debt [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.80%
Maximum interest rate on long-term debt	6.35%
Long-term Debt, Gross	1,750,000,000			1,750,000,000
Rate Stabilization Bonds [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	5.72%
Maximum interest rate on long-term debt	5.82%
Long-term Debt, Gross	195,000,000			265,000,000
Senior Notes [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.00%
Maximum interest rate on long-term debt	7.60%
Long-term Debt, Gross	7,071,000,000			7,571,000,000
Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	3.25%
Maximum interest rate on long-term debt	3.35%
Long-term Debt, Gross	70,000,000			0
Pollution Control Notes [Member]
Debt Instrument [Line Items]
Maximum interest rate on long-term debt	4.10%
Long-term Debt, Gross	0			20,000,000
Non Recourse Fixed Rate [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.33%
Maximum interest rate on long-term debt	6.00%
Long-term Debt, Gross	1,166,000,000			1,077,000,000
Non Recourse Variable Rate [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.41%
Maximum interest rate on long-term debt	5.00%
Long-term Debt, Gross	1,101,000,000			150,000,000
Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	6.95%	[4]
Maximum interest rate on long-term debt	7.83%	[4]
Long-term Debt, Gross	174,000,000	[4]		181,000,000	[4]
Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital lease obligations, noncurrent	32,000,000			41,000,000
Due in 2015	3,000,000
Due in 2016	4,000,000
Due in 2018	4,000,000
Due in 2019	5,000,000
Due in 2020	12,000,000
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	8,134,000,000			7,552,000,000
Unamortized debt discount and premium, net	-14,000,000			11,000,000
Long-term debt (including amounts due within one year)	146,000,000			166,000,000
Long-term debt due within one year	-614,000,000			-561,000,000
Long-term debt	6,709,000,000			5,645,000,000
Long-term debt to financing trusts	943,000,000			1,523,000,000
Debt and Capital Lease Obligations	7,652,000,000			7,168,000,000
Capital lease obligations, noncurrent	24,000,000			33,000,000
Due in 2015	3,000,000
Due in 2016	4,000,000
Due in 2017	4,000,000
Due in 2018	4,000,000
Due in 2020	4,000,000
Exelon Generation Co L L C [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.00%
Maximum interest rate on long-term debt	7.60%
Long-term Debt, Gross	5,771,000,000			6,271,000,000
Exelon Generation Co L L C [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	3.25%
Long-term Debt, Gross	70,000,000			0
Exelon Generation Co L L C [Member] | Pollution Control Notes [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	4.10%
Long-term Debt, Gross	0			20,000,000
Exelon Generation Co L L C [Member] | Non Recourse Fixed Rate [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.33%
Maximum interest rate on long-term debt	6.00%
Long-term Debt, Gross	1,166,000,000			1,077,000,000
Exelon Generation Co L L C [Member] | Non Recourse Variable Rate [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.41%
Maximum interest rate on long-term debt	5.00%
Long-term Debt, Gross	1,101,000,000			150,000,000
Exelon Generation Co L L C [Member] | Notes Payable, Other Payables [Member]
Debt Instrument [Line Items]
Maximum interest rate on long-term debt	7.83%	[5]
Long-term Debt, Gross	26,000,000	[5]		33,000,000	[5]
Exelon Generation Co L L C [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Due in 2019	5,000,000
Exelon Generation Co L L C [Member] | Social Security Administration [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.93%
Long-term Debt, Gross	0			1,000,000
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	5,977,000,000			5,694,000,000
Unamortized debt discount and premium, net	-19,000,000			-19,000,000
Long-term debt due within one year	-260,000,000			-617,000,000
Long-term debt	5,698,000,000			5,058,000,000
Interest rate on long-term debt	6.35%	[6]
Long-term debt to financing trusts	206,000,000			206,000,000
Debt and Capital Lease Obligations	5,698,000,000			5,058,000,000
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	206,000,000	[1]
Commonwealth Edison Co [Member] | Notes Payable to Banks [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	6.95%	[7]
Maximum interest rate on long-term debt	7.49%	[7]
Long-term Debt, Gross	148,000,000	[7]		148,000,000	[7]
Commonwealth Edison Co [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital lease obligations, noncurrent	8,000,000			8,000,000
Due in 2020	1,000,000
Commonwealth Edison Co [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	1.95%	[8],[9]
Maximum interest rate on long-term debt	6.45%	[8],[9]
Long-term Debt, Gross	5,829,000,000	[8],[9]		5,546,000,000	[8],[9]
PECO Energy Co [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	2,250,000,000			2,200,000,000
Unamortized debt discount and premium, net	-4,000,000			-3,000,000
Long-term debt	2,246,000,000			1,947,000,000
Long-term debt to financing trusts	184,000,000	[10]		184,000,000	[10]
Long-term debt due within one year	0			-250,000,000
Debt and Capital Lease Obligations	2,246,000,000			1,947,000,000
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	7.38%	[10]
Long-term debt to financing trusts	81,000,000	[10]		81,000,000	[10]
PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	5.75%	[10]
Long-term debt to financing trusts	103,000,000	[10]		103,000,000	[10]
PECO Energy Co [Member] | First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	1.20%	[11],[12]
Maximum interest rate on long-term debt	5.95%	[11],[12]
Long-term Debt, Gross	2,250,000,000	[11],[12]		2,200,000,000	[11],[12]
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	1,945,000,000			2,015,000,000
Unamortized debt discount and premium, net	-3,000,000			-4,000,000
Long-term debt	1,867,000,000			1,941,000,000
Long-term debt to financing trusts	258,000,000			258,000,000
Long-term debt due within one year	-75,000,000			-70,000,000
Debt and Capital Lease Obligations				2,011,000,000
Long-term debt	1,867,000,000			1,941,000,000
Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member]
Debt Instrument [Line Items]
Interest rate on long-term debt	6.20%	[13]
Long-term debt to financing trusts	258,000,000	[13]		258,000,000	[13]
Baltimore Gas and Electric Company [Member] | Unsecured Debt [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	2.80%
Maximum interest rate on long-term debt	6.35%
Long-term Debt, Gross	1,750,000,000			1,750,000,000
Baltimore Gas and Electric Company [Member] | Rate Stabilization Bonds [Member]
Debt Instrument [Line Items]
Minimum interest rate on long-term debt	5.72%
Maximum interest rate on long-term debt	5.82%
Long-term Debt, Gross	$195,000,000			$265,000,000
[1]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[2]	Includes first mortgage bonds issued under the ComEd and PECO mortgage indentures securing pollution control bonds and notes.
[3]	Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s assets are subject to the liens of their respective mortgage indentures.
[4]	Includes capital lease obligations of $32 million and $41 million at December 31, 2014 and 2013, respectively. Lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $12 million will be made in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.
[5]	Includes Generation’s capital lease obligations of $24 million and $33 million at December 31, 2014 and 2013, respectively. Generation will make lease payments of $3 million, $4 million, $4 million, $4 million, $5 million and $4 million in 2015, 2016, 2017, 2018, 2019 and thereafter, respectively.
[6]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
[7]	Includes ComEd’s capital lease obligations of $8 million at both December 31, 2014 and 2013, respectively. Lease payments of less than $1 million will be made from 2015 through expiration at 2053.
[8]	Includes first mortgage bonds issued under the ComEd mortgage indenture securing pollution control bonds and notes.
[9]	Substantially all of ComEd’s assets other than expressly excepted property are subject to the lien of its mortgage indenture.
[10]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[11]	Includes first mortgage bonds issued under the PECO mortgage indenture securing pollution control bonds and notes.
[12]	Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
[13]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.

Debt_and_Credit_Agreements_Sch

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) (USD $)	Dec. 31, 2014		Jun. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
2015	$1,739,000,000
2016	1,269,000,000
2017	2,400,000,000
2018	1,415,000,000
2019	982,000,000
Thereafter	13,599,000,000	[1]
Total	21,404,000,000		131,000,000
Long-term debt to financing trusts	648,000,000			648,000,000
BGE Trust Member [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	258,000,000	[2]		258,000,000	[2]
ComEd Financing Three Affiliate [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	206,000,000	[2]		206,000,000	[2]
ComEd, PECO and BGE Financing Trusts [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	648,000,000	[2]
PECO Financing Trusts [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	184,000,000	[2]
Exelon Generation Co L L C [Member]
Debt Instrument [Line Items]
2015	604,000,000
2016	4,000,000
2017	705,000,000
2018	75,000,000
2019	682,000,000
Thereafter	6,064,000,000
Total	8,134,000,000
Long-term debt to financing trusts	943,000,000			1,523,000,000
Commonwealth Edison Co [Member]
Debt Instrument [Line Items]
2015	260,000,000
2016	665,000,000
2017	425,000,000
2018	840,000,000
2019	300,000,000
Thereafter	3,693,000,000	[3]
Total	6,183,000,000
Long-term debt to financing trusts	206,000,000			206,000,000
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	206,000,000	[2]
PECO Energy Co [Member]
Debt Instrument [Line Items]
2015	0
2016	300,000,000
2017	0
2018	500,000,000
2019	0
Thereafter	1,634,000,000	[4]
Total	2,434,000,000
Long-term debt to financing trusts	184,000,000	[5]		184,000,000	[5]
Baltimore Gas and Electric Company [Member]
Debt Instrument [Line Items]
2015	75,000,000
2016	300,000,000
2017	120,000,000
2018	0
2019	0
Thereafter	1,708,000,000	[6]
Total	2,203,000,000
Long-term debt to financing trusts	258,000,000			258,000,000
Baltimore Gas and Electric Company [Member] | BGE Trust Member [Member]
Debt Instrument [Line Items]
Long-term debt to financing trusts	$258,000,000	[7]		$258,000,000	[7]
[1]	Includes $648 million due to ComEd, PECO and BGE financing trusts.
[2]	Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
[3]	Includes $206 million due to ComEd financing trust.
[4]	Includes $184 million due to PECO financing trusts.
[5]	Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
[6]	ncludes $258 million due to BGE financing trust.
[7]	Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.

Income_Taxes_Components_of_Inc

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Income taxes	$666	$1,044	$627
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Income taxes	207	615	500
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Income taxes	268	152	239
PECO Energy Co [Member]
Income Taxes [Line Items]
Income taxes	114	162	127
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current	0	0	0
Income taxes	140	134	7
Internal Revenue Service (IRS) [Member]
Income Taxes [Line Items]
Current	121	744	37
Deferred	576	140	701
Investment Tax Credit	20	15	11
Internal Revenue Service (IRS) [Member] | Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current	360	250	104
Deferred	-35	360	326
Investment Tax Credit	16	11	6
Internal Revenue Service (IRS) [Member] | Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current	-171	160	-40
Deferred	395	-27	237
Investment Tax Credit	2	2	2
Internal Revenue Service (IRS) [Member] | PECO Energy Co [Member]
Income Taxes [Line Items]
Current	28	126	88
Deferred	87	23	25
Investment Tax Credit	0	1	2
Internal Revenue Service (IRS) [Member] | Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Current	24	9	-97
Deferred	90	100	101
Investment Tax Credit	1	1	1
State and Local Jurisdiction [Member]
Income Taxes [Line Items]
Current	42	181	-25
Deferred	-53	-6	-75
State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Current	35	50	-12
Deferred	-137	-34	88
State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Current	7	50	6
Deferred	39	-29	38
State and Local Jurisdiction [Member] | PECO Energy Co [Member]
Income Taxes [Line Items]
Current	-2	16	4
Deferred	1	-2	12
State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Deferred	$27	$26	$4

Income_Taxes_Reconciliation_to

Income Taxes - Reconciliation to Effective Tax Rate (Details)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
U.S. Federal statutory rate	35.00%	35.00%	35.00%	[1]
State income taxes, net of Federal income tax benefit	1.30%	4.80%	-3.50%	[1]
Qualified nuclear decommissioning trust fund income	-2.40%	-3.70%	-5.40%	[1]
Tax exempt income	0.20%	0.20%	0.20%	[1]
Domestic production activities deduction	2.00%	0.00%	0.00%	[1]
Health care reform legislation	-0.10%	-0.10%	-0.10%	[1]
Amortization of investment tax credit, net deferred taxes	1.10%	1.90%	1.10%	[1]
Plant basis differences	-1.90%	-1.60%	-2.20%	[1]
Merger expenses			2.60%	[1],[2]
Merger expenses (c)			2.40%	[1]
Statute of limitations expiration	-2.60%	-0.10%	-0.10%	[1]
Production tax credits and other credits	-2.40%	-2.10%	-2.40%	[1]
Non-controlling interest	-1.80%
Other	0.00%	0.10%	1.10%	[1]
Effective income tax rate	26.80%	37.60%	34.90%	[1]
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
U.S. Federal statutory rate	35.00%	35.00%	35.00%	[1]
State income taxes, net of Federal income tax benefit	-1.90%	1.80%	4.90%	[1]
Qualified nuclear decommissioning trust fund income	-4.80%	-6.10%	-9.10%	[1]
Tax exempt income	0.50%	0.30%	0.40%	[1]
Domestic production activities deduction	4.10%	0.00%	0.00%	[1]
Health care reform legislation	0.00%	0.00%	0.00%	[1]
Amortization of investment tax credit, net deferred taxes	2.00%	3.00%	1.30%	[1]
Plant basis differences	0.00%	0.00%	-3.70%	[1]
Merger expenses			4.40%	[1],[2]
Merger expenses (c)			0.00%	[1]
Statute of limitations expiration	-5.30%	-0.20%	-0.30%	[1]
Production tax credits and other credits	-4.80%	-3.40%	0.00%	[1]
Non-controlling interest	-3.70%
Other	0.60%	-0.70%	0.40%	[1]
Effective income tax rate	16.90%	36.70%	47.30%	[1]
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
U.S. Federal statutory rate	35.00%	35.00%	35.00%
State income taxes, net of Federal income tax benefit	4.50%	3.40%	4.60%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Tax exempt income	0.00%	0.00%	0.00%
Domestic production activities deduction	0.00%	0.00%	0.00%
Health care reform legislation	-0.20%	-0.70%	-0.40%
Amortization of investment tax credit, net deferred taxes	0.30%	0.60%	0.40%
Plant basis differences	-0.10%	-0.80%	0.00%
Merger expenses			0.00%	[2]
Merger expenses (c)			0.00%
Statute of limitations expiration	0.00%	0.00%	0.00%
Production tax credits and other credits	0.00%	-0.10%	-0.30%
Non-controlling interest	0.00%
Other	-0.30%	-0.30%	0.60%
Effective income tax rate	39.60%	37.90%	38.70%
PECO Energy Co [Member]
Income Taxes [Line Items]
U.S. Federal statutory rate	35.00%	35.00%	35.00%
State income taxes, net of Federal income tax benefit	-0.10%	1.60%	2.00%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%
Tax exempt income	0.00%	0.00%	0.00%
Domestic production activities deduction	0.00%	0.00%	0.00%
Health care reform legislation	0.00%	0.00%	0.00%
Amortization of investment tax credit, net deferred taxes	0.10%	0.10%	0.30%
Plant basis differences	-10.40%	-7.10%	0.00%
Merger expenses			0.00%	[2]
Merger expenses (c)			0.00%
Statute of limitations expiration		0.00%	0.00%
Production tax credits and other credits	0.00%	0.00%	-11.50%
Non-controlling interest	0.00%
Other	-0.10%	0.30%	0.20%
Effective income tax rate	24.50%	29.10%	25.00%
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
U.S. Federal statutory rate	35.00%	35.00%	35.00%	[3]
State income taxes, net of Federal income tax benefit	5.00%	4.90%	24.30%	[3]
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	[3]
Tax exempt income	0.00%	0.00%	0.00%	[3]
Domestic production activities deduction	0.00%	0.00%	0.00%	[3]
Health care reform legislation	-0.20%	-0.20%	-11.60%	[3]
Amortization of investment tax credit, net deferred taxes	0.30%	0.00%	8.60%	[3]
Plant basis differences	0.20%	-0.20%	0.00%	[3]
Merger expenses			0.00%	[2],[3]
Merger expenses (c)			24.20%	[3]
Statute of limitations expiration	0.00%	0.00%	0.00%	[3]
Production tax credits and other credits	0.00%	0.00%	-9.00%	[3]
Non-controlling interest	0.00%
Other	0.20%	0.90%	13.90%	[3]
Effective income tax rate	39.90%	39.00%	63.60%	[3]
[1]	Exelon activity for the twelve months ended December 31, 2012 includes the results of Constellation and BGE for March 12, 2012—December 31, 2012. Generation activity for the twelve months ended December 31, 2012 includes the results of Constellation for March 12, 2012—December 31, 2012.
[2]	Prior to the close of the merger, the Registrants recorded the applicable taxes on merger transaction costs assuming the merger would not be completed. Upon closing of the merger, the Registrants reversed such taxes for those merger transaction costs that were determined to be non tax-deductible upon successful completion of a merger.
[3]	BGE activity represents the activity for the twelve months ended December 31, 2012.

Income_Taxes_Tax_Effects_of_Te

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Operating Loss Carryforwards [Line Items]
Plant basis differences	($12,143)	($11,612)
Accrual based contracts	-178	-214
Derivatives and other financial instruments	-46	-509
Deferred pension and postretirement obligation	1,914	1,489
Nuclear decommissioning activities	-726	-647
Deferred debt refinancing costs	112	173
Regulatory assets and liabilities	-1,824	-1,611
Tax loss carryforward	111	252
Tax credit carryforward	97	534
Investment in CENG	-563	-541
Other, net	1,029	804
Deferred income tax liabilities (net)	12,217	11,882
Unamortized investment tax credits	-555	-490
Total deferred income tax liabilities (net) and unamortized investment tax credits	-12,772	-12,372
Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	-3,834	-3,879
Accrual based contracts	-178	-214
Derivatives and other financial instruments	-79	-505
Deferred pension and postretirement obligation	-390	-362
Nuclear decommissioning activities	-726	-646
Deferred debt refinancing costs	57	79
Regulatory assets and liabilities	0	0
Tax loss carryforward	48	76
Tax credit carryforward	143	534
Investment in CENG	-563	-541
Other, net	346	67
Deferred income tax liabilities (net)	5,176	5,391
Unamortized investment tax credits	-528	-454
Total deferred income tax liabilities (net) and unamortized investment tax credits	-5,704	-5,845
Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	-3,945	-3,523
Accrual based contracts	0	0
Derivatives and other financial instruments	-4	-4
Deferred pension and postretirement obligation	-543	-522
Nuclear decommissioning activities	0	0
Deferred debt refinancing costs	-18	-21
Regulatory assets and liabilities	-286	-241
Tax loss carryforward	0	47
Tax credit carryforward	0	0
Investment in CENG	0	0
Other, net	255	154
Deferred income tax liabilities (net)	4,541	4,110
Unamortized investment tax credits	-20	-22
Total deferred income tax liabilities (net) and unamortized investment tax credits	-4,561	-4,132
PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	-2,749	-2,573
Accrual based contracts	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	2	0
Nuclear decommissioning activities	0	0
Deferred debt refinancing costs	-2	-3
Regulatory assets and liabilities	27	42
Tax loss carryforward	11	11
Tax credit carryforward	0	0
Investment in CENG	0	0
Other, net	111	122
Deferred income tax liabilities (net)	2,600	2,401
Unamortized investment tax credits	-2	-3
Total deferred income tax liabilities (net) and unamortized investment tax credits	-2,602	-2,404
Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Plant basis differences	-1,661	-1,538
Accrual based contracts	0	0
Derivatives and other financial instruments	0	0
Deferred pension and postretirement obligation	-53	-74
Nuclear decommissioning activities	0	0
Deferred debt refinancing costs	-4	-5
Regulatory assets and liabilities	-258	-253
Tax loss carryforward	39	52
Tax credit carryforward	0	0
Investment in CENG	0	0
Other, net	30	26
Deferred income tax liabilities (net)	1,907	1,792
Unamortized investment tax credits	-5	-6
Total deferred income tax liabilities (net) and unamortized investment tax credits	($1,912)	($1,798)

Income_Taxes_Schedule_of_Carry

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	$184	[1]
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	184	[1]
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	0	[1]
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	0	[1]
Internal Revenue Service (IRS) [Member] | General Business Tax Credit Carryforward [Member] | Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Tax Credit Carryforward, Amount	0	[1]
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforward	3,141	[2]
State net operating losses and other credit carryforwards	169
Valuation allowance on state tax attributes	50
State and Local Jurisdiction [Member] | Exelon Generation Co L L C [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforward	1,693	[3]
State net operating losses and other credit carryforwards	96
Valuation allowance on state tax attributes	48
State and Local Jurisdiction [Member] | Commonwealth Edison Co [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforward	0
State net operating losses and other credit carryforwards	0
Valuation allowance on state tax attributes	0
State and Local Jurisdiction [Member] | PECO Energy Co [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforward	170
State net operating losses and other credit carryforwards	11
Valuation allowance on state tax attributes	0
State and Local Jurisdiction [Member] | Baltimore Gas and Electric Company [Member]
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforward	730
State net operating losses and other credit carryforwards	39
Valuation allowance on state tax attributes	$1
[1]	Exelon’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015
[2]	Generation’s state net operating losses and other carryforwards, which are presented on a post-apportioned basis, will expire beginning in 2015.
[3]	PECO’s state net operating losses will expire beginning in 2031.

Income_Taxes_Reconciliation_of

Income Taxes - Reconciliation of Unrecognized Tax Benefits (Details) (USD $)	3 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance		$2,175	$1,024	$807
Merger balance transfer				195
Increases based on tax positions related to current year		15	19	34
Changes to tax positions that only affect timing		-255	649	-88
Increases based on tax positions prior to current year		18	493	91
Decreases based on tax positions prior to current year		-1	-6	-6
Decrease from settlements with taxing authorities		-35		-2
Decreases from expiration of statute of limitations		-88	-4	-7
Unrecognized tax benefits - ending balance	1,829	1,829	2,175	1,024
Exelon Generation Co L L C [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance		1,415	876	683
Merger balance transfer				183
Increases based on tax positions related to current year		15	19	3
Changes to tax positions that only affect timing		33	36	-69
Increases based on tax positions prior to current year		18	493	91
Decreases based on tax positions prior to current year	-661	-2	-5	-6
Decrease from settlements with taxing authorities		-34		-2
Decreases from expiration of statute of limitations		-88	-4	-7
Unrecognized tax benefits - ending balance	1,357	1,357	1,415	876
Commonwealth Edison Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance		324	67	70
Merger balance transfer				0
Increases based on tax positions related to current year		0	0	0
Changes to tax positions that only affect timing		-175	257	-3
Increases based on tax positions prior to current year		0	0	0
Decreases based on tax positions prior to current year		0	0	0
Decrease from settlements with taxing authorities		0		0
Decreases from expiration of statute of limitations		0	0	0
Unrecognized tax benefits - ending balance	149	149	324	67
PECO Energy Co [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance		44	44	48
Merger balance transfer				0
Increases based on tax positions related to current year		0	0	0
Changes to tax positions that only affect timing		0	0	-4
Increases based on tax positions prior to current year		0	0	0
Decreases based on tax positions prior to current year		0	0	0
Decrease from settlements with taxing authorities		0		0
Decreases from expiration of statute of limitations		0	0	0
Unrecognized tax benefits - ending balance	44	44	44	44
Baltimore Gas and Electric Company [Member]
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Unrecognized tax benefits - beginning balance		0	0	11
Merger balance transfer				0
Increases based on tax positions related to current year		0	0	0
Changes to tax positions that only affect timing		0	0	-11
Increases based on tax positions prior to current year		0	0	0
Decreases based on tax positions prior to current year		0	0	0
Decrease from settlements with taxing authorities		0		0
Decreases from expiration of statute of limitations		0	0	0
Unrecognized tax benefits - ending balance	$0	$0	$0	$0

Income_Taxes_Narrative_Details

Income Taxes - Narrative (Details) (USD $)	1 Months Ended	3 Months Ended			12 Months Ended				3 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2012	Dec. 31, 2014	Mar. 31, 2014	Mar. 31, 2012	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Mar. 31, 2013	Dec. 31, 1999
Income Taxes [Line Items]
Tax positions for which there is uncertainty about the timing of tax benefits		$1,129			$1,129	$1,387
Unrecognized tax benefits that if recognized would affect the effective tax rate		701			701	788
Unrecognized Tax Benefits					1	6	6
Increase in unrecognized tax benefits resulting from settlements with taxing authorities					188
Deferred gain on sale of property										1,200
IRS asserted penalties for understatement of tax					90
Expected non-cash charge to earnings									265
Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position		810			810
Potential interest expense from a successful IRS challenge of the like-kind exchange position		310			310
Proceeds from long-term capital lease obligations			335
Taxes accrued		305	285		305	315
Cash tax benefit (detriment) as a result of repair costs deduction								300
Effective Income Tax Rate Reconciliation, Deduction, Other, Amount								35
Gas Distribution Repair Tax Benefit Expense	26
Deferred State Tax Asset From State Tax Apportionment				72
Income tax benefit recorded as a result of re-apportionment of state income taxes		3		116
Deferred state tax liability resulting from purchase accounting				44
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Unrecognized tax benefits that if recognized would affect the effective tax rate		672			672	768
Unrecognized Tax Benefits		661			2	5	6
Taxes accrued		248			248	212
Cash tax benefit (detriment) as a result of repair costs deduction								28
Income tax benefit recorded as a result of re-apportionment of state income taxes		7		14
Deferred state tax liability resulting from purchase accounting				14
Allocation of federal tax benefit under tax sharing agreement			77			26
Allocation of tax benefit from parent							48
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits					0	0	0
Taxes accrued		42			42	16
Cash tax benefit (detriment) as a result of repair costs deduction							27
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits					0	0	0
Deferred gain on sale of property			155
Expected non-cash charge to earnings									170
Noncash contributions from parent									172
Taxes accrued		59			59	62
Cash tax benefit (detriment) as a result of repair costs deduction								250
Intercompany Non Cash Allocation Of Tax Benefit					273	0	11
PECO Energy Co [Member]
Income Taxes [Line Items]
Unrecognized Tax Benefits					0	0	0
Taxes accrued		3			3	24
Cash tax benefit (detriment) as a result of repair costs deduction								95
Gas Distribution Repair Tax Benefit Expense	29
Allocation of federal tax benefit under tax sharing agreement						27
Allocation of tax benefit from parent						27	9
Maximum [Member]
Income Taxes [Line Items]
Cash tax benefit (detriment) as a result of repair costs deduction					$120

Income_Taxes_Summary_of_Intere

Income Taxes - Summary of Interest Receivable (Payable) (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	($310)	($349)
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	40	-37
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	-203	-174
PECO Energy Co [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	3	3
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net interest receivable (payable) recognized related to uncertain tax positions	($1)	$0

Income_Taxes_Summary_of_Intere1

Income Taxes - Summary of Interest Expense (Income) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	($36)	$391	($1)
Exelon Generation Co L L C [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	-50	17	11
Commonwealth Edison Co [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	6	281	-20
PECO Energy Co [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	0	-1	-1
Baltimore Gas and Electric Company [Member]
Income Taxes [Line Items]
Net interest (income) expense recognized related to uncertain tax positions	$1	$0	$9

Asset_Retirement_Obligations_N

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) (Exelon Generation Co L L C [Member], USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Current	$1		$0
Nuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	4,855	[1]	4,741
Accretion expense	334		259
Net increase (decrease) resulting from updates to estimated future cash flows	19		-140
Costs incurred to decommission retired plants	-7		-5
ARO ending balance	6,961	[1]	4,855	[1]
Asset Retirement Obligation, Current	8		9
CENG [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Consolidation of CENG	$1,760	[2]
[1]	Includes $8 million and $9 million as the current portion of the ARO at December 31, 2014 and 2013, respectively, which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.
[2]	Represents the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

Asset_Retirement_Obligations_N1

Asset Retirement Obligations - Narrative (Details) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Oct. 02, 2013	Dec. 31, 2012
			reactor
Asset Retirement Obligations [Line Items]
Nuclear decommissioning annual recovery current	$24,000,000
Percent of additional decommissioning shortfall with recourse	50.00%
Nuclear decommissioning trust funds	10,537,000,000	8,071,000,000
Minimum [Member]
Asset Retirement Obligations [Line Items]
Years after cessation of plant operations	20 years
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Increase (decrease) in asset retirement obligation	2,100,000,000	114,000,000
Shortfall of decommissioning funds with recourse	50,000,000
Percent of additional decommissioning shortfall with recourse	5.00%
Nuclear decommissioning trust funds	10,537,000,000	8,071,000,000
Percent of NDT funds invested in equity	52.00%	48.00%
Percent of NDT funds invested in fixed income securities	48.00%	52.00%
Zion Station spent nuclear fuel obligation	86,000,000
ZionSolutions rent payable	1
EnergySolutions letter of credit	200,000,000
Assumed annual after-tax return on NDT funds	2.00%
Assumed annual after-tax return on NDT funds for former PECO units	3.00%
Annual average accretion of the ARO	5.00%
Number of years used in present value measurement	30 years
Estimated annual after tax return on nuclear decommissioning funds lower bound	6.00%
Estimated annual after tax return on nuclear decommissioning funds upper bound	6.30%
Historical five-year annual average after-tax return on NDT funds	9.00%
NRC funding assurance parent guarantees				115,000,000
Number of operating reactors			104
Exelon Generation Co L L C [Member] | Minimum [Member]
Asset Retirement Obligations [Line Items]
Years after cessation of plant operations	10 years
Exelon Generation Co L L C [Member] | Maximum [Member]
Asset Retirement Obligations [Line Items]
Years after cessation of plant operations	70 years
Nuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Net increase (decrease) resulting from updates to estimated future cash flows	19,000,000	-140,000,000
Property, Plant and Equipment [Member] | Nuclear Decommissioning Asset Retirement Obligation [Member] | Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Net increase (decrease) resulting from updates to estimated future cash flows	$16,000,000

Asset_Retirement_Obligations_U

Asset Retirement Obligations - Unrealized Gain on NDT Funds (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligations [Line Items]
Net unrealized gains (losses) on decommissioning trust funds - Regulatory Agreement Units	$180	[1]	$406	[1]	$386	[1]
Net unrealized gains (losses) on decommissioning trust funds - Non-Regulatory Agreement Units	134	[2],[3]	146	[2],[3]	105	[2],[3]
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Unrealized Gain Loss Investment Income Pledged Assets	$29		$7		$73
[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 $29 million, $7 million and $73 million of net unrealized gains related to the Zion Station pledged assets in 2014, 2013 and 2012, respectively. Net unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.
[3]	Net unrealized gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

Asset_Retirement_Obligations_P

Asset Retirement Obligations - Pledged Assets and Payables to ZionSolutions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Asset Retirement Obligations [Line Items]
Carrying value of Zion Station pledged assets	$319		$458
Exelon Generation Co L L C [Member]
Asset Retirement Obligations [Line Items]
Carrying value of Zion Station pledged assets	319		458
Payable to Zion Solutions	292	[1]	414	[1]
Current portion of payable to Zion Solutions	137	[2]	109	[2]
Withdrawals by Zion Solutions to pay decommissioning costs	$666		$498
[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.

Asset_Retirement_Obligations_N2

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	$351	[1]	$343
Net increase (decrease) resulting from updates to estimated future cash flows	-1	[2]	1	[2]
Development projects	11	[3]	2	[3]
Accretion expense	15	[4]	18	[4]
Payments	-6		-13
Reclassified to liabilities held for sale	-4	[5]
Asset Divestitures	-20	[6]
ARO ending balance	346	[1]	351	[1]
Exelon Generation Co L L C [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Reduction to operating and maintenance expense due to updates to estimated future cash flows	-2		13
Asset Retirement Obligation, Current	1		0
Exelon Generation Co L L C [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	201	[1]	207
Net increase (decrease) resulting from updates to estimated future cash flows	-2	[2]	-11	[2]
Development projects	11	[3]	2	[3]
Accretion expense	11	[4]	13	[4]
Payments	-3		-10
Reclassified to liabilities held for sale	-4	[5]
Asset Divestitures	-20	[6]
ARO ending balance	194	[1]	201	[1]
Commonwealth Edison Co [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Reduction to operating and maintenance expense due to updates to estimated future cash flows	1
Asset Retirement Obligation, Current	1		2
Commonwealth Edison Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	101	[1]	99
Net increase (decrease) resulting from updates to estimated future cash flows	2	[2]	0	[2]
Development projects	0	[3]	0	[3]
Accretion expense	3	[4]	4	[4]
Payments	-2		-2
Reclassified to liabilities held for sale	0	[5]
Asset Divestitures	0	[6]
ARO ending balance	104	[1]	101	[1]
PECO Energy Co [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Current	1		1
PECO Energy Co [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	30	[1]	29
Net increase (decrease) resulting from updates to estimated future cash flows	0	[2]	0	[2]
Development projects	0	[3]	0	[3]
Accretion expense	1	[4]	1	[4]
Payments	-1		0
Reclassified to liabilities held for sale	0	[5]
Asset Divestitures	0	[6]
ARO ending balance	30	[1]	30	[1]
Baltimore Gas and Electric Company [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation, Current	1		0
Baltimore Gas and Electric Company [Member] | Nonnuclear Decommissioning Asset Retirement Obligation [Member]
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
ARO beginning balance	19	[1]	8
Net increase (decrease) resulting from updates to estimated future cash flows	-1	[2]	12	[2]
Development projects	0	[3]	0	[3]
Accretion expense	0	[4]	0	[4]
Payments	0		-1
Reclassified to liabilities held for sale	0	[5]
Asset Divestitures	0	[6]
ARO ending balance	$18	[1]	$19	[1]
[1]	During the year ended December 31, 2014, Generation, ComEd, PECO and BGE recorded $1 million, $1 million, $1 million, and $1 million, respectively, as the current portion of the ARO. During December 31, 2013 Generation, ComEd, PECO and BGE recorded $0 million, $2 million, $1 million, and $0 million, respectively, as the current portion of the ARO. This is included in Other current liabilities on the Registrants' respective Consolidated Balance Sheets.
[2]	During the year ended December 31, 2014, Generation recorded a decrease of $(2) million and ComEd recorded an increase of $1 million in Operating and maintenance expense. PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2014. During the year ended December 31, 2013, Generation recorded an increase in Operating and maintenance expense of $13 million. ComEd, PECO, and BGE did not record any adjustments in Operating and maintenance expense for the year ended December 31, 2013.
[3]	Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.
[4]	For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
[5]	Represents AROs related to generating stations classified as held for sale as of December 31, 2014. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.
[6]	Reflects a reduction to the ARO resulting primarily from the sales of the Keystone and Conemaugh generating stations. See Note 4 — Mergers, Acquisitions, and Dispositions for further information.

Retirement_Benefits_Narrative_

Retirement Benefits - Narrative (Details) (USD $)

3 Months Ended

12 Months Ended

1 Months Ended

3 Months Ended

0 Months Ended

Mar. 31, 2014

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Apr. 30, 2014

Jun. 30, 2014

Dec. 31, 2014

Oct. 31, 2014

Apr. 30, 2014

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined benefit plan, amounts recognized In regulatory liabilities, before tax

$5,000,000

Effect of federal subsidy on net periodic postretirement benefit costs under the Prescription Drug Act

0

0

17,000,000

Expected qualified pension plan contributions

447,000,000

447,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

37,000,000

37,000,000

Projected Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Funded status of the pension and other postretirement benefit obligations

81.00%

88.00%

Accumulated Benefit Obligation In Excess Of Plan Assets [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Funded status of the pension and other postretirement benefit obligations

87.00%

93.00%

Exelon Generation Co L L C [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected qualified pension plan contributions

230,000,000

230,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

17,000,000

17,000,000

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

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected non-qualified pension plan contributions

4,000,000

4,000,000

Business Services Company [Member] | Remeasurement [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Regulatory asset increase (decrease) due to updated valuation adjustment

125,000,000

Commonwealth Edison Co [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected qualified pension plan contributions

138,000,000

138,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

1,000,000

1,000,000

Expected other postretirement benefit plan contributions

2,000,000

2,000,000

PECO Energy Co [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected qualified pension plan contributions

40,000,000

40,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

1,000,000

1,000,000

Expected other postretirement benefit plan contributions

0

0

Baltimore Gas and Electric Company [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected qualified pension plan contributions

1,000,000

1,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

1,000,000

1,000,000

Expected other postretirement benefit plan contributions

17,000,000

17,000,000

Exelon Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Regulatory asset increase (decrease) due to updated valuation adjustment

34,000,000

Constellation Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

AOCI valuation adjustment

12,000,000

1,000,000

Regulatory asset increase (decrease) due to updated valuation adjustment

15,000,000

Pension Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected return on plan assets

7.00%

[1]

7.50%

[1]

7.50%

[1]

7.00%

Discount rate

4.80%

[2]

3.92%

[3]

4.74%

[4]

3.95%

Increase (decrease) in pension obligation

361,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

1,064,000,000

1,064,000,000

Healthcare cost trend on covered charges

7.00%

Pension Plan, Defined Benefit [Member] | Remeasurement [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected return on plan assets

6.59%

Pension Plan, Defined Benefit [Member] | Exelon Generation Co L L C [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

6,000,000

6,000,000

Pension Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Benefit obligation increase (decrease) reflecting actual census data

35,000,000

13,000,000

Pension Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected return on plan assets

7.75%

Pension Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | Minimum [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Discount rate

3.60%

Pension Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member] | Maximum [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Discount rate

4.30%

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Benefit obligation increase (decrease) due to design changes

790,000,000

Regulatory asset increase (decrease) due to design changes

240,000,000

Other comprehensive income (loss) due to design changes

259,000,000

Expected return on plan assets

6.59%

[1]

6.45%

[1]

6.68%

[1]

6.59%

Discount rate

4.90%

[2]

4.00%

[3]

4.80%

[4]

4.30%

Increase (decrease) in pension obligation

117,000,000

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

217,000,000

217,000,000

Healthcare cost trend on covered charges

6.46%

Other Postretirement Benefit Plan, Defined Benefit [Member] | Exelon Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Benefit obligation increase (decrease) reflecting actual census data

12,000,000

3,000,000

Other Postretirement Benefit Plan, Defined Benefit [Member] | Constellation Legacy Benefit Plans [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected return on plan assets

4.55%

Exelon Sponsored Benefit Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Expected qualified pension plan contributions

36,000,000

36,000,000

Non-Qualified Pension Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]

Defined Benefit Plan, Expected Future Benefit Payments, Next Twelve Months

$15,000,000

$15,000,000

[1]

Not applicable to pension and other postretirement benefit plans that do not have plan asset

[2]

)The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectivel

[3]

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

[4]

The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurement

Retirement_Benefits_Summary_of

Retirement Benefits - Summary of Changes in Benefit Obligations (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Net benefit obligation at beginning of year	$15,459		$16,800
Service cost	293		317		280
Interest cost	749		650		698
Plan participants’ contributions	0		0
Actuarial loss (gain)	2,095		-1,363
Plan amendments	0		1
Acquisitions/divestitures(a)	594		0
Curtailments	-8		0
Settlements	-30	[1]	-69	[1]
Gross benefits paid	-896		-877
Net benefit obligation at end of year	18,256		15,459		16,800
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Benefit Obligation [Roll Forward]
Net benefit obligation at beginning of year	4,451		4,820
Service cost	117		162		156
Interest cost	186		194		205
Plan participants’ contributions	42		34
Actuarial loss (gain)	502		-551
Plan amendments	-1,012		15
Acquisitions/divestitures(a)	142		0
Curtailments	0		0
Settlements	0	[1]	0	[1]
Gross benefits paid	-231		-223
Net benefit obligation at end of year	$4,197		$4,451		$4,820
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmFiYTQ1MWI2ZGYzNjQ3OWM4OTUwZjNhNDE5MzEyMWVmfFRleHRTZWxlY3Rpb246N0NFMEI0QkQ2ODg4NDYzNDFGOTY4RTdCNDgxQjJFMTIM}

Retirement_Benefits_Summary_of1

Retirement Benefits - Summary of Changes in Plan Assets (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	$13,571		$13,357
Actual return on plan assets	1,443		821
Employer contributions	332		339
Plan participants’ contributions	0		0
Benefits paid	-896		-877
Acquisitions/divestitures(a)	454		0
Settlements	-30	[1]	-69	[1]
Fair value of net plan assets at end of year	14,874		13,571
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	2,238		2,135
Actual return on plan assets	90		209
Employer contributions	291		83
Plan participants’ contributions	42		34
Benefits paid	-231		-223
Acquisitions/divestitures(a)	0		0
Settlements	0	[1]	0	[1]
Fair value of net plan assets at end of year	$2,430		$2,238
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmFiYTQ1MWI2ZGYzNjQ3OWM4OTUwZjNhNDE5MzEyMWVmfFRleHRTZWxlY3Rpb246N0NFMEI0QkQ2ODg4NDYzNDFGOTY4RTdCNDgxQjJFMTIM}

Retirement_Benefits_Balance_Sh

Retirement Benefits - Balance Sheet locations of Benefit Obligations and Plan Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	$16	$12
Pension obligations	3,366	1,876
Non-pension postretirement benefit obligations	0	0
Unfunded status (net benefit obligation less net plan assets)	3,382	1,888
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current liabilities	25	23
Pension obligations	0	0
Non-pension postretirement benefit obligations	1,742	2,190
Unfunded status (net benefit obligation less net plan assets)	$1,767	$2,213

Retirement_Benefits_Projected_

Retirement Benefits - Projected Benefit Obligations and Accumulated Benefit Obligations in Excess of Plan Assets (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Projected Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	$18,256	$15,452
Fair value of net plan assets	14,874	13,564
Accumulated Benefit Obligation In Excess Of Plan Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected benefit obligation	18,256	15,452
Fair value of net plan assets	14,874	13,564
Accumulated benefit obligation	$17,191	$14,552

Retirement_Benefits_Components

Retirement Benefits - Components of Net Periodic Benefit Cost (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Contractual termination benefit cost					$1
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Contractual termination benefit cost					4
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	293		317		280
Interest cost	749		650		698
Expected return on assets	-994		-1,015		-988
Transition obligation	0		0		0
Prior service cost (credit)	14		14		15
Actuarial loss	420		562		450
Curtailment benefits	0		0		0
Settlement charges	2		9		31
Contractual termination benefit cost	0	[1]	0	[1]	14	[1]
Net periodic benefit cost	484		537		500
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	117		162		156
Interest cost	186		194		205
Expected return on assets	-154		-132		-115
Transition obligation	0		0		11
Prior service cost (credit)	-122		-19		-17
Actuarial loss	50		83		81
Curtailment benefits	0		0		-7
Settlement charges	0		0		0
Contractual termination benefit cost	0	[1]	0	[1]	6	[1]
Net periodic benefit cost	$77		$288		$320
[1]	)ComEd and BGE established regulatory assets of $1 million and $4 million, respectively, for their portion of the contractual termination benefit charge in

Retirement_Benefits_Components1

Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets (Liabilities) related to Retirement Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	$1,639		($1,169)		$1,693
Amortization of actuarial loss	-420		-562		-450
Current year prior service (credit) cost	0		0		1
Amortization of prior service (cost) credit	-14		-14		-15
Current year transition (asset) obligation	0		0		0
Amortization of transition asset (obligation)	0		0		0
Curtailments	0		0		-10
Settlements	-2		-8		-31
Total recognized in AOCI and regulatory assets (liabilities)	1,203	[1]	-1,753	[1]	1,188	[1]
Defined benefit plan, amounts recognized in OCI, before tax	788		1,071		283
Defined benefit plan, amounts recognized in regulatory assets, before tax	415		682		904
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	561		-628		304
Amortization of actuarial loss	-50		-83		-81
Current year prior service (credit) cost	-1,012		15		-109
Amortization of prior service (cost) credit	122		19		17
Current year transition (asset) obligation	0		0		1
Amortization of transition asset (obligation)	0		0		-11
Curtailments	0		0		-1
Settlements	0		0		0
Total recognized in AOCI and regulatory assets (liabilities)	-379	[1]	-677	[1]	120	[1]
Defined benefit plan, amounts recognized in OCI, before tax	162		352		39
Defined benefit plan, amounts recognized in regulatory assets, before tax	$217		$325		$81
[1]	)Of the $1,203 million loss related to pension benefits, $788 million and $415 million were recognized in AOCI and regulatory assets, respectively, during 2014. Of the $379 million gain related to other postretirement benefits, $162 million and $217 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2014. Of the $1,753 million gain related to pension benefits, $1,071 million and $682 million were recognized in AOCI and regulatory assets, respectively, during 2013. Of the $677 million gain related to other postretirement benefits, $352 million and $325 million were recognized in AOCI and regulatory assets (liabilities), respectively, during 2013. Of the $1,188 million loss related to pension benefits, $283 million and $904 million were recognized in AOCI and regulatory assets, respectively, during 2012. Of the $120 million loss related to other postretirement benefits, $39 million and $81 million were recognized in AOCI and regulatory assets, respectively, during 2012.

Retirement_Benefits_Gross_Accu

Retirement Benefits - Gross Accumulated Other Comprehensive Loss and Regulatory Assets (Liabilities) not Recognized as Components of Periodic Benefit Cost (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	$49		$62
Actuarial loss	7,407		6,192
Total	7,456	[1]	6,254	[1]
Benefits included in accumulated other comprehensive income	4,310		3,523
Benefits included in regulatory assets	3,146		2,731
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	-963		-73
Actuarial loss	985		474
Total	22	[1]	401	[1]
Benefits included in accumulated other comprehensive income			161
Benefits included in regulatory assets	$22		$240
[1]	)Of the $7,456 million related to pension benefits, $4,310 million and $3,146 million are included in AOCI and regulatory assets, respectively, at December 31, 2014. Of the $22 million related to other postretirement benefits, $22 million is included in regulatory assets (liabilities) at December 31, 2014. Of the $6,254 million related to pension benefits, $3,523 million and $2,731 million are included in AOCI and regulatory assets, respectively, at December 31, 2013. Of the $401 million related to other postretirement benefits, $161 million and $240 million are included in AOCI and regulatory assets (liabilities), respectively, at

Retirement_Benefits_Components2

Retirement Benefits - Components of Accumulated Other Comprehensive Income and Regulatory Assets expected to be Amortized as Components of Periodic Benefit Cost (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan Amounts That Will Be Amortized From Accumulated Other Comprehensive Income Loss And Regulatory Assets In Next Fiscal Year	($101)
Benefits included in accumulated other comprehensive income	-51
Benefits included in regulatory assets	-50
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)	13
Defined Benefit Plan, Future Amortization of Gain (Loss)	562
Benefits included in accumulated other comprehensive income	575	[1]
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax	329
Pension Plan, Defined Benefit [Member] | Regulatory Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, Net of Tax	246
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received			10
Defined Benefit Plan, Future Amortization of Prior Service Cost (Credit)	-175
Defined Benefit Plan, Future Amortization of Gain (Loss)	74
Benefits included in accumulated other comprehensive income	($101)	[1]
[1]	)Of the $575 million related to pension benefits at December 31, 2014, $329 million and $246 million are expected to be amortized from AOCI and regulatory assets in 2015, respectively. Of the $101 million related to other postretirement benefits at December 31, 2014, $(51) million and $(50) million are expected to be amortized from AOCI and regulatory assets (liabilities) in 2015, respectivel

Retirement_Benefits_Assumption

Retirement Benefits - Assumptions Used in Calculations (Details)	0 Months Ended	12 Months Ended						1 Months Ended	0 Months Ended
	Oct. 31, 2014	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Apr. 30, 2014	Apr. 30, 2014
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate		3.94%		4.80%		3.92%
Discount rate	3.95%	4.80%	[1]	3.92%	[2]	4.74%	[3]
Expected return on plan assets	7.00%	7.00%	[4]	7.50%	[4]	7.50%	[4]
Rate of compensation increase						3.75%
Pension Plan, Defined Benefit [Member] | Remeasurement [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Expected return on plan assets								6.59%
Discount rate used for remeasurement due to design changes				4.21%		3.71%
Pension Plan, Defined Benefit [Member] | First Five Years [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Rate of compensation increase		3.25%				3.25%
Rate of compensation increase		3.25%		3.25%
Pension Plan, Defined Benefit [Member] | Thereafter [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Rate of compensation increase		3.75%				3.75%
Rate of compensation increase		3.75%		3.75%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate		3.92%		4.90%		4.00%
Discount rate		4.90%	[1]	4.00%	[2]	4.80%	[3]		4.30%
Expected return on plan assets		6.59%	[4]	6.45%	[4]	6.68%	[4]		6.59%
Rate of compensation increase						3.75%
Health care cost trend rate		6.00%		6.50%		6.50%
Ultimate health care cost trend rate		5.00%		5.00%		5.00%
Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate used for remeasurement due to design changes				4.66%		3.72%
Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Minimum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate used for remeasurement due to design changes		4.09%
Other Postretirement Benefit Plan, Defined Benefit [Member] | Remeasurement [Member] | Maximum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate used for remeasurement due to design changes		4.55%
CENG Legacy Benefit Plans [Member] | Remeasurement [Member] | Minimum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate used for remeasurement due to design changes		3.60%
CENG Legacy Benefit Plans [Member] | Remeasurement [Member] | Maximum [Member]
Defined Benefit Plan Assumptions Used In Calculations [Line Items]
Discount rate used for remeasurement due to design changes		4.30%
[1]	)The discount rates above represent the initial discount rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of 6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectivel
[2]	The discount rates above represent the initial discount rates used to establish Exelon's pension and other postretirement benefits costs for the year ended December 31, 2013. Certain of the benefit plans were remeasured during the year using discount rates of 4.21% and 4.66% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2013 reflect the impact of these measurements
[3]	The discount rates above represent the initial discounts rates used to establish Exelon’s pension and other postretirement benefits costs for the year ended December 31, 2012. Certain of the benefit plans were remeasured during the year due to the Constellation merger, plan settlement and curtailment events, and plan changes using discount rates of 3.71% and 3.72% for pension and other postretirement benefits, respectively. Costs for the year ended December 31, 2012 reflect the impact of these remeasurement
[4]	Not applicable to pension and other postretirement benefit plans that do not have plan asset

Retirement_Benefits_Effects_of

Retirement Benefits - Effects of One Percentage Point Change in Assumed Health Care Cost Trend Rates (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Compensation and Retirement Disclosure [Abstract]
Effect of a one percentage point increase in assumed healthcare cost trend on 2010 total service and interest cost components	$35
Effect of a one percentage point increase in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010	162
Effect of a one percentage point decrease in assumed healthcare cost trend on 2010 total service and interest cost components	-24
Effect of a one percentage point decrease in assumed healthcare cost trend on postretirement benefit obligation at December 31, 2010	($113)

Retirement_Benefits_Contributi

Retirement Benefits - Contributions made to Pension and Other Postretirement Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	$617		$422		$462
Expected qualified pension plan contributions	447
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	332	[1]	339		149
Service cost	293		317		280
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received					10
Pension and non-pension postretirement benefit contributions	291		83	[2]	323	[2]
Service cost	117		162		156
Defined Contribution Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	250
Exelon Generation Co L L C [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	297		149		178
Expected qualified pension plan contributions	230
Exelon Generation Co L L C [Member] | CENG [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected non-qualified pension plan contributions	4
Exelon Generation Co L L C [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	173	[1]	119		48
Exelon Generation Co L L C [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received					5
Pension and non-pension postretirement benefit contributions	124		30	[2]	135	[2]
Exelon Corporate [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	9	[1]	72		13
Commonwealth Edison Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	248		122		138
Expected qualified pension plan contributions	138
Commonwealth Edison Co [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	122	[1]	118		25
Commonwealth Edison Co [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received					4
Pension and non-pension postretirement benefit contributions	125		4	[2]	119	[2]
PECO Energy Co [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	16		31		45
Expected qualified pension plan contributions	40
PECO Energy Co [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	11	[1]	11		13
PECO Energy Co [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received					1
Pension and non-pension postretirement benefit contributions	5		20	[2]	33	[2]
Baltimore Gas and Electric Company [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	16		24		16
Expected qualified pension plan contributions	1
Baltimore Gas and Electric Company [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	0	[1],[3]	0	[3]	0	[3]
Baltimore Gas and Electric Company [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Gross Prescription Drug Subsidy Receipts Received					2
Pension and non-pension postretirement benefit contributions	17	[3]	24	[2],[3]	12	[2],[3]
Business Services Company [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	26	[1]	91		63
Business Services Company [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	20		5	[2]	24	[2]
Constellation Legacy Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and non-pension postretirement benefit contributions	$43	[1]
[1]	)Exelon's and Generation's pension contributions include $43 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters Agreement (EMA) between Exelon and CEN
[2]	)The Registrants present the cash contributions above net of Federal subsidy payments received on each of their respective Consolidated Statements of Cash Flows. Exelon, Generation, ComEd, PECO, and BGE received Federal subsidy payments of $10 million, $5 million, $4 million, $1 million and $2 million, respectively, in 2012. Effective January 1, 2013, Exelon is no longer receiving this subsid
[3]	)BGE’s other postretirement benefit payments for 2012 exclude $4 million, of other postretirement benefit payments made by BGE prior to the closing of the Constellation merger on March 12, 2012. These pre-Constellation merger contributions are not included in Exelon’s financial statements but are reflected in BGE’s financial statement

Retirement_Benefits_Estimated_

Retirement Benefits - Estimated Future Benefit Payments (Details) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	$37
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	1,064
2016	962
2017	979
2018	1,004
2019	1,032
2020 through 2024	5,825
Total estimated future benefit payments through 2024	10,866
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
2015	217
2016	223
2017	230
2018	236
2019	247
2020 through 2024	1,373
Total estimated future benefit payments through 2024	$2,526

Retirement_Benefits_Allocated_

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense	$561		$825		$820
Exelon Generation Co L L C [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense	250		347		341
Commonwealth Edison Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense	162		309		282
PECO Energy Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense	36		43		50
Business Services Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense	46	[1]	71	[1]	99	[1]
Baltimore Gas and Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense	67	[2],[3]	55	[2],[3]	60	[2],[3]
Constellation Legacy Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense					12
Pension and Other Postretirement Benefits [Member] | Commonwealth Edison Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense					1
Pension and Other Postretirement Benefits [Member] | Baltimore Gas and Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Amount included in capital and operating & maintenance expense					$3	[2],[3]
[1]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above. As of December 31, 2012, ComEd and BGE each reported a regulatory asset of $1 million related to their BSC-billed portion of the second quarter 2012 contractual termination benefit charg
[2]	BGE’s pension and other postretirement benefit costs for the year ended December 31, 2012 include a $3 million contractual termination benefit charge, which was recorded as a regulatory asset as of December 31, 2012.
[3]	The amounts included in capital and Operating and maintenance expense for the years ended December 31, 2012 include $12 million in costs incurred prior to the closing of the Constellation merger on March 12, 2012. These amounts are not included in Exelon’s capital expenditures and Operating and maintenance expense for the year ended December 31, 201

Retirement_Benefits_Pension_an

Retirement Benefits - Pension and Other Postretirement Benefit Plan Target Asset Allocations (Details)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Percentage of Plan Assets	100.00%		100.00%
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Percentage of Plan Assets	42.00%		45.00%
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Percentage of Plan Assets	33.00%		35.00%
Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	41.00%
Equity Securities [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	32.00%
Fixed Income Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	34.00%
Percentage of Plan Assets	34.00%		37.00%
Fixed Income Securities [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	37.00%
Percentage of Plan Assets	37.00%		37.00%
Alternative Investments [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	25.00%	[1]
Percentage of Plan Assets	24.00%	[1]	18.00%	[1]
Alternative Investments [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Target asset allocation percentage	31.00%	[1]
Percentage of Plan Assets	30.00%	[1]	28.00%	[1]
[1]	Alternative investments include private equity, hedge funds and real estate.

Retirement_Benefits_Fair_Value

Retirement Benefits - Fair Value Measurements of Pension and Postretirement Benefit Plan Assets (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Millions, unless otherwise specified
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Derivative, notional amount	$1,491		$2,651
Net assets pending transactions excluded	42		43
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,430		2,238		2,135
Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14,874		13,571		13,357
Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	226		115		108
Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,251		2,470		2,415
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0		0
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2		2		0
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		0		0
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	272		41		0
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0		2		1
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	904		806		754
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	110		4		12
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,329		1,039		1,235
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	116		109		95
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	744		582		426
Fair Value, Measurements, Recurring [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	17,261	[1],[2]	15,766	[1],[2]
Fair Value, Measurements, Recurring [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,427	[2]	2,233	[2]
Fair Value, Measurements, Recurring [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	14,834	[2]	13,533	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	5,323	[1],[2]	5,368	[1],[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	767	[2]	831	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,556	[2]	4,537	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	8,461	[1],[2]	7,813	[1],[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,434	[2]	1,287	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	7,027	[2]	6,526	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,477	[1],[2]	2,585	[1],[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	226	[2]	115	[2]
Fair Value, Measurements, Recurring [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,251	[2]	2,470	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	11	[2]	51	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	11	[2]	51	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	0	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	0	[2]
Fair Value, Measurements, Recurring [Member] | Cash and Cash Equivalents [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	674	[2]	641	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,691	[2]	2,454	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	296	[2]	296	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,556	[2]	1,587	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	378	[2]	345	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,133	[2]	865	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	0	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2	[2]	2	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	331	[2]	324	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2,021	[2]	2,075	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	184	[2]	154	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,705	[2]	1,773	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	147	[2]	170	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	316	[2]	302	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	0	[2]
Fair Value, Measurements, Recurring [Member] | Equity Security Commingled Fund [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	0	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,005	[2]	965	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	4,712	[2]	4,529	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	480	[2]	450	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	3,261	[2]	3,360	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	525	[2]	515	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,449	[2]	1,167	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	0	[2]
Fair Value, Measurements, Recurring [Member] | Equity Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	2	[2]	2	[2]
Fair Value, Measurements, Recurring [Member] | US Treasury and Government [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	74	[2]	63	[2]
Fair Value, Measurements, Recurring [Member] | US Treasury and Government [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,139	[2]	1,007	[2]
Fair Value, Measurements, Recurring [Member] | US Treasury and Government [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
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Defined Benefit Plan, Fair Value of Plan Assets	120	[2]	41	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	525	[2]	530	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	253	[2]	305	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	272	[2]	225	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	838	[2]	794	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	5,546	[2]	5,045	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	268	[2]	322	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	1,051	[2]	913	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	570	[2]	472	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	4,223	[2]	4,091	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	449	[2]	299	[2]
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Defined Benefit Plan, Fair Value of Plan Assets	2,684	[2]	2,305	[2]
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
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Defined Benefit Plan, Fair Value of Plan Assets	339	[2]	295	[2]
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,355	[2]	1,266	[2]
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
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Defined Benefit Plan, Fair Value of Plan Assets	110	[2]	4	[2]
Fair Value, Measurements, Recurring [Member] | Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	1,329	[2]	1,039	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	124	[2]	122	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	987	[2]	848	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
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Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 1 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	243	[2]	264	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	5	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 2 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	0	[2]	2	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	116	[2]	109	[2]
Fair Value, Measurements, Recurring [Member] | Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$744	[2]	$582	[2]
[1]	Excludes net assets of $42 million and $43 million at December 31, 2014 and 2013, respectively, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchases.
[2]	See Note 11—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
[3]	Derivative instruments have a total notional amount of $1,491 million and $2,651 million at December 31, 2014 and 2013, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

Retirement_Benefits_Reconcilia

Retirement Benefits - Reconciliation of Level 3 Assets and Liabilities measured at Fair Value for Pension and Other Postretirement Benefit Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	$13,571		$13,357
Purchases	454		0
Fair value of net plan assets at end of year	14,874		13,571
Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	2,238		2,135
Purchases	0		0
Fair value of net plan assets at end of year	2,430		2,238
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Transfers into (out of) Level 3	56
Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	2,470		2,415
Relating to assets still held at the reporting date	279		292
Relating to assets sold during the period	3		-1
Purchases	847		752
Sales	-60		-167
Settlements	-301	[1]	-198	[1]
Transfers into (out of) Level 3	13	[2],[3]	-623	[2]
Fair value of net plan assets at end of year	3,251		2,470
Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member] | Constellation Energy Group Acquisition [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Transfers into (out of) Level 3			825
Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	115		108
Relating to assets still held at the reporting date	14		12
Purchases	111		4
Sales	-13		-1
Settlements	-1	[1]	-4	[1]
Transfers into (out of) Level 3			-4	[2]
Fair value of net plan assets at end of year	226		115
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	1,039		1,235
Relating to assets still held at the reporting date	77		143
Relating to assets sold during the period	3		3
Purchases	311		360
Sales	-38		-76
Settlements	-33	[1]	-3	[1]
Transfers into (out of) Level 3	-30	[2],[3]	-623	[2]
Fair value of net plan assets at end of year	1,329		1,039
Hedge Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	4		12
Relating to assets still held at the reporting date	1		1
Purchases	109		0
Sales	-4		-1
Settlements	0	[1]	-4	[1]
Transfers into (out of) Level 3			-4	[2]
Fair value of net plan assets at end of year	110		4
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	806		754
Relating to assets still held at the reporting date	112		86
Relating to assets sold during the period	0		0
Purchases	173		123
Sales	0		0
Settlements	-203	[1]	-157	[1]
Transfers into (out of) Level 3	16	[2],[3]	0	[2]
Fair value of net plan assets at end of year	904		806
Private Equity Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	2		1
Relating to assets still held at the reporting date	0		0
Purchases	1		1
Sales	-2		0
Settlements	-1	[1]	0	[1]
Transfers into (out of) Level 3			0	[2]
Fair value of net plan assets at end of year	0		2
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	582		426
Relating to assets still held at the reporting date	83		63
Relating to assets sold during the period	0		-4
Purchases	136		226
Sales	-19		-91
Settlements	-65	[1]	-38	[1]
Transfers into (out of) Level 3	27	[2],[3]	0	[2]
Fair value of net plan assets at end of year	744		582
Real Estate Funds [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	109		95
Relating to assets still held at the reporting date	13		11
Purchases	1		3
Sales	-7		0
Settlements	0	[1]	0	[1]
Transfers into (out of) Level 3			0	[2]
Fair value of net plan assets at end of year	116		109
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	41		0
Relating to assets still held at the reporting date	7		0
Relating to assets sold during the period	0		0
Purchases	227		41
Sales	-3		0
Settlements	0	[1]	0	[1]
Transfers into (out of) Level 3	0	[2],[3]	0	[2]
Fair value of net plan assets at end of year	272		41
Debt Securities [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	0		0
Relating to assets still held at the reporting date	0		0
Purchases	0		0
Sales	0		0
Settlements	0	[1]	0	[1]
Transfers into (out of) Level 3			0	[2]
Fair value of net plan assets at end of year	0		0
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Pension Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	2		0
Relating to assets still held at the reporting date	0		0
Relating to assets sold during the period	0		0
Purchases	0		2
Sales	0		0
Settlements	0	[1]	0	[1]
Transfers into (out of) Level 3	0	[2],[3]	0	[2]
Fair value of net plan assets at end of year	2		2
Equity Security Individually Held [Member] | Fair Value, Inputs, Level 3 [Member] | Other Postretirement Benefit Plan, Defined Benefit [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Fair value of net plan assets at beginning of year	0		0
Relating to assets still held at the reporting date	0		0
Purchases	0		0
Sales	0		0
Settlements	0	[1]	0	[1]
Transfers into (out of) Level 3			0	[2]
Fair value of net plan assets at end of year	0		0
Hedge Fund Investments [Member] | Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Transfers into (out of) Level 3	$43		$627
[1]	Represents cash settlements only.
[2]	As of January 1, 2014 and January 1, 2013, hedge fund investments that contained redemption restrictions limiting Exelon’s ability to redeem the investments within a reasonable period of time were classified as Level 3 investments. As of December 31, 2014 and December 31, 2013, restrictions for certain investments no longer applied, therefore allowing redemption within a reasonable period of time from the measurement date at NAV. As such, these hedge fund investments are reflected as transfers out of Level 3 to Level 2 of $43 million and $627 million in 2014 and 2013 respectively.
[3]	In connection with the Employee Matters Agreement between EDF and Exelon, Exelon assumed the pension plan assets of Nine Mile Point Nuclear Station, LLC and Constellation Energy Nuclear Group, LLC resulting in transfers into Level 3 of $56 million.

Retirement_Benefits_Summary_of2

Retirement Benefits - Summary of Defined Contribution Savings Plan (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	$103		$85		$67
Exelon Generation Co L L C [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	51		40		30
Commonwealth Edison Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	26		22		19
PECO Energy Co [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	8		8		7
Baltimore Gas and Electric Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	8	[1]	8	[1]	7	[1]
Business Services Company [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions	10	[2]	7	[2]	5	[2]
Constellation Energy Group LLC [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Savings plan matching contributions					$1
[1]	BGE’s matching contributions for the year ended December 31, 2012 include $1 million incurred prior to the closing of the Constellation merger on March 12, 2012. These costs are not included in Exelon’s matching contributions for the year ended December 31, 2012.
[2]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO, or BGE amounts above.

Severance_Narrative_Details

Severance - Narrative (Details) (USD $)	12 Months Ended				3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2014	Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Severance costs			$124	[1],[2]
Business Combination, Integration Related Costs	19	28
Payments	24
Constellation Energy Nuclear Group LLC [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs					2
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs			80	[1]		16
Business Combination, Integration Related Costs					19
Operating And Maintenance Expense [Member] | Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs	$3	$2
[1]	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
[2]	Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period.

Severance_Severance_Liabilitie

Severance - Severance Liabilities related to CENG (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Restructuring Reserve [Roll Forward]
Payments	($24)
Severance [Member]
Restructuring Reserve [Roll Forward]
Beginning Balance	2
Severance charges	3
Payments	-11
Ending Balance	13
Constellation Energy Group LLC [Member] | Severance [Member]
Restructuring Reserve [Roll Forward]
Severance charges	$19	[1]
[1]	Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.

Severance_Severance_Benefit_Co

Severance - Severance Benefit Costs associated with Job Reductions (Details) (USD $)	12 Months Ended						3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2013
Restructuring Cost and Reserve [Line Items]
Stock compensation	$7	[1],[2]
Total severance benefits	138	[2],[3]
Severance costs	124	[1],[2]
Severance Costs [Member]
Restructuring Cost and Reserve [Line Items]
Net regulatory assets	35
Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	19	[4]	7	[4]	18	[4]
Stock compensation	7	[1],[2]
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation	4	[1]
Total severance benefits	88	[3]
Severance costs	80	[1]					16
Exelon Generation Co L L C [Member] | Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs	46
Exelon Generation Co L L C [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	14	[4]	5	[4]	16	[4]
Stock compensation	4	[1]
Commonwealth Edison Co [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation	1	[1],[2]
Total severance benefits	16	[2],[3]
Severance costs	14	[1],[2]
Commonwealth Edison Co [Member] | Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs	14
Commonwealth Edison Co [Member] | Severance Costs [Member]
Restructuring Cost and Reserve [Line Items]
Net regulatory assets	16
Commonwealth Edison Co [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	2	[4]	1	[4]	2	[4]
Stock compensation	1	[1],[2]
Baltimore Gas and Electric Company [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation	1	[1],[2]
Total severance benefits	19	[2],[3]
Severance costs	17	[1],[2]
Baltimore Gas and Electric Company [Member] | Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs	7
Baltimore Gas and Electric Company [Member] | Severance Costs [Member]
Restructuring Cost and Reserve [Line Items]
Net regulatory assets	19
Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	3	[4]	1	[4]	0	[4]
Stock compensation	1	[1],[2]
PECO Energy Co [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation	0	[1]
Total severance benefits	7	[3]
Severance costs	7	[1]
PECO Energy Co [Member] | Corporate, Non-Segment [Member]
Restructuring Cost and Reserve [Line Items]
Severance costs	7
PECO Energy Co [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	1	[4]	0	[4]	0	[4]
Stock compensation	$0	[1]
[1]	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
[2]	Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period.
[3]	Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this includes an additional $3 million of severance charges incurred in the first quarter of 2014 by CENG. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for additional information.
[4]	The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material

Severance_Severance_Liabilitie1

Severance - Severance Liabilities Rollforward (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Restructuring Cost and Reserve [Line Items]
Severance benefit obligation - beginning balance	$53	$111
Stock compensation				7	[1],[2]
Payments	-41	-64
Severance benefit obligation - ending balance	12	53		111
Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges		5	[3]
Stock Compensation Plan [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation		1
Exelon Generation Co L L C [Member]
Restructuring Cost and Reserve [Line Items]
Severance benefit obligation - beginning balance	10	33
Stock compensation				4	[1]
Payments	-7	-24
Severance benefit obligation - ending balance	3	10		33
Exelon Generation Co L L C [Member] | Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges		1	[3]
Exelon Generation Co L L C [Member] | Stock Compensation Plan [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation		0
Commonwealth Edison Co [Member]
Restructuring Cost and Reserve [Line Items]
Severance benefit obligation - beginning balance	0	1
Stock compensation				1	[1],[2]
Payments	0	-1
Severance benefit obligation - ending balance	0	0		1
Commonwealth Edison Co [Member] | Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges		0	[3]
Commonwealth Edison Co [Member] | Stock Compensation Plan [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation		0
PECO Energy Co [Member]
Restructuring Cost and Reserve [Line Items]
Severance benefit obligation - beginning balance	0	0
Stock compensation				0	[1]
Payments	0	0
Severance benefit obligation - ending balance	0	0		0
PECO Energy Co [Member] | Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges		0	[3]
PECO Energy Co [Member] | Stock Compensation Plan [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation		0
Baltimore Gas and Electric Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance benefit obligation - beginning balance	6	11
Stock compensation				1	[1],[2]
Payments	-4	-5
Severance benefit obligation - ending balance	2	6		11
Baltimore Gas and Electric Company [Member] | Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges		0	[3]
Baltimore Gas and Electric Company [Member] | Stock Compensation Plan [Member]
Restructuring Cost and Reserve [Line Items]
Stock compensation		$0
[1]	The amounts above include $46 million at Generation, $14 million at ComEd, $7 million at PECO, and $7 million at BGE, for amounts billed by BSC through intercompany allocations for the year ended December 31, 2012.
[2]	Exelon, ComEd and BGE established regulatory assets of $35 million, $16 million and $19 million, respectively, for severance benefits costs for the year ended December 31, 2012. The majority of these costs are expected to be recovered over a five-year period.
[3]	Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for under Exelon’s ongoing severance plan. One-time termination benefits were not material for the years ended December 31, 2014 and December 31, 2013.

Severance_Ongoing_Severance_Pl

Severance - Ongoing Severance Plans (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	$7	[1]	$18	[1]	$19	[1]
Business Service Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges			2		0
Severance [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	3
Severance accrual	3
Exelon Generation Co L L C [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	5	[1]	16	[1]	14	[1]
Exelon Generation Co L L C [Member] | Business Service Company [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	1
Commonwealth Edison Co [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	1	[1]	2	[1]	2	[1]
PECO Energy Co [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	0	[1]	0	[1]	1	[1]
Baltimore Gas and Electric Company [Member] | Other Severance Charges [Member]
Restructuring Cost and Reserve [Line Items]
Severance charges	$1	[1]	$0	[1]	$3	[1]
[1]	The amounts above for Generation include $1 million, $2 million, and $0 million for amounts billed by BSC through intercompany allocations for the years ended December 31, 2014, December 31, 2013, and December 31, 2012, respectively. Amounts billed by BSC to ComEd, PECO and BGE were not material

Preferred_and_Preference_Secur2

Preferred and Preference Securities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013	1-May-13
In Millions, except Share data, unless otherwise specified
Preferred Stock [Member]
Preferred Securities Additional Narrative Information [Line Items]
Shares authorized	100,000,000	100,000,000
Commonwealth Edison Co [Member] | Preferred Stock [Member]
Preferred Securities Additional Narrative Information [Line Items]
Shares authorized	850,000	850,000
Commonwealth Edison Co [Member] | Cumulative Preferred Stock [Member]
Preferred Securities Additional Narrative Information [Line Items]
Shares authorized	6,810,451	6,810,451
PECO Energy Co [Member]
Preferred Securities Additional Narrative Information [Line Items]
Preferred securities			$87
Baltimore Gas and Electric Company [Member] | Preference Stock [Member]
Preferred Securities Additional Narrative Information [Line Items]
Shares authorized	6,500,000	6,500,000
Preferred stock, par value	100	100

Preferred_and_Preference_Secur3

Preferred and Preference Securities - Summary of Preference Stock (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Class of Stock [Line Items]
Shares outstanding	1,900,000		1,900,000
Dollar amount	$190		$190
Series 7.125% Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate percentage	7.13%
Redemption price	$100	[1]
Shares outstanding	400,000		400,000
Dollar amount	40		40
Series 6.97% Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate percentage	6.97%
Redemption price	$100	[1]
Shares outstanding	500,000		500,000
Dollar amount	50		50
Series 6.7% Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate percentage	6.70%
Redemption price	$100	[1]
Shares outstanding	400,000		400,000
Dollar amount	40		40
Series 6.99% Preferred Stock [Member]
Class of Stock [Line Items]
Dividend rate percentage	6.99%
Redemption price	$100	[1]
Shares outstanding	600,000		600,000
Dollar amount	$60		$60
[1]	Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.

Schedule_of_Common_Stock_Autho

- Schedule of Common Stock Authorized and Outstanding (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Class of Stock [Line Items]
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	859,833,343	857,290,484
Commonwealth Edison Co [Member]
Class of Stock [Line Items]
Par value	12.5
Common stock, shares authorized	250,000,000
Common stock, shares outstanding	127,016,947	127,016,896
PECO Energy Co [Member]
Class of Stock [Line Items]
Common stock, shares authorized	500,000,000
Common stock, shares outstanding	170,478,507	170,478,507
Baltimore Gas and Electric Company [Member]
Class of Stock [Line Items]
Common stock, shares authorized	175,000,000
Common stock, shares outstanding	1,000	1,000

Common_Stock_Narrative_Details

Common Stock - Narrative (Details) (USD $)	1 Months Ended	3 Months Ended	12 Months Ended
	Jun. 30, 2014	Jun. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Stock Narrative Information [Line Items]
Common stock shares reserved for warrant conversion			24,511
Equity offering	57,500,000	57,500,000
Price per share (in usd per share)	$35	$35
Underwriting discount	$60,000,000	$35,000,000
Shares required to settle agreement			4,000,000
Junior subordinated notes	1,150,000,000	1,150,000,000
Shares of junior subordinated notes	23,000,000	23,000,000
Treasury stock, at cost			2,327,000,000	2,327,000,000
Expiration period			10 years
Obligations of outstanding restricted stock not settled			85,000,000	77,000,000
Settlement of restricted stock			43,000,000	28,000,000	25,000,000
Unrecognized compensation costs of nonvested restricted stock			59,000,000
Weighted average grant date fair value of performance shares (in usd per share)			28.75	31.55	39.71
Settlement of performance shares			27,000,000	26,000,000	23,000,000
Settlement of performance shares in cash			13,000,000	12,000,000	3,000,000
Unrecognized compensation costs of performance based shares			54,000,000
Weighted-average period of recognition of unrecognized compensation costs of performance based shares			1 year 7 months 6 days
2004 Repurchase Plan [Member]
Common Stock Narrative Information [Line Items]
Common stock held as treasury stock			35,000,000
Treasury stock, at cost			2,300,000,000
Commonwealth Edison Co [Member]
Common Stock Narrative Information [Line Items]
Warrants outstanding			73,533	73,709
Common stock shares reserved for warrant conversion				24,570
Performance Shares [Member]
Common Stock Narrative Information [Line Items]
Mix of awards				67.00%
Percentage to be settled as common stock			50.00%
Percentage to be settled as cash			50.00%
Percentage to be settled as cash if ownership requirements are met			100.00%
Weighted average grant date fair value (in usd per share)			$28.75
Nonvested Stock Option [Member]
Common Stock Narrative Information [Line Items]
Unrecognized compensation costs			1,000,000
Weighted-average period of recognition of unrecognized compensation costs			1 year
Employee Stock Option [Member]
Common Stock Narrative Information [Line Items]
Requisite service period			4 years
Restricted Stock [Member]
Common Stock Narrative Information [Line Items]
Mix of awards				33.00%
Weighted-average period of recognition of unrecognized compensation costs			2 years 1 month 6 days
Weighted average grant date fair value (in usd per share)			$28.71	$31.06	$39.94
Minimum [Member]
Common Stock Narrative Information [Line Items]
Net proceeds at the forward price specified in agreements	1,800,000,000	1,800,000,000
Minimum [Member] | Restricted Stock [Member]
Common Stock Narrative Information [Line Items]
Requisite service period			3 years
Maximum [Member]
Common Stock Narrative Information [Line Items]
Net proceeds at the forward price specified in agreements	$1,900,000,000	$1,900,000,000
Maximum [Member] | Restricted Stock [Member]
Common Stock Narrative Information [Line Items]
Requisite service period			5 years
LTIP [Member]
Common Stock Narrative Information [Line Items]
Shares authorized			16,000,000
2013 Plan [Member] | Performance Shares [Member]
Common Stock Narrative Information [Line Items]
Vesting period				3 years
2012 Plan [Member] | Performance Shares [Member]
Common Stock Narrative Information [Line Items]
Vesting period				3 years
Performance period				1 year
Performance Share Transition Award [Member]
Common Stock Narrative Information [Line Items]
Percentage to be settled as common stock				50.00%
Percentage to be settled as cash				50.00%
Percentage to be settled as cash if ownership requirements are met				100.00%
Performance Share Transition Award [Member] | Performance Shares [Member]
Common Stock Narrative Information [Line Items]
Vesting period				1 year
Performance period				2 years

Common_Stock_Schedule_of_Stock

Common Stock - Schedule of Stock-based Compensation Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Stock [Abstract]
Performance share awards	$59	$48	$46
Restricted stock units	61	61	50
Stock options	2	3	15
Other stock-based awards	5	6	4
Total stock-based compensation expense included in operating and maintenance expense	127	118	115
Income tax benefit	-47	-44	-44
Total after-tax stock-based compensation expense	$80	$74	$71

Common_Stock_Schedule_of_PreTa

Common Stock - Schedule of Pre-Tax Stock-based Compensation Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense	$127		$118		$115	[1]
Exelon Generation Co L L C [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense	52		48		42	[1]
Commonwealth Edison Co [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense	7		9		11	[1]
PECO Energy Co [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense	3		5		5	[1]
Baltimore Gas and Electric Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense	5		6		5	[1]
Business Services Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense	60	[2]	50	[2]	52	[1],[2]
CENG [Member] | Baltimore Gas and Electric Company [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Pre-tax stock-based compensation expense					$2
[1]	BGE’s stock-based compensation expense (pre-tax) for December 31, 2012 excludes $2 million of cost incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012. This amount is not included in Exelon’s stock-based compensation expense for the year ended December 31, 2012 shown in the table titled Components of Stock-Based Compensation Expense and the breakout by subsidiary above.
[2]	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO and BGE amounts above.

Common_Stock_Components_of_Tax

Common Stock - Components of Tax Benefits from Stock-based Compensation (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Common Stock [Abstract]
Stock options	$0	$0	$3
Restricted stock units	17	11	11
Performance share awards	11	11	7
Stock deferral plan	0	1	0
Stock options	$0	$0	$2

Common_Stock_Assumptions_used_

Common Stock - Assumptions used in Calculating Fair Value of Options (Details) (USD $)	12 Months Ended
	Dec. 31, 2012
Common Stock [Abstract]
Dividend yield	5.28%
Expected volatility	23.20%
Risk-free interest rate	1.30%
Expected life (years)	6 years 3 months
Weighted average grant date fair value (per share)	$4.18

Common_Stock_Summary_of_Stock_

Common Stock - Summary of Stock Option Activity (Details) (Employee Stock Option [Member], USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Employee Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
31-Dec-13	21,035,445
Options exercised	-291,805
Options forfeited	-8,886
Options expired	-1,903,787
31-Dec-14	18,830,967
Weighted Average Exercise Price (in usd per share)	$46.85		$46.07
Options Reinstated, Weighted Average Exercise Price (in usd per share)	$25.27
Options Forfeited, Weighted Average Exercise Price (in usd per share)	$55.78
Options Expired, Weighted Average Exercise Price (in usd per share)	$41.47
Shares Outstanding, Weighted Average Remaining Contractual Life	4 years 1 month 10 days
Shares Outstanding, Aggregate Intrinsic Value	$29
Exercisable at December 31, 2014	18,398,932	[1]
Shares Exercisable, Weighted Average Exercise Price (in usd per share)	$47.01	[1]
Shares Exercisable, Weighted Average Remaining Contractual Life	4 years 15 days	[1]
Shares Exercisable, Aggregate Intrinsic Value	$29	[1]
[1]	Includes stock options issued to retirement eligible employees.

Common_Stock_Summary_of_Inform

Common Stock - Summary of Information of Stock Options Exercised (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Common Stock [Abstract]
Aggregate value	$3	[1]	$4	[1]	$19	[1]
Cash received for exercise price	$7		$19		$47
[1]	Includes stock options issued to retirement eligible employees.

Common_Stock_Summary_of_Nonves

Common Stock - Summary of Nonvested Stock Option Activity (Details) (Nonvested Stock Option [Member], USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Nonvested Stock Option [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Options, Nonvested, Number of Shares [Roll Forward]
Nonvested at December 31, 2013	847,118	[1]
Vested	-406,197
Forfeited	-8,886
Nonvested at December 31, 2014	432,035	[1]
Nonvested, Weighted Average Exercise Price (in usd per share)	$39.91	[1]	$40.22	[1]
Vested, Weighted Average Exercise Price (in usd per share)	$40.21
Forfeited, Weighted Average Exercise Price (in usd per share)	$55.78
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees	746,140		1,348,913
[1]	Excludes 746,140 and 1,348,913 of stock options issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.

Common_Stock_Summary_of_Nonves1

Common Stock - Summary of Nonvested Restrict Stock Unit Activity (Details) (Restricted Stock [Member], USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2014
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested at December 31, 2013	3,386,697	[1]
Granted	2,252,574
Vested	-1,216,016
Forfeited	-86,094
Undistributed vested awards	-578,943	[2]
Nonvested at December 31, 2014	3,758,218	[1]	3,386,697	[1]
Nonvested, Weighted Average Exercise Price (in usd per share)	$34.10	[1]				$31.27	[1]
Granted, Weighted Average Grant Date Fair Value (in usd per share)	$28.71		$31.06		$39.94
Vested, Weighted Average Exercise Price (in usd per share)	$35.36
Forfeited, Weighted Average Exercise Price (in usd per share)	$31.99
Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)	$29.17	[2]
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees	975,116		931,628
[1]	Excludes 975,116 and 931,628 of restricted stock units issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
[2]	Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2014.

Common_Stock_Summary_of_Nonves2

Common Stock - Summary of Nonvested Performance Share Awards Activity (Details) (Performance Shares [Member], USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Nonvested at December 31, 2013	2,014,190	[1]
Granted	1,712,085
Change in performance	98,227
Vested	-497,714
Forfeited	-29,476
Undistributed vested awards	-601,215	[2]
Nonvested at December 31, 2014	2,696,097	[1]
Nonvested, Weighted Average Exercise Price (in usd per share)	$30.62	[1]	$32.74	[1]
Granted, Weighted Average Grant Date Fair Value (in usd per share)	$28.75
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Change in Performance, Weighted Average Grant Date Fair Value	$31.85
Vested, Weighted Average Exercise Price (in usd per share)	$35.05
Forfeited, Weighted Average Exercise Price (in usd per share)	$30.16
Undistributed Vested Awards, Weighted Average Grant Date Fair Value (in usd per share)	$28.96	[2]
Fully Vested Stock Based Compensation Issued To Retirement Eligible Employees	1,535,791		1,411,824
[1]	Excludes 1,535,791 and 1,411,824 of performance share awards issued to retirement-eligible employees as of December 31, 2014 and December 31, 2013, respectively, as they are fully vested.
[2]	Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2014.

Common_Stock_Balance_Sheet_Cla

Common Stock - Balance Sheet Classification of Obligations related to Outstanding Performance Share Awards Not Yet Settled (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Millions, unless otherwise specified
Common Stock [Abstract]
Current liabilities	$28	[1]	$13	[1]
Deferred credits and other liabilities	36	[2]	24	[2]
Common stock	33		32
Total	$97		$69
[1]	Represents the current liability related to performance share awards expected to be settled in cash.
[2]	Represents the long-term liability related to performance share awards expected to be settled in cash.

Earnings_Per_Share_and_Equity_2

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share [Abstract]
Net income attributable to common shareholders									$1,623	$1,719	$1,160
Weighted average common shares outstanding—basic	861	861	860	858	856	857	856	855	860	856	816
Assumed exercise and/or distributions of stock-based awards									4	4	3
Weighted average common shares outstanding—diluted	868	863	864	861	860	860	860	855	864	860	819

Earnings_Per_Share_and_Equity_3

Earnings Per Share and Equity - Narrative (Details) (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger)	17,000,000	20,000,000	14,000,000
Treasury Stock, Shares held	35,000,000	35,000,000
Treasury stock, at cost	$2,327	$2,327
Pepco Holdings [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Stock options not included in the calculation of diluted common shares outstanding (less than 1 million related to PHI merger)	1,000,000

Changes_in_Accumulated_Other_C2

Changes in Accumulated Other Comprehensive Income - Schedule of Changes in AOCI (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	($2,040)	[1]	($2,767)	[1]
OCI before reclassifications	-528		791	[1]
Amounts reclassified from AOCI	-116		-64	[1],[2]
Other comprehensive income (loss)	-644		727	[1]	-317
Ending balance	-2,684		-2,040	[1]	-2,767	[1]
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	120	[1]	368	[1]
OCI before reclassifications	-31		29	[1]
Amounts reclassified from AOCI	-117		-277	[1],[2]
Other comprehensive income (loss)	-148		-248	[1]
Ending balance	-28		120	[1]
Accumulated Net Unrealized Investment Gain (Loss) [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	2	[1]
OCI before reclassifications	-1		2	[1]
Amounts reclassified from AOCI	2
Other comprehensive income (loss)	1		2	[1]
Ending balance	3		2	[1]
Accumulated Defined Benefit Plans Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-2,260	[1]	-3,137	[1]
OCI before reclassifications	-498		669	[1]
Amounts reclassified from AOCI	118		208	[1],[2]
Other comprehensive income (loss)	-380		877	[1]
Ending balance	-2,640		-2,260	[1]
Accumulated Translation Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-10	[1]
OCI before reclassifications	-9		-10	[1]
Other comprehensive income (loss)	-9		-10	[1]
Ending balance	-19		-10	[1]
Accumulated Equity Investment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	108	[1]	2	[1]
OCI before reclassifications	11		101	[1]
Amounts reclassified from AOCI	-119		5	[1],[2]
Other comprehensive income (loss)	-108		106	[1]
Ending balance	0		108	[1]
Exelon Generation Co L L C [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	214	[1]	513	[1]
OCI before reclassifications	-14		109	[1]
Amounts reclassified from AOCI	-236		-408	[1],[2]
Other comprehensive income (loss)	-250		-299	[1]	-402
Ending balance	-36		214	[1]	513	[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	114	[1]	512	[1]
OCI before reclassifications	-15		15	[1]
Amounts reclassified from AOCI	-117		-413	[1],[2]
Other comprehensive income (loss)	-132		-398	[1]
Ending balance	-18		114	[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	2	[1]	0	[1]
OCI before reclassifications	-1		2	[1]
Other comprehensive income (loss)	-1		2	[1]
Ending balance	1		2	[1]
Exelon Generation Co L L C [Member] | Accumulated Translation Adjustment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	-10	[1]
OCI before reclassifications	-9		-10	[1]
Other comprehensive income (loss)	-9		-10	[1]
Ending balance	-19		-10	[1]
Exelon Generation Co L L C [Member] | Accumulated Equity Investment [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	108	[1]	1	[1]
OCI before reclassifications	11		102	[1]
Amounts reclassified from AOCI	-119		5	[1],[2]
Other comprehensive income (loss)	-108		107	[1]
Ending balance	0		108	[1]
PECO Energy Co [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Beginning balance	1	[1]	1	[1]
Other comprehensive income (loss)	0		0		1
Ending balance	1		1	[1]	1	[1]
PECO Energy Co [Member] | Accumulated Net Unrealized Investment Gain (Loss) [Member]
Movement in Accumulated Other Comprehensive Income [Roll Forward]
Ending balance	$1		$1	[1]	$1	[1]
[1]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[2]	See next tables for details about these reclassifications.

Changes_in_Accumulated_Other_C3

Changes in Accumulated Other Comprehensive Income - Reclassifications out of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended										12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenues	$7,255		$6,912	$6,024	$7,237	$6,163	$6,502	$6,141	$6,082		$27,429	[1]	$24,888	[1]	$23,489	[1]
Interest expense											-610		-896		-575
Prior service costs											19		0		-1
Sale of equity method investment											455		460		353
Total income (loss) in equity method investments											-20		10		-91
Income before income taxes											2,486		2,773		1,798
Income tax benefit (expense)											-666		-1,044		-627
Net income	18	[2]	993	522	90	495	738	490	-4	[3]	1,820		1,729		1,171
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income											116	[4]	64	[4]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income											-2	[4]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenues											-2	[4]
Income before income taxes											195	[4]	461	[4]
Income tax benefit (expense)											-78	[4]	-184	[4]
Net income											117	[4]	277	[4]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenues											195	[4]	464	[4]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense													-3	[4]
Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Sale of equity method investment											5	[4]
Equity in losses of unconsolidated affiliates											193	[4]
Total income (loss) in equity method investments													-8	[4]
Income before income taxes													-8	[4]
Income tax benefit (expense)													3	[4]
Net income													-5	[4]
Exelon Generation Co L L C [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenues	4,802		4,412	3,789	4,390	3,772	4,255	4,070	3,533		17,393		15,630		14,437
Interest expense											50		-2		-55
Sale of equity method investment											406		355		246
Total income (loss) in equity method investments											-20		10		-91
Income tax benefit (expense)											-207		-615		-500
Net income	-91		771	340	-185	269	490	330	-18		1,019		1,060		558
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Net income											236	[4]	408	[4]
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income before income taxes											195	[4]	683	[4]
Income tax benefit (expense)											-78	[4]	-270	[4]
Net income											117	[4]	413	[4]
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Energy Related Derivative [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Revenues											195	[4]	683	[4]
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] | Cash Flow Hedging [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Interest expense													0	[4]
Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Sale of equity method investment											5	[4]
Equity in losses of unconsolidated affiliates											193	[4]
Total income (loss) in equity method investments													-8	[4]
Income before income taxes													-8	[4]
Income tax benefit (expense)													3	[4]
Net income													-5	[4]
Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Nuclear Decommissioning Attributable To Equity Method Investments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income before income taxes											198	[4]
Income tax benefit (expense)											-79	[4]
Net income											119	[4]
Other Equity Investment Reclassified Out of Accumulated Other Comprehensive Income [Member] | Exelon Generation Co L L C [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Pension Nuclear Decommissioning Attributable To Equity Method Investments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Income before income taxes											198	[4]
Income tax benefit (expense)											-79	[4]
Net income											119	[4]
Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Prior service costs											46	[4],[5]	-2	[4],[5]
Actuarial gains/losses											-239	[4],[5]	-339	[4],[5]
Income before income taxes											-193	[4]	-342	[4]
Income tax benefit (expense)											75	[4]	134	[4]
Net income											-118	[4]	-208	[4]
Pension Plan, Defined Benefit [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Equity Method Investments [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Actuarial gains/losses													($1)	[4],[6]
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[3]	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
[4]	Amounts in parenthesis represent a decrease in net income.
[5]	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 16 — Retirement Benefits for additional details).
[6]	Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.

Changes_in_Accumulated_Other_C4

Changes in Accumulated Other Comprehensive Income - Components of Accumulated Other Comprehensive Income (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Line Items]
Prior service costs	$19	$0	($1)
Actuarial loss reclassified to periodic cost, taxes	-93	-133	-110
Other Comprehensive (Income) Loss, Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Transition (Asset) Obligation, Tax			-2
Pension and non-pension postretirement benefit plan valuation adjustment, taxes	317	-430	237
Change in unrealized gain (loss) on cash flow hedges, taxes	96	166	68
Change in unrealized gain (loss) on equity investments taxes	73	-71	-1
Other Comprehensive Income (Loss), Unrealized Holding Gain (Loss) on Securities Arising During Period, Tax			1
Other comprehensive income, income taxes	412	-468	192
Exelon Generation Co L L C [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Change in unrealized gain (loss) on cash flow hedges, taxes	84	262	262
Change in unrealized gain (loss) on equity investments taxes	73	-72	1
Other comprehensive income, income taxes	$157	$190	$263

Commitments_and_Contingencies_2

Commitments and Contingencies - Narrative (Details) (USD $)

0 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

1 Months Ended

3 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

1 Months Ended

12 Months Ended

0 Months Ended

Jun. 05, 2013

Jun. 30, 2013

Dec. 31, 2014

Dec. 31, 2012

Apr. 12, 2012

Feb. 28, 2012

Jan. 31, 2013

Oct. 31, 2007

Jun. 30, 2014

Dec. 31, 2013

Jan. 31, 2005

Nov. 19, 2013

Jul. 11, 2011

Sep. 30, 2014

31-May-06

Dec. 31, 1999

Jan. 22, 2015

Jul. 26, 2013

Dec. 27, 2013

Dec. 12, 2014

Dec. 22, 2014

Mar. 31, 2014

Dec. 31, 2003

30-May-12

Customer

Open_claim

Defendant

Defendant

Defendant

Customer

Principle_responsible_party

Principle_responsible_party

MW

MW

MW

MW

Commitments and Contingencies [Line Items]

Nuclear insurance liability limit per incident

$18,300,000

Cost surcharge to Price-Anderson Act nuclear incident assessment

5.00%

Guarantee obligations maximum exposure

9,402,000,000

Coal rail car lease proof of claims

21,000,000

Maximum estimated clean-up costs for all potentially responsible parties

105,000,000

Asbestos liability reserve

100,000,000

90,000,000

Probable contingency (liability)

22,000,000

Open asbestos liability claims

255

Asbestos liability reserve related to anticipated claims

78,000,000

FERC civil penalty

110,000,000

FERC settlement recorded in operation and maintenance expense

50,000,000

Number of customers affected by a major storm

34,559

Rossville ash site [Member]

Commitments and Contingencies [Line Items]

Area of property

32

Cotter Corporation [Member]

Commitments and Contingencies [Line Items]

Number of defendants

14

15

Nuclear Insurance Premiums [Member]

Commitments and Contingencies [Line Items]

Guarantee obligations maximum exposure

3,014,000,000

[1]

Sithe Guarantee [Member]

Commitments and Contingencies [Line Items]

Guarantee obligations maximum exposure

200,000,000

Exelon Generation Co L L C [Member]

Commitments and Contingencies [Line Items]

Nuclear financial protection pool value

375,000,000

United States licensed nuclear reactors total

104

Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses

13,200,000,000

Cost surcharge to Price-Anderson Act nuclear incident assessment

12730000000.00%

Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident

19,000,000

Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident

2,700,000,000

Total retrospective premium obligation under insurance from a nuclear industry mutual insurance company

319,000,000

Mutual Replacement Power Cost Insurance Maximum Retrospective Premium Obligation

3,200,000,000

Cost of spent nuclear fuel disposal per kWh of net nuclear generation

0.001

Net nuclear fuel disposal fees

49,000,000

136,000,000

Department of Energy SNF one-time fee applicable to nuclear generation

277,000,000

DOE SNF one-time fee with interest

1,021,000,000

13-week Treasury Rate used to calculate DOE SNF one-time fee

2.00%

Capacity of energy construction project

150

Guarantee obligations maximum exposure

6,384,000,000

Consent decree penalty

1,000,000

Environmental loss contingencies

13,000,000

14,000,000

Payments for operating leases

10,000,000

Increase (decrease) in the value of the asbestos liability reserve

15,000,000

25,000,000

Open asbestos liability claims

300

FERC civil penalty

135,000,000

FERC settlement recorded in operation and maintenance expense

195,000,000

Exelon Generation Co L L C [Member] | Cotter Corporation [Member]

Commitments and Contingencies [Line Items]

Total cost of remediation to be shared by PRPs

50,000,000

DOJ potential settlement

90,000,000

Exelon Generation Co L L C [Member] | Rossville ash site [Member]

Commitments and Contingencies [Line Items]

Estimate of possible loss

10,000,000

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

Commitments and Contingencies [Line Items]

Purchase obligations, due within two years

38,000,000

Unrecorded unconditional purchase obligation, due in next 12 months

98,000,000

Other unrecorded amounts

20,000,000

Exelon Generation Co L L C [Member] | Perryman Construction [Member]

Commitments and Contingencies [Line Items]

Purchase obligations, due within two years

39,000,000

Capacity of energy construction project

120

Exelon Generation Co L L C [Member] | Fourmile Wind Project [Member]

Commitments and Contingencies [Line Items]

Capacity of energy construction project

40

40

Unrecorded unconditional purchase obligation, due in next 12 months

2,000,000

Exelon Generation Co L L C [Member] | Combine-cycle Turbine Units [Member]

Commitments and Contingencies [Line Items]

Unrecorded unconditional purchase obligation, due in next 12 months

1,000,000,000

Exelon Generation Co L L C [Member] | Fair Wind Project [Member]

Commitments and Contingencies [Line Items]

Capacity of energy construction project

30

30

Unrecorded unconditional purchase obligation, due in next 12 months

19,000,000

Exelon Generation Co L L C [Member] | Sendero Wind Project [Member]

Commitments and Contingencies [Line Items]

Capacity of energy construction project

78

Unrecorded unconditional purchase obligation, due in next 12 months

56,000,000

Exelon Generation Co L L C [Member] | Beebe Construction [Member]

Commitments and Contingencies [Line Items]

Accrued environmental liabilities

2,000,000

Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]

Commitments and Contingencies [Line Items]

Nuclear insurance liability limit per incident

13,600,000,000

Guarantee obligations maximum exposure

3,014,000,000

[2]

Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]

Commitments and Contingencies [Line Items]

Mutual Property Insurance Distribution To Members

18,500,000

Exelon Generation Co L L C [Member] | Sithe Guarantee [Member]

Commitments and Contingencies [Line Items]

Acquisition of interest in subsidiary

50.00%

Sale of interest in subsidiary

100.00%

Midwest Generation, LLC [Member]

Commitments and Contingencies [Line Items]

Environmental loss contingencies

9,000,000

Percentage agreed to reimburse related parties

50.00%

Increase (decrease) in the value of the asbestos liability reserve

6,000,000

Midwest Generation's estimated environmental investigation and remediation costs

53,000,000

Commonwealth Edison Co [Member]

Commitments and Contingencies [Line Items]

Guarantee obligations maximum exposure

222,000,000

Total number of MGP sites

42

Sites approved for clean-up

17

Sites under study/remediation

25

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 possible defendants

1,200,000

Interest rate on long-term debt

6.35%

[3]

Commonwealth Edison Co [Member] | Minimum [Member]

Commitments and Contingencies [Line Items]

Value of damages sought

500

Commonwealth Edison Co [Member] | Maximum [Member]

Commitments and Contingencies [Line Items]

Value of damages sought

1,500

Commonwealth Edison Co [Member] | Accrual For MGP Investigation And Remediation [Member]

Commitments and Contingencies [Line Items]

Increase (decrease) in accrual for environmental loss contingencies

26,000,000

PECO Energy Co [Member]

Commitments and Contingencies [Line Items]

Guarantee obligations maximum exposure

218,000,000

Total number of MGP sites

26

Sites approved for clean-up

16

Sites under study/remediation

10

PECO Energy Co [Member] | Accrual For MGP Investigation And Remediation [Member]

Commitments and Contingencies [Line Items]

Increase (decrease) in accrual for environmental loss contingencies

4,000,000

Baltimore Gas and Electric Company [Member]

Commitments and Contingencies [Line Items]

Guarantee obligations maximum exposure

265,000,000

Total number of MGP sites

13

Sites under study/remediation

2

Maximum estimated clean-up costs for all potentially responsible parties

1,700,000

Number of claimants

486

Baltimore Gas and Electric Company [Member] | Deferrable Interest Subordinated Debentures [Member]

Commitments and Contingencies [Line Items]

Interest rate on long-term debt

6.20%

Baltimore Gas and Electric Company [Member] | Sixty-Eighth Street Dump [Member]

Commitments and Contingencies [Line Items]

Number of parties jointly and severally liable In environmental protection agency action

19

19

Minimum estimated clean-up costs for all potentially responsible parties

50,000,000

Maximum estimated clean-up costs for all potentially responsible parties

64,000,000

Subsequent Event [Member]

Commitments and Contingencies [Line Items]

Settlement amount

$14,000,000

[1]

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

[2]

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

[3]

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

Commitments_and_Contingencies_3

Commitments and Contingencies - Schedule of Government Agreement Settlements (Details) (Department of Energy [Member], Exelon Generation Co L L C [Member], USD $)	9 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2014		Dec. 31, 2013
Department of Energy [Member] | Exelon Generation Co L L C [Member]
Schedule of Government Agreements [Line Items]
Spent Nuclear Fuel Storage Reimbursement	$33	[1]	$836	[1]
Spent Nuclear Fuel Storage Reimbursement Net Co Owners	30	[1],[2]	702	[1],[2]
DOE Receivable - Current	82	[3]	82	[3]	71	[3]
DOE Receivable - Noncurrent	7	[4]	7	[4]	0	[4]
Amounts owed to co-owners	($5)	[3],[5]	($5)	[3],[5]	($18)	[3],[5]
[1]	Includes $33 million and $30 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation of CENG.
[2]	Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.
[3]	Recorded in Accounts receivable, other.
[4]	Recorded in Deferred debits and other assets, other
[5]	Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.

Commitments_and_Contingencies_4

Commitments and Contingencies - Schedule of Purchases of Energy, Capacity and Transmission Rights (Details) (Exelon Generation Co L L C [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Capacity Offsets [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	$132
2016	133	[1]
2017	136
2018	137
2019	138
Thereafter	591
Net Capacity Purchases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	418	[1]
2016	283	[1]
2017	222	[1]
2018	112	[1]
2019	117	[1]
Thereafter	279	[1]
Total	1,431	[1]
Power Purchases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	152	[2]
2016	228	[2]
2017	121	[2]
2018	29	[2]
2019	5	[2]
Thereafter	1	[2]
Total	536	[2]
Transmission Rights Purchases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	20	[3]
2016	15	[3]
2017	15	[3]
2018	16	[3]
2019	16	[3]
Thereafter	35	[3]
Total	117	[3]
Total Unregulated Energy Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
2015	590
2016	526
2017	358
2018	157
2019	138
Thereafter	315
Total	$2,084
[1]	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 December 31, 2014, 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 December 31, 2014, capacity offsets were $132 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.
[2]	The table excludes renewable energy purchases that are contingent in nature.
[3]	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.

Commitments_and_Contingencies_5

Commitments and Contingencies - Schedule of Energy Supply Procurement, Curtailment Services, REC and AEC Purchase Commitments (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Commonwealth Edison Co [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Term of contract	20 years
Commonwealth Edison Co [Member] | DSP Program Electric Procurement Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	620	[1]
2015	329	[1]
2016	151	[1]
2017	140	[1]
2018	0	[1]
2019	0	[1]
Thereafter	0	[1]
Commonwealth Edison Co [Member] | Renewable Energy Including Renewable Energy Credits [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	1,517	[2]
2015	75	[2]
2016	76	[2]
2017	77	[2]
2018	78	[2]
2019	84	[2]
Thereafter	1,127	[2]
PECO Energy Co [Member] | DSP Program Electric Procurement Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	609	[2]
2015	527	[3]
2016	82	[3]
2017	0	[3]
2018	0	[3]
2019	0	[3]
Thereafter	0	[3]
PECO Energy Co [Member] | Alternative Energy Credits [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	13	[4]
2015	2	[4]
2016	2	[4]
2017	2	[4]
2018	2	[4]
2019	2	[4]
Thereafter	3	[4]
Baltimore Gas and Electric Company [Member] | DSP Program Electric Procurement Contracts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	1,315	[5]
2015	779	[5]
2016	448	[5]
2017	88	[5]
2018	0	[5]
2019	0	[5]
Thereafter	0	[5]
Baltimore Gas and Electric Company [Member] | Curtailment Services [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	115	[6]
2015	40	[6]
2016	34	[6]
2017	29	[6]
2018	12	[6]
2019	0	[6]
Thereafter	0	[6]
[1]	ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of December 31, 2014, 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]	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.
[3]	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2015 and 2016. 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 3 — Regulatory Matters for additional information.
[4]	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 3 — Regulatory Matters for additional information.
[5]	BGE entered into various contracts for the procurement of electricity beginning 2015 through 2017. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 3 — Regulatory Matters for additional information.
[6]	BGE has entered into various contracts with curtailment services providers related to transactions in PJM’s capacity market. See Note 3 — Regulatory Matters for additional information.

Commitments_and_Contingencies_6

Commitments and Contingencies - Schedule of Fuel Purchase Obligations (Details) (Public Utilities, Inventory, Fuel [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Exelon Generation Co L L C [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	$8,981
2015	1,404
2016	1,119
2017	1,124
2018	1,001
2019	888
Thereafter	3,445
PECO Energy Co [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	428
2015	146
2016	103
2017	60
2018	34
2019	14
Thereafter	71
Baltimore Gas and Electric Company [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	611
2015	111
2016	82
2017	67
2018	57
2019	54
Thereafter	$240

Commitments_and_Contingencies_7

Commitments and Contingencies - Schedule of Other Purchase Obligations (Details) (Other Purchase Obligations [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	$894
2015	336
2016	258
2017	150
2018	36
2019	30
Thereafter	84
Exelon Generation Co L L C [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	396	[1],[2]
2015	163	[1],[2]
2016	67	[1],[2]
2017	42	[1],[2]
2018	30	[1],[2]
2019	24	[1],[2]
Thereafter	70	[1],[2]
Commonwealth Edison Co [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	148	[3]
2015	63	[3]
2016	77	[3]
2017	1	[3]
2018	1	[3]
2019	1	[3]
Thereafter	5	[3]
PECO Energy Co [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	7	[3]
2015	3	[3]
2016	4	[3]
2017	0	[3]
2018	0	[3]
2019	0	[3]
Thereafter	0	[3]
Baltimore Gas and Electric Company [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Total	343	[3]
2015	107	[3]
2016	110	[3]
2017	107	[3]
2018	5	[3]
2019	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]	Purchase obligations include commitments related to assets-held-for-sale. See Note 4 — Mergers, Acquisitions, and Dispositions for additional information.
[3]	Purchase obligations include commitments related to smart meter installation. See Note 3 — Regulatory Matters for additional information.

Commitments_and_Contingencies_8

Commitments and Contingencies - Schedule of Commercial Commitments (Details) (USD $)	Dec. 31, 2014
Guarantor Obligations [Line Items]
Total	$9,402,000,000
2015	5,448,000,000
2016	107,000,000
2017	29,000,000
2018	21,000,000
2019	22,000,000
2020 and beyond	3,775,000,000
Percentage ownership of common stock	100.00%
Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Total	1,233,000,000	[1]
2015	1,151,000,000	[1]
2016	77,000,000	[1]
2017	5,000,000	[1]
2018	0	[1]
2019	0	[1]
2020 and beyond	0	[1]
Surety Bond [Member]
Guarantor Obligations [Line Items]
Total	596,000,000	[2]
2015	545,000,000	[2]
2016	10,000,000	[2]
2017	4,000,000	[2]
2018	1,000,000	[2]
2019	2,000,000	[2]
2020 and beyond	34,000,000	[2]
Performance Guarantee [Member]
Guarantor Obligations [Line Items]
Total	1,239,000,000	[3]
2015	472,000,000	[2]
2016	20,000,000	[2]
2017	20,000,000	[2]
2018	20,000,000	[2]
2019	20,000,000	[2]
2020 and beyond	687,000,000	[2]
Energy Contract Guarantee [Member]
Guarantor Obligations [Line Items]
Total	3,220,000,000	[4]
2015	3,220,000,000	[4]
2016	0	[4]
2017	0	[4]
2018	0	[4]
2019	0	[4]
2020 and beyond	0	[4]
Estimated total assumed for commercial transaction obligations	3,200,000,000
Property Lease Guarantee [Member]
Guarantor Obligations [Line Items]
Total	40,000,000	[5]
2015	0	[5]
2016	0	[5]
2017	0	[5]
2018	0	[5]
2019	0	[5]
2020 and beyond	40,000,000	[5]
Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Total	3,014,000,000	[6]
2015	0	[6]
2016	0	[6]
2017	0	[6]
2018	0	[6]
2019	0	[6]
2020 and beyond	3,014,000,000	[6]
Underwriters Discount [Member]
Guarantor Obligations [Line Items]
Total	60,000,000	[7]
2015	60,000,000	[7]
2016	0	[7]
2017	0	[7]
2018	0	[7]
2019	0	[7]
2020 and beyond	0	[7]
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Estimated net exposure for commercial transaction obligations	600,000,000
Baltimore Gas and Electric Company [Member]
Guarantor Obligations [Line Items]
Total	265,000,000
2015	15,000,000
2016	0
2017	0
2018	0
2019	0
2020 and beyond	250,000,000
Baltimore Gas and Electric Company [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Total	1,000,000	[8]
2015	1,000,000	[8]
2016	0	[8]
2017	0	[8]
2018	0	[8]
2019	0	[8]
2020 and beyond	0	[8]
Baltimore Gas and Electric Company [Member] | Surety Bond [Member]
Guarantor Obligations [Line Items]
Total	11,000,000	[9]
2015	11,000,000	[9]
2016	0	[9]
2017	0	[9]
2018	0	[9]
2019	0	[9]
2020 and beyond	0	[9]
Baltimore Gas and Electric Company [Member] | Performance Guarantee [Member]
Guarantor Obligations [Line Items]
Total	253,000,000	[10]
2015	3,000,000	[10]
2016	0	[10]
2017	0	[10]
2018	0	[10]
2019	0	[10]
2020 and beyond	250,000,000	[10]
Baltimore Gas and Electric Company [Member] | Trust Preferred Securities [Member]
Guarantor Obligations [Line Items]
Total	250,000,000
PECO Energy Co [Member]
Guarantor Obligations [Line Items]
Total	218,000,000
2015	40,000,000
2016	0
2017	0
2018	0
2019	0
2020 and beyond	178,000,000
PECO Energy Co [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Total	22,000,000	[11]
2015	22,000,000	[11]
2016	0	[11]
2017	0	[11]
2018	0	[11]
2019	0	[11]
2020 and beyond	0	[11]
PECO Energy Co [Member] | Surety Bond [Member]
Guarantor Obligations [Line Items]
Total	18,000,000	[2]
2015	18,000,000	[2]
2016	0	[2]
2017	0	[2]
2018	0	[2]
2019	0	[2]
2020 and beyond	0	[2]
PECO Energy Co [Member] | Performance Guarantee [Member]
Guarantor Obligations [Line Items]
Total	178,000,000	[12]
2015	0	[12]
2016	0	[12]
2017	0	[12]
2018	0	[12]
2019	0	[12]
2020 and beyond	178,000,000	[12]
PECO Energy Co [Member] | Trust Preferred Securities [Member]
Guarantor Obligations [Line Items]
Total	178,000,000
Commonwealth Edison Co [Member]
Guarantor Obligations [Line Items]
Total	222,000,000
2015	20,000,000
2016	0
2017	0
2018	0
2019	0
2020 and beyond	202,000,000
Commonwealth Edison Co [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Total	17,000,000	[13]
2015	17,000,000	[13]
2016	0	[13]
2017	0	[13]
2018	0	[13]
2019	0	[13]
2020 and beyond	0	[13]
Commonwealth Edison Co [Member] | Surety Bond [Member]
Guarantor Obligations [Line Items]
Total	5,000,000	[2]
2015	3,000,000	[2]
2016	0	[2]
2017	0	[2]
2018	0	[2]
2019	0	[2]
2020 and beyond	2,000,000	[2]
Commonwealth Edison Co [Member] | Performance Guarantee [Member]
Guarantor Obligations [Line Items]
Total	200,000,000	[14]
2015	0	[14]
2016	0	[14]
2017	0	[14]
2018	0	[14]
2019	0	[14]
2020 and beyond	200,000,000	[14]
Commonwealth Edison Co [Member] | Trust Preferred Securities [Member]
Guarantor Obligations [Line Items]
Total	200,000,000
Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
Total	6,384,000,000
2015	3,137,000,000
2016	99,000,000
2017	25,000,000
2018	20,000,000
2019	20,000,000
2020 and beyond	3,083,000,000
Exelon Generation Co L L C [Member] | Financial Standby Letter of Credit [Member]
Guarantor Obligations [Line Items]
Total	1,187,000,000	[15]
2015	1,106,000,000	[15]
2016	76,000,000	[15]
2017	5,000,000	[15]
2018	0	[15]
2019	0	[15]
2020 and beyond	0	[15]
Exelon Generation Co L L C [Member] | Surety Bond [Member]
Guarantor Obligations [Line Items]
Total	481,000,000
2015	468,000,000
2016	3,000,000
2017	0
2018	0
2019	0
2020 and beyond	10,000,000
Exelon Generation Co L L C [Member] | Performance Guarantee [Member]
Guarantor Obligations [Line Items]
Total	458,000,000	[16]
2015	319,000,000	[16]
2016	20,000,000	[16]
2017	20,000,000	[16]
2018	20,000,000	[16]
2019	20,000,000	[16]
2020 and beyond	59,000,000	[16]
Exelon Generation Co L L C [Member] | Energy Contract Guarantee [Member]
Guarantor Obligations [Line Items]
Total	1,244,000,000	[17]
2015	1,244,000,000	[17]
2016	0	[17]
2017	0	[17]
2018	0	[17]
2019	0	[17]
2020 and beyond	0	[17]
Estimated total assumed for commercial transaction obligations	1,200,000,000
Exelon Generation Co L L C [Member] | Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Total	3,014,000,000	[18]
2015	0	[18]
2016	0	[18]
2017	0	[18]
2018	0	[18]
2019	0	[18]
2020 and beyond	3,014,000,000	[18]
Exelon Generation Co L L C [Member] | Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]
Guarantor Obligations [Line Items]
Estimated net exposure for commercial transaction obligations	$400,000,000
Commonwealth Edison Three [Member] | Commonwealth Edison Co [Member]
Guarantor Obligations [Line Items]
Percentage ownership of common stock	100.00%
PECO Trust III and IV [Member] | PECO Energy Co [Member]
Guarantor Obligations [Line Items]
Percentage ownership of common stock	100.00%
[1]	Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[2]	Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[3]	Performance guarantees—Guarantees issued to ensure performance under specific contracts. Additionally includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust Preferred Securities of BGE Capital Trust II.
[4]	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $3.2 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Exelon’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.6 billion at December 31, 2014, which represents the total amount Exelon could be required to fund based on December 31, 2014 market prices.
[5]	Lease guarantees—Guarantees issued to ensure payments on building leases.
[6]	Nuclear insurance premiums—Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.
[7]	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 19 - Common Stock for further details of the equity securities offering.
[8]	Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[9]	Surety bond—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
[10]	Performance guarantee—Reflects full and unconditional guarantee of Trust Preferred Securities of BGE Capital Trust which is an unconsolidated VIE of BGE.
[11]	Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[12]	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
[13]	Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
[14]	Performance guarantees—Reflects full and unconditional guarantee of Trust Preferred Securities of ComEd Financing III which is a 100% owned finance subsidiary of ComEd.
[15]	Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
[16]	Performance guarantees—Guarantees issued to ensure performance under specific contracts.
[17]	Energy marketing contract guarantees—Guarantees issued to ensure performance under energy commodity contracts. Amount includes approximately $1.2 billion of guarantees previously issued by Constellation on behalf of its Generation and NewEnergy business to allow it the flexibility needed to conduct business with counterparties without having to post other forms of collateral. The majority of these guarantees contain evergreen provisions that require the guarantee to remain in effect until cancelled. Generation’s estimated net exposure for obligations under commercial transactions covered by these guarantees is approximately $0.4 billion at December 31, 2014, which represents the total amount Generation could be required to fund based on December 31, 2014 market prices.
[18]	Nuclear insurance premiums — Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generation’s nuclear insurance premiums.

Commitments_and_Contingencies_9

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) (Equity Method Investments [Member], Exelon Generation Co L L C [Member], USD $)	Dec. 31, 2014
In Millions, unless otherwise specified
Equity Method Investments [Member] | Exelon Generation Co L L C [Member]
Guarantor Obligations [Line Items]
2015	$98
2016	38
2017	20
2018	11
Total	$167

Recovered_Sheet4

Commitments and Contingencies - Schedule of Minimum Future Operating Lease Payments (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014
Operating Leases Future Minimum Payments Due [Line Items]
2015	$99
2016	102
2017	102
2018	86
2019	70
Remaining years	699
Total minimum future lease payments	1,158	[1]
Exelon Generation Co L L C [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2015	51	[2]
2016	57	[2]
2017	63	[2]
2018	57	[2]
2019	43	[2]
Remaining years	628	[2]
Total minimum future lease payments	899	[1],[2]
Exelon Generation Co L L C [Member] | Baltimore Headquarters [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2015	0
2016	5
2017	12
2018	13
2019	13
Remaining years	285
Commonwealth Edison Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2015	14	[3]
2016	13	[3]
2017	8	[3]
2018	4	[3]
2019	4	[3]
Remaining years	2	[3]
Total minimum future lease payments	45	[3]
Commonwealth Edison Co [Member] | Real Estate Leases and Railroad Licenses [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total minimum future lease payments	2
PECO Energy Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2015	3	[3]
2016	3	[3]
2017	3	[3]
2018	3	[3]
2019	2	[3]
Remaining years	0	[3]
Total minimum future lease payments	14	[3]
PECO Energy Co [Member] | Real Estate Leases and Railroad Licenses [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total minimum future lease payments	3
Baltimore Gas and Electric Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
2015	13	[3],[4]
2016	11	[3],[4]
2017	10	[3],[4]
2018	9	[3],[4]
2019	7	[3],[4]
Remaining years	27	[3],[4]
Total minimum future lease payments	77	[3],[4]
Baltimore Gas and Electric Company [Member] | Baltimore Headquarters [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total minimum future lease payments	328
Term of lease	20 years
Baltimore Gas and Electric Company [Member] | Real Estate Leases and Railroad Licenses [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Total minimum future lease payments	$2
[1]	Excludes Generation’s PPAs and tolling arrangements that are accounted for as contingent operating lease payments, since these expected cash outflows are already disclosed in the Net Capacity Purchases table under the Energy Commitment.
[2]	The Generation column above now includes minimum future lease payments associated with a 20-year lease agreement for the Baltimore headquarters that became effective during the second quarter of 2014. Generation’s total commitments under the lease agreement are $0 in 2015, and $5 million, $12 million, $13 million, $13 million, and $285 million related to years 2016, 2017, 2018, 2019, and thereafter, respectively, for a total of $328 million .
[3]	Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO and BGE have excluded these payments from the remaining years, as such amounts would not be meaningful. ComEd’s, PECO’s, and BGE’s annual obligation for these arrangements, included in each of the years 2015—2019, was $2 million, $3 million, and $2 million respectively.
[4]	Includes all future lease payments on a 99 year real estate lease that expires in 2106.

Recovered_Sheet5

Commitments and Contingencies - Schedule of Future Rental Expense under Operating Leases (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating Leases Future Minimum Payments Due [Line Items]
Lease and rental expense	$865		$806		$930
Exelon Generation Co L L C [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Lease and rental expense	806	[1]	744	[1]	872	[1]
Long Term Contract For Purchase Of Electric Power Capacity	755		694		801
Commonwealth Edison Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Lease and rental expense	15		15		18
PECO Energy Co [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Lease and rental expense	14		21		27
Baltimore Gas and Electric Company [Member]
Operating Leases Future Minimum Payments Due [Line Items]
Lease and rental expense	$12		$11		$12
[1]	Includes Generation’s PPAs and other capacity contracts that are accounted for as operating leases and are reflected as net capacity purchases in the Energy Commitments table above. These agreements are considered contingent operating lease payments and are not included in the minimum future operating lease payments table above. Payments made under Generation’s PPAs and other capacity contracts totaled $755 million, $694 million and $801 million during 2014, 2013 and 2012, respectively.

Recovered_Sheet6

Commitments and Contingencies - Schedule of Environmental Liabilities (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	$347	$338
Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	277	273
Exelon Generation Co L L C [Member] | Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	63	56
Exelon Generation Co L L C [Member] | Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	0	0
Commonwealth Edison Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	238	234
Commonwealth Edison Co [Member] | Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	235	229
PECO Energy Co [Member] | Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	45	47
PECO Energy Co [Member] | Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	42	44
Baltimore Gas and Electric Company [Member] | Total Accrual For Environmental Loss Contingencies [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	1	1
Baltimore Gas and Electric Company [Member] | Accrual For MGP Investigation And Remediation [Member]
Accrual For Environmental Loss Contingencies [Line Items]
Accrued environmental liabilities	$0	$0

Supplemental_Financial_Informa2

Supplemental Financial Information - Summary of Taxes other than Income (Details) (USD $)	10 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Supplemental Financial Information Tables [Line Items]
Utility Taxes			$456	[1]	$449	[1]	$463	[1]
Property			396		302		227
Payroll			200		159		131
Other			102		185		198
Total taxes other than income			1,154		1,095		1,019
Exelon Generation Co L L C [Member]
Supplemental Financial Information Tables [Line Items]
Utility Taxes			89	[1]	79	[1]	82	[1]
Property			240		205		189
Payroll			118		89		78
Other			18		16		20
Total taxes other than income			465		389		369
Commonwealth Edison Co [Member]
Supplemental Financial Information Tables [Line Items]
Utility Taxes			238	[1]	241	[1]	239	[1]
Property			25		24		22
Payroll			28		27		26
Other			2		7		8
Total taxes other than income			293		299		295
PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Utility Taxes			128	[1]	129	[1]	141	[1]
Property			15		14		13
Payroll			14		13		12
Other			2		2		-4
Total taxes other than income			159		158		162
Baltimore Gas and Electric Company [Member]
Supplemental Financial Information Tables [Line Items]
Utility Taxes	59	[1]	86	[1]	82	[1]	75	[1]
Property			114		112		111
Payroll			18		15		18
Other			3		4		4
Total taxes other than income			$221		$213		$208
[1]	Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

Supplemental_Financial_Informa3

Supplemental Financial Information - Summary of Other Income (Expense) (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Supplemental Financial Information Tables [Line Items]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	$216	[1]	$256	[1]	$189	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	159	[1]	77	[1]	102	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	180	[1]	406	[1]	386	[1]
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	134	[1]	146	[1]	105	[1]
Net unrealized income (losses) on pledged assets	29	[1]	7	[1]	73	[1]
Regulatory offset to decommissioning trust fund-related activities	-358	[1],[2]	-546	[1],[2]	-530	[1],[2]
Total decommissioning-related activities	360		346		325
Investment income	1		8		20
Long-term lease income	24		28		29
Interest income related to uncertain income tax positions	40		24		15
AFUDC—Equity	21		22		17
Credit facility termination fees					-85
Other	9		32		32
Other, net	455		460		353
Exelon Generation Co L L C [Member]
Supplemental Financial Information Tables [Line Items]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	216	[1]	256	[1]	189	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	159	[1]	77	[1]	102	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	180	[1]	406	[1]	386	[1]
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	134	[1]	146	[1]	105	[1]
Net unrealized income (losses) on pledged assets	29	[1]	7	[1]	73	[1]
Regulatory offset to decommissioning trust fund-related activities	-358	[1],[2]	-546	[1],[2]	-530	[1],[2]
Total decommissioning-related activities	360		346		325
Investment income	1		-1		3
Long-term lease income	0		0		0
Interest income related to uncertain income tax positions	54		4		2
AFUDC—Equity	0		0		0
Credit facility termination fees					-85
Other	-9		6		1
Other, net	406		355		246
Commonwealth Edison Co [Member]
Supplemental Financial Information Tables [Line Items]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on pledged assets	0	[1]	0	[1]	0	[1]
Regulatory offset to decommissioning trust fund-related activities	0	[1],[2]	0	[1],[2]	0	[1],[2]
Total decommissioning-related activities	0		0		0
Investment income	0		0		1
Long-term lease income	0		0		0
Interest income related to uncertain income tax positions	0		0		20
AFUDC—Equity	3		11		6
Credit facility termination fees					0
Other	14		15		12
Other, net	17		26		39
Other Income	17
PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on pledged assets	0	[1]	0	[1]	0	[1]
Regulatory offset to decommissioning trust fund-related activities	0	[1],[2]	0	[1],[2]	0	[1],[2]
Total decommissioning-related activities	0		0		0
Investment income	-1		-1		2
Long-term lease income	0		0		0
Interest income related to uncertain income tax positions	0		0		0
AFUDC—Equity	6		4		4
Credit facility termination fees					0
Other	2		3		2
Other, net	7		6		8
Baltimore Gas and Electric Company [Member]
Supplemental Financial Information Tables [Line Items]
Net realized income on decommissioning trust funds - Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	0	[1]	0	[1]	0	[1]
Net unrealized income (losses) on pledged assets	0	[1]	0	[1]	0	[1]
Regulatory offset to decommissioning trust fund-related activities	0	[1],[2]	0	[1],[2]	0	[1],[2]
Total decommissioning-related activities	0		0		0
Investment income	7	[3]	9	[3]	11	[3]
Long-term lease income	0		0		0
Interest income related to uncertain income tax positions	0		0		0
AFUDC—Equity	12		7		10
Credit facility termination fees					0
Other	-1		1		2
Other, net	$18		$17		$23
[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 for additional information regarding the accounting for nuclear decommissioning.
[3]	Relates to the cash return on BGE’s rate stabilization deferral. See Note 3 — Regulatory Matters for additional information regarding the rate stabilization deferral.

Supplemental_Financial_Informa4

Supplemental Financial Information - Summary of Depreciation, Amortization, Accretion and Depletion (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Supplemental Financial Information Tables [Line Items]
Property, plant and equipment	$2,080		$1,893		$1,712
Regulatory assets	191		212		129
Amortization of intangible assets, net	44		48		40
Amortization of Intangible Assets	179	[1]	478	[1]	1,150	[1]
Nuclear fuel	1,073	[2]	921	[2]	848	[2]
ARO accretion	345	[3]	275	[3]	240	[3]
Total depreciation, amortization, accretion and depletion	3,868		3,779		4,079
Exelon Generation Co L L C [Member]
Supplemental Financial Information Tables [Line Items]
Property, plant and equipment	922		813		733
Regulatory assets	0		0		0
Amortization of intangible assets, net	44		43		35
Amortization of Intangible Assets	179	[1]	550	[1]	1,145	[1]
Nuclear fuel	1,073	[2]	921	[2]	848	[2]
ARO accretion	345	[3]	275	[3]	240	[3]
Total depreciation, amortization, accretion and depletion	2,519		2,559		2,966
Commonwealth Edison Company [Member]
Supplemental Financial Information Tables [Line Items]
Energy Contract Amortization	0	[4]
Commonwealth Edison Co [Member]
Supplemental Financial Information Tables [Line Items]
Property, plant and equipment	588		545		525
Regulatory assets	99		119		80
Amortization of intangible assets, net	0		5		5
Amortization of Intangible Assets	7		7		7
Energy Contract Amortization			0	[4]	0	[4]
Nuclear fuel	0	[2]	0	[2]	0	[2]
ARO accretion	0	[3]	0	[3]	0	[3]
Total depreciation, amortization, accretion and depletion	687		669		610
PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Property, plant and equipment	227		219		207
Regulatory assets	9		9		10
Amortization of intangible assets, net	0		0		0
Amortization of Intangible Assets	0	[4]	0	[4]	0	[4]
Nuclear fuel	0	[2]	0	[2]	0	[2]
ARO accretion	0	[3]	0	[3]	0	[3]
Total depreciation, amortization, accretion and depletion	236		228		217
Baltimore Gas and Electric Company [Member]
Supplemental Financial Information Tables [Line Items]
Property, plant and equipment	288		264		245
Regulatory assets	83		84		53
Amortization of intangible assets, net	0		0		0
Amortization of Intangible Assets	0	[4]	0	[4]	0	[4]
Nuclear fuel	0	[2]	0	[2]	0	[2]
ARO accretion	0	[3]	0	[3]	0	[3]
Total depreciation, amortization, accretion and depletion	371		348		298
Unamortized Energy Contracts [Member]
Supplemental Financial Information Tables [Line Items]
Amortization of Intangible Assets	135	[5],[6]	430	[5],[6]	1,110	[5],[6]
Unamortized Energy Contracts [Member] | Exelon Generation Co L L C [Member]
Supplemental Financial Information Tables [Line Items]
Amortization of Intangible Assets	$135	[5],[6]	$507	[5],[6]	$1,110	[4]
[1]	At Exelon, amortization of unamortized energy contracts totaling $135 million, $430 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Exelon’s Consolidated Statement of Operations and Comprehensive Income. At Generation, amortization of unamortized energy contracts totaling $135 million, $507 million and $1,110 million for the years ended December 31, 2014, 2013 and 2012, respectively, was recorded in Purchase power and fuel expense or Operating revenues within Generation’s Consolidated Statement 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]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[5]	Includes unamortized energy contract assets and liabilities on Exelon's and Generation's Consolidated Balance Sheets. Excludes $26 million of other miscellaneous unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $4 million, $3 million, $0 million, $2 million and $2 million for 2015, 2016, 2017, 2018 and 2019, respectively.
[6]	In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement, ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized ratably over the remaining term of the franchise agreement, which ends in 2020.

Supplemental_Financial_Informa5

Supplemental Financial Information - Supplemental Cash Flow Information (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Supplemental Cash Flow Information [Line Items]
Interest (net of amount capitalized)	$940		$866		$761
Income taxes (net of refunds)	314		112		-171
Pension and non-pension postretirement benefit costs	560		825		820
Income (Loss) from Equity Method Investments	20		-10		91
Provision for uncollectible accounts	156		101		164
Provision for excess and obsolete inventory	5		9		6
Stock-based compensation costs	91		120		94
Other decommissioning related-activity	-132	[1]	-169	[1]	-145	[1]
Energy-related options	122	[2]	104	[2]	160	[2]
Amortization of regulatory asset related to debt costs	11		12		18
Amortization of rate stabilization deferral	65		66		57
Amortization of debt fair value adjustment	-23		-34		-34
Merger-related commitments	44				141	[3]
Discrete impacts from EIMA	53	[4]	-271	[4]	-96	[5]
Amortization of debt costs	53		18		19
Lower of cost or market inventory adjustment	29
Other	-2		-53		-30
Total other non-cash operating activities	1,054		718		1,364
Under/over-recovered energy and transmission costs	47		12		71
Other regulatory assets and liabilities	-167		-64		-404
Increase (Decrease) in Deposits	-241	[6]
Other current assets	7		-165		213
Other noncurrent assets and liabilities	-204		322		-248
Total changes in other assets and liabilities	-558		102		-368
Change in ARC	72		-128		781
Change in capital expenditures not paid	220		-38		160
Consolidated VIE dividend to noncontrolling	421		63
Fair value of net assets recorded upon CENG consolidation (f)	-3,400	[7]
Issuance of equity units	131	[8]
Other Cost and Expense, Operating	8,568		7,270		7,961
Antelope Valle [Member]
Supplemental Cash Flow Information [Line Items]
Change in capital expenditures not paid	170		55		127
Indemnification Agreement [Member]
Supplemental Cash Flow Information [Line Items]
Energy-related options	70	[9]
Indemnification of like-kind exchange position	0	[10]	0	[11]
Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Interest (net of amount capitalized)	322		291		286
Income taxes (net of refunds)	227		-18		175
Pension and non-pension postretirement benefit costs	249		345		341
Income (Loss) from Equity Method Investments	20		-10		91
Provision for uncollectible accounts	14		10		22
Provision for excess and obsolete inventory	5		9		6
Stock-based compensation costs	0		0		0
Other decommissioning related-activity	-132	[1]	-169	[1]	-145	[1]
Energy-related options	122	[2]	104	[2]	160	[2]
Amortization of regulatory asset related to debt costs	0		0		0
Amortization of rate stabilization deferral	0		0		0
Amortization of debt fair value adjustment	-23		-34		-34
Merger-related commitments	44				32	[3]
Discrete impacts from EIMA	0	[4]	0	[4]	0	[5]
Amortization of debt costs	12		10		11
Lower of cost or market inventory adjustment	29
Other	6		5		0
Total other non-cash operating activities	346		270		518
Under/over-recovered energy and transmission costs	0		0		0
Other regulatory assets and liabilities	0		0		0
Increase (Decrease) in Deposits	-241	[6]
Other current assets	81		-151		-30
Other noncurrent assets and liabilities	-89		15		-98
Total changes in other assets and liabilities	-249		-136		-128
Change in ARC	72		-128		781
Change in capital expenditures not paid	-61	[12]	-107	[13]	103	[14]
Consolidated VIE dividend to noncontrolling	-1,548		63
Fair value of net assets recorded upon CENG consolidation (f)	-3,400	[7]
Issuance of equity units	0	[8]
Other Cost and Expense, Operating	4,943		3,960		4,398
Exelon Generation Co L L C [Member] | Indemnification Agreement [Member]
Supplemental Cash Flow Information [Line Items]
Energy-related options	70	[9]
Indemnification of like-kind exchange position	0	[10]	0	[11]
Commonwealth Edison Co [Member]
Supplemental Cash Flow Information [Line Items]
Interest (net of amount capitalized)	292		283		288
Income taxes (net of refunds)	-6		33		-42
Pension and non-pension postretirement benefit costs	162		308		282
Income (Loss) from Equity Method Investments	0		0
Provision for uncollectible accounts	26		-15		42
Provision for excess and obsolete inventory	0		0		1
Stock-based compensation costs	0		0		0
Other decommissioning related-activity	0	[1]	0	[1]	0	[1]
Energy-related options	0	[2]	0	[2]	0	[2]
Amortization of regulatory asset related to debt costs	8		9		13
Amortization of rate stabilization deferral	0		0		0
Amortization of debt fair value adjustment	0		0		0
Merger-related commitments	0				0	[3]
Discrete impacts from EIMA	53	[4]	-271	[4]	-96	[5]
Amortization of debt costs	4		1		5
Lower of cost or market inventory adjustment	0
Other	2		-4		5
Total other non-cash operating activities	255		28		252
Under/over-recovered energy and transmission costs	36		-35		28
Other regulatory assets and liabilities	-13		-43		-68
Increase (Decrease) in Deposits	0	[6]
Other current assets	-10		51		33
Other noncurrent assets and liabilities	32		268	[15]	-95
Total changes in other assets and liabilities	45		241		-102
Change in ARC	0		0		2
Change in capital expenditures not paid	78		-8		15
Fair value of net assets recorded upon CENG consolidation (f)	0	[7]
Issuance of equity units	0	[8]
Indemnification of like-kind exchange position	273		0		0
Other Cost and Expense, Operating	1,263		1,211		1,182
Commonwealth Edison Co [Member] | Indemnification Agreement [Member]
Supplemental Cash Flow Information [Line Items]
Energy-related options	0	[9]
Indemnification of like-kind exchange position	5	[10]	176	[11]
PECO Energy Co [Member]
Supplemental Cash Flow Information [Line Items]
Interest (net of amount capitalized)	94		95		113
Income taxes (net of refunds)	85		70		-64
Pension and non-pension postretirement benefit costs	36		43		50
Income (Loss) from Equity Method Investments	0		0		0
Provision for uncollectible accounts	52		61		60
Provision for excess and obsolete inventory	0		0		0
Stock-based compensation costs	0		0		0
Other decommissioning related-activity	0	[1]	0	[1]	0	[1]
Energy-related options	0	[2]	0	[2]	0	[2]
Amortization of regulatory asset related to debt costs	3		3		3
Amortization of rate stabilization deferral	0		0		0
Amortization of debt fair value adjustment	0		0		0
Merger-related commitments	0				0	[3]
Discrete impacts from EIMA	0	[4]	0	[4]	0	[5]
Amortization of debt costs	2		2		3
Lower of cost or market inventory adjustment	0
Other	-1		-1		9
Total other non-cash operating activities	92		108		125
Under/over-recovered energy and transmission costs	0		9		20
Other regulatory assets and liabilities	-16		-16		18
Increase (Decrease) in Deposits	0	[6]
Other current assets	-2		13		-12
Other noncurrent assets and liabilities	1		-12		-10
Total changes in other assets and liabilities	-17		-6		16
Change in ARC	0		0		0
Change in capital expenditures not paid	0		13		26
Fair value of net assets recorded upon CENG consolidation (f)	0	[7]
Issuance of equity units	0	[8]
Indemnification of like-kind exchange position	24		27		9
Other Cost and Expense, Operating	767		647		698
PECO Energy Co [Member] | Indemnification Agreement [Member]
Supplemental Cash Flow Information [Line Items]
Energy-related options	0	[9]
Indemnification of like-kind exchange position	0	[10]	0	[11]
Baltimore Gas and Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Interest (net of amount capitalized)	111		130		136
Income taxes (net of refunds)	-21		42		-112
Pension and non-pension postretirement benefit costs	64		56		57
Income (Loss) from Equity Method Investments	0		0		0
Provision for uncollectible accounts	64		44		44
Provision for excess and obsolete inventory	0		0		0
Stock-based compensation costs	0		0		0
Other decommissioning related-activity	0	[1]	0	[1]	0	[1]
Energy-related options	0	[2]	0	[2]	0	[2]
Amortization of regulatory asset related to debt costs	0		0		2
Amortization of rate stabilization deferral	65		66		67
Amortization of debt fair value adjustment	0		0		0
Merger-related commitments	0				27	[3]
Discrete impacts from EIMA	0	[4]	0	[4]	0	[5]
Amortization of debt costs	2		2		2
Lower of cost or market inventory adjustment	0
Other	-15		-15		-6
Total other non-cash operating activities	180		153		193
Under/over-recovered energy and transmission costs	11		38		26
Other regulatory assets and liabilities	-121		-71		-112
Increase (Decrease) in Deposits	0	[6]
Other current assets	-44		-8		-7
Other noncurrent assets and liabilities	-9		-23		8
Total changes in other assets and liabilities	-163		-64		-85
Change in ARC	0		4		0
Change in capital expenditures not paid	25		-48		-4
Fair value of net assets recorded upon CENG consolidation (f)	0	[7]
Issuance of equity units	0	[8]
Indemnification of like-kind exchange position	0		0		66
Other Cost and Expense, Operating	614		551		622
Baltimore Gas and Electric Company [Member] | Indemnification Agreement [Member]
Supplemental Cash Flow Information [Line Items]
Energy-related options	0	[9]
Indemnification of like-kind exchange position	0	[10]	0	[11]
Exelon Consolidations [Member]
Supplemental Cash Flow Information [Line Items]
Income (Loss) from Equity Method Investments	22
Total changes in other assets and liabilities			105
Severance [Member]
Supplemental Cash Flow Information [Line Items]
Other Cost and Expense, Operating					99
Severance [Member] | Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Other Cost and Expense, Operating					34
Severance [Member] | Commonwealth Edison Co [Member]
Supplemental Cash Flow Information [Line Items]
Other Cost and Expense, Operating					0
Severance [Member] | PECO Energy Co [Member]
Supplemental Cash Flow Information [Line Items]
Other Cost and Expense, Operating					0
Severance [Member] | Baltimore Gas and Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Other Cost and Expense, Operating					0
Constellation Energy Group Acquisition [Member]
Supplemental Cash Flow Information [Line Items]
Consolidated VIE dividend to noncontrolling			63		7,365
Constellation Energy Group Acquisition [Member] | Exelon Generation Co L L C [Member]
Supplemental Cash Flow Information [Line Items]
Consolidated VIE dividend to noncontrolling			63		5,264
Constellation Energy Group Acquisition [Member] | Commonwealth Edison Co [Member]
Supplemental Cash Flow Information [Line Items]
Consolidated VIE dividend to noncontrolling			0		0
Constellation Energy Group Acquisition [Member] | PECO Energy Co [Member]
Supplemental Cash Flow Information [Line Items]
Consolidated VIE dividend to noncontrolling			0		0
Constellation Energy Group Acquisition [Member] | Baltimore Gas and Electric Company [Member]
Supplemental Cash Flow Information [Line Items]
Consolidated VIE dividend to noncontrolling			$0		$0
[1]	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 for additional information regarding the accounting for nuclear decommissioning.
[2]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[3]	Relates to the integration costs to achieve distribution synergies related to the Constellation merger transaction. See Note 4 — Mergers, Acquisitions, and Dispositions for more information on Constellation merger-related commitments.
[4]	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters for more information.
[5]	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through pre-established performance-based formula rate tariff. See Note 3 — Regulatory Matters.
[6]	Relates primarily to cash deposits made to ISO's/RTO's.
[7]	See Note 5 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
[8]	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 19 — Common Stock for additional information.
[9]	Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation on June 30, 2014 and September 24, 2014. Generation is required to make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.
[10]	See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.
[11]	See Note 14 — Income Taxes for discussion of the like-kind exchanged tax position.
[12]	Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.
[13]	Includes $55 million of changes in capital expenditures not paid between December 31, 2013 and 2012 related to Antelope Valley.
[14]	Includes $127 million of changes in capital expenditures not paid between December 31, 2012 and 2011 related to Antelope Valley.
[15]	Relates primarily to interest payable related to like-kind exchange tax position. See Note 14 — Income Taxes for discussion of the like-kind exchange tax position.

Supplemental_Financial_Informa6

Supplemental Financial Information - Narrative (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Supplemental Financial Information Tables [Line Items]
Amount included in capital expenditures		$74
Smart Grid Grant Reimbursements		95
PECO Energy Co [Member]
Supplemental Financial Information Tables [Line Items]
Amount included in capital expenditures	2	27
Smart Grid Grant Reimbursements	5	37
Baltimore Gas and Electric Company [Member]
Supplemental Financial Information Tables [Line Items]
Amount included in capital expenditures		47
Smart Grid Grant Reimbursements		$58

Supplemental_Financial_Informa7

Supplemental Financial Information - Supplemental Balance Sheet Information (Details) (USD $)	Dec. 31, 2014		Mar. 31, 2014	Dec. 31, 2013
In Millions, unless otherwise specified
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	$0			$1,925
Total equity method investments	50			2,295
Net investment in leases	361			698
Total investments	544			3,112
Compensation-related accruals	832			683
Taxes accrued	305		285	315
Interest accrued	240			234
Severance accrued	49			66
Other accrued expenses	113			335
Total accrued expenses	1,539			1,633
Antelope Valle [Member]
Supplemental Balance Sheet Information [Line Items]
Other accrued expenses	19			228
Financing Trusts [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	22	[1]		22	[1]
Bloom Energy [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	13
Net Power [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	9
Other Equity Method Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	1			2
Sunnyside [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	5
Keystone Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				32
Conemaugh Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				21
CENG [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				1,925
Safe Harbor [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				285
Malacha [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				8
Trust for Benefit of Employees [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	85	[2]		90	[2]
Other Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	42	[3]		22	[3]
Exelon Generation Co L L C [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0			1,925
Total equity method investments	28			2,273
Net investment in leases	7			7
Total investments	104			2,325
Compensation-related accruals	447			337
Taxes accrued	248			212
Interest accrued	66			72
Severance accrued	33			31
Other accrued expenses	92			324
Total accrued expenses	886			976
Exelon Generation Co L L C [Member] | Financing Trusts [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0	[1]		0	[1]
Exelon Generation Co L L C [Member] | Bloom Energy [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	13
Exelon Generation Co L L C [Member] | Net Power [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	9
Exelon Generation Co L L C [Member] | Other Equity Method Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	1			2
Exelon Generation Co L L C [Member] | Sunnyside [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	5
Exelon Generation Co L L C [Member] | Keystone Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				32
Exelon Generation Co L L C [Member] | Conemaugh Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				21
Exelon Generation Co L L C [Member] | CENG [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				1,925
Exelon Generation Co L L C [Member] | Safe Harbor [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				285
Exelon Generation Co L L C [Member] | Malacha [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				8
Exelon Generation Co L L C [Member] | Trust for Benefit of Employees [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	27	[2]		23	[2]
Exelon Generation Co L L C [Member] | Other Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	42	[3]		22	[3]
Commonwealth Edison Co [Member]
Supplemental Balance Sheet Information [Line Items]
Total equity method investments	6			6
Net investment in leases	0			0
Total investments	6			11
Compensation-related accruals	153			135
Taxes accrued	59			62
Interest accrued	102			95
Severance accrued	2			3
Other accrued expenses	15			12
Total accrued expenses	331			307
Commonwealth Edison Co [Member] | Financing Trusts [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	6	[1]		6	[1]
Commonwealth Edison Co [Member] | Bloom Energy [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
Commonwealth Edison Co [Member] | Net Power [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
Commonwealth Edison Co [Member] | Other Equity Method Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0			0
Commonwealth Edison Co [Member] | Keystone Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Commonwealth Edison Co [Member] | Conemaugh Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Commonwealth Edison Co [Member] | CENG [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Commonwealth Edison Co [Member] | Safe Harbor [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Commonwealth Edison Co [Member] | Malacha [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Commonwealth Edison Co [Member] | Trust for Benefit of Employees [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	0	[2]		5	[2]
Commonwealth Edison Co [Member] | Other Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	0	[3]		0	[3]
PECO Energy Co [Member]
Supplemental Balance Sheet Information [Line Items]
Total equity method investments	8			8
Net investment in leases	0			0
Total investments	31			31
Compensation-related accruals	50			47
Taxes accrued	3			24
Interest accrued	33			32
Severance accrued	1			1
Other accrued expenses	4			2
Total accrued expenses	91			106
PECO Energy Co [Member] | Financing Trusts [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	8	[1]		8	[1]
PECO Energy Co [Member] | Bloom Energy [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
PECO Energy Co [Member] | Net Power [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
PECO Energy Co [Member] | Other Equity Method Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0			0
PECO Energy Co [Member] | Sunnyside [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
PECO Energy Co [Member] | Keystone Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
PECO Energy Co [Member] | Conemaugh Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
PECO Energy Co [Member] | CENG [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
PECO Energy Co [Member] | Safe Harbor [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
PECO Energy Co [Member] | Malacha [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
PECO Energy Co [Member] | Trust for Benefit of Employees [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	23	[2]		23	[2]
PECO Energy Co [Member] | Other Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	0	[3]		0	[3]
Baltimore Gas and Electric Company [Member]
Supplemental Balance Sheet Information [Line Items]
Total equity method investments	8			8
Net investment in leases	0			0
Total investments	12			13
Compensation-related accruals	58			55
Taxes accrued	42			16
Interest accrued	29			29
Severance accrued	2			4
Other accrued expenses	0			7
Total accrued expenses	131			111
Baltimore Gas and Electric Company [Member] | Financing Trusts [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	8	[1]		8	[1]
Baltimore Gas and Electric Company [Member] | Bloom Energy [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
Baltimore Gas and Electric Company [Member] | Net Power [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
Baltimore Gas and Electric Company [Member] | Other Equity Method Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0			0
Baltimore Gas and Electric Company [Member] | Sunnyside [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments	0
Baltimore Gas and Electric Company [Member] | Keystone Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Baltimore Gas and Electric Company [Member] | Conemaugh Fuels [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Baltimore Gas and Electric Company [Member] | CENG [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Baltimore Gas and Electric Company [Member] | Safe Harbor [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Baltimore Gas and Electric Company [Member] | Malacha [Member]
Supplemental Balance Sheet Information [Line Items]
Equity Method Investments				0
Baltimore Gas and Electric Company [Member] | Trust for Benefit of Employees [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	4	[2]		5	[2]
Baltimore Gas and Electric Company [Member] | Other Investments [Member]
Supplemental Balance Sheet Information [Line Items]
Employee benefit trusts and investments	0	[3]		0	[3]
Exelon Consolidations [Member]
Supplemental Balance Sheet Information [Line Items]
Net investment in leases	$367			$705
[1]	Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the Consolidated Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.
[2]	The Registrants’ investments in these marketable securities are recorded at fair market value.
[3]	Includes cost method and available-for-sale investments.

Segment_Information_Narrative_

Segment Information - Narrative (Details)	12 Months Ended
	Dec. 31, 2014
	Reportable_segment
Segment Reporting Information [Line Items]
Number of reportable segments	9
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	6

Segment_Information_Analysis_a

Segment Information - Analysis and Reconciliation to Consolidated Financial Statements (Details) (USD $)	3 Months Ended											10 Months Ended		12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013		Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013		Dec. 31, 2012		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Revenues	$7,255		$6,912	$6,024	$7,237	$6,163		$6,502	$6,141	$6,082				$27,429	[1]	$24,888	[1]	$23,489	[1]
Operating revenues from affiliates														23		70		48
Depreciation and amortization														2,314		2,153		1,881
Operating Expenses														25,039	[1]	21,242	[1]	21,018	[1]
Equity in earnings (losses) of unconsolidated affiliates														-20		10		-91
Interest expense, net														1,065		1,356		928
Income (loss) from continuing operations before income taxes														2,486		2,773		1,798
Income taxes														666		1,044		627
Net income	18	[2]	993	522	90	495		738	490	-4	[3]			1,820		1,729		1,171
Capital expenditures														6,077		5,395		5,789
Assets	86,814	[4]				79,924	[4]							86,814	[4]	79,924	[4]
Utility taxes														456	[5]	449	[5]	463	[5]
PECO Energy Co Affiliate [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														1	[6]	10	[6]	6	[6]
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues														4,475		4,270		4,848
Operating Segments [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Revenues														17,393	[1],[7]	15,630	[1],[7]	14,437	[1],[7]
Depreciation and amortization														967	[7]	856	[7]	768	[7]
Operating Expenses														16,923	[1],[7]	13,976	[1],[7]	13,226	[1],[7]
Equity in earnings (losses) of unconsolidated affiliates														-20	[7]	10	[7]	-91	[7]
Interest expense, net														356	[7]	357	[7]	301	[7]
Income (loss) from continuing operations before income taxes														1,226	[7]	1,675	[7]	1,058	[7]
Income taxes														207	[7]	615	[7]	500	[7]
Net income														1,019	[7]	1,060	[7]	558	[7]
Capital expenditures														3,012	[7]	2,752	[7]	3,554	[7]
Assets	45,348	[7]				41,232	[7]							45,348	[7]	41,232	[7]
Operating Segments [Member] | Commonwealth Edison Co [Member]
Segment Reporting Information [Line Items]
Revenues														4,564	[1]	4,464	[1]	5,443	[1]
Depreciation and amortization														687		669		610
Operating Expenses														3,586	[1]	3,510	[1]	4,557	[1]
Equity in earnings (losses) of unconsolidated affiliates														0		0		0
Interest expense, net														321		579		307
Income (loss) from continuing operations before income taxes														676		401		618
Income taxes														268		152		239
Net income														408		249		379
Capital expenditures														1,689		1,433		1,246
Assets	25,392					24,118								25,392		24,118
Operating Segments [Member] | PECO Energy Co [Member]
Segment Reporting Information [Line Items]
Revenues														3,094	[1]	3,100	[1]	3,186	[1]
Depreciation and amortization														236		228		217
Operating Expenses														2,522	[1]	2,434	[1]	2,563	[1]
Equity in earnings (losses) of unconsolidated affiliates														0		0		0
Interest expense, net														113		115		123
Income (loss) from continuing operations before income taxes														466		557		508
Income taxes														114		162		127
Net income														352		395		381
Capital expenditures														661		537		422
Assets	9,943					9,617								9,943		9,617
Operating Segments [Member] | Baltimore Gas and Electric Company [Member]
Segment Reporting Information [Line Items]
Revenues														3,165	[1],[8]	3,065	[1],[8]	2,091	[1],[8]
Depreciation and amortization														371	[8]	348	[8]	238	[8]
Operating Expenses														2,726	[1],[8]	2,616	[1],[8]	2,053	[1],[8]
Equity in earnings (losses) of unconsolidated affiliates														0	[8]	0	[8]	0	[8]
Interest expense, net														106	[8]	122	[8]	111	[8]
Income (loss) from continuing operations before income taxes														351	[8]	344	[8]	-54	[8]
Income taxes														140	[8]	134	[8]	-23	[8]
Net income														211	[8]	210	[8]	-31	[8]
Capital expenditures														620	[8]	587	[8]	500	[8]
Assets	8,078	[8]				7,861	[8]							8,078	[8]	7,861	[8]
Operating Segments [Member] | Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues														4,467	[9]	4,280	[9]	4,824	[9]
Income (loss) from continuing operations before income taxes																7
Other Segments [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Revenues														1,285	[1],[10]	1,241	[1],[10]	1,396	[1],[10]
Depreciation and amortization														53	[10]	52	[10]	48	[10]
Operating Expenses														1,353	[1],[10]	1,324	[1],[10]	1,662	[1],[10]
Equity in earnings (losses) of unconsolidated affiliates														0	[10]	0	[10]	0	[10]
Interest expense, net														169	[10]	183	[10]	86	[10]
Income (loss) from continuing operations before income taxes														-227	[10]	-191	[10]	-325	[10]
Income taxes														-63	[10]	-20	[10]	-215	[10]
Net income														-164	[10]	-171	[10]	-110	[10]
Capital expenditures														95	[10]	86	[10]	67	[10]
Assets	9,794	[10]				8,317	[10]							9,794	[10]	8,317	[10]
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Revenues														-2,072	[1]	-2,612	[1]	-3,064	[1]
Operating revenues from affiliates														6	[11]	14	[11]	6	[11]
Depreciation and amortization														0		0		0
Operating Expenses														-2,071	[1]	-2,618	[1]	-3,043	[1]
Equity in earnings (losses) of unconsolidated affiliates														0		0		0
Interest expense, net														0		0		0
Income (loss) from continuing operations before income taxes														-6		-13		-7
Income taxes														0		1		-1
Net income														-6		-14		-6
Capital expenditures														0		0		0
Assets	-11,741					-11,221								-11,741		-11,221
Intersegment Eliminations [Member] | Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														762	[11],[7]	1,367	[11],[7]	1,660	[11],[7]
Intersegment Eliminations [Member] | Commonwealth Edison Co [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														4	[11]	3	[11]	2	[11]
Intersegment Eliminations [Member] | PECO Energy Co [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														2	[11]	1	[11]	3	[11]
Intersegment Eliminations [Member] | Baltimore Gas and Electric Company [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														25	[11],[8]	13	[11],[8]	9	[11],[8]
Intersegment Eliminations [Member] | Corporate and Other [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														1,280	[10],[11]	1,237	[10],[11]	1,381	[10],[11]
Intersegment Eliminations [Member] | Generation Midwest [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														8		-10		24
Intersegment Eliminations [Member] | Segment Elimination [Member]
Segment Reporting Information [Line Items]
Operating revenues from affiliates														-2,067	[11]	-2,607	[11]	-3,049	[11]
Exelon Generation Co L L C [Member]
Segment Reporting Information [Line Items]
Revenues	4,802		4,412	3,789	4,390	3,772		4,255	4,070	3,533				17,393		15,630		14,437
Operating revenues from affiliates														779		1,423		1,702
Income (loss) from continuing operations before income taxes														1,226		1,675		1,058
Income taxes														207		615		500
Net income	-91		771	340	-185	269		490	330	-18				1,019		1,060		558
Assets	45,348	[12]				41,232	[12]							45,348	[12]	41,232	[12]
Utility taxes														89	[5]	79	[5]	82	[5]
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member]
Segment Reporting Information [Line Items]
Revenues														198	[13]
Operating revenues from affiliates																405	[13]	543	[13]
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]
Segment Reporting Information [Line Items]
Revenues														387	[14]
Operating revenues from affiliates																455	[14]	322	[14]
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member]
Segment Reporting Information [Line Items]
Revenues														176	[15]
Operating revenues from affiliates																506	[15]	795	[15]
Exelon Generation Co L L C [Member] | Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenues																		7
Commonwealth Edison Co [Member]
Segment Reporting Information [Line Items]
Revenues	1,079		1,222	1,128	1,134	1,068		1,156	1,080	1,160				4,564		4,464		5,443
Operating revenues from affiliates														4		3		2
Income taxes														268		152		239
Net income	73		126	111	98	109		126	96	-81				408		249		379
Assets	25,392					24,118								25,392		24,118
Utility taxes														238	[5]	241	[5]	239	[5]
PECO Energy Co [Member]
Segment Reporting Information [Line Items]
Revenues	750		693	656	993	805		728	672	895				3,094		3,100		3,186
Operating revenues from affiliates														2		1		3
Income (loss) from continuing operations before income taxes														466		557		508
Income taxes														114		162		127
Net income	98		81	84	89	102		92	72	121				352		395		381
Assets	9,943					9,617								9,943		9,617
Utility taxes														128	[5]	129	[5]	141	[5]
Baltimore Gas and Electric Company [Member]
Segment Reporting Information [Line Items]
Revenues	761		697	653	1,054	794		737	653	880				3,165		3,065		2,735
Operating revenues from affiliates														25		13		10
Income (loss) from continuing operations before income taxes														351		344		11
Income taxes														140		134		7
Net income	52		46	16	85	47		50	22	77				211		210		4
Assets	8,078	[16]				7,861	[16]							8,078	[16]	7,861	[16]
Utility taxes												$59	[5]	$86	[5]	$82	[5]	$75	[5]
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[3]	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
[4]	Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[5]	Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s and BGE’s utility taxes represent municipal and state utility taxes and gross receipts taxes related to their operating revenues, respectively. The offsetting collection of utility taxes from customers is recorded in revenues on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[6]	The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.
[7]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. For the year ended December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic region, and sales to ComEd of $176 million in the Midwest region, which eliminate upon consolidation. For the year ended December 31, 2013, intersegment revenues for Generation include revenue from sales to PECO of $405 million and sales to BGE of $455 million in the Mid-Atlantic region, and sales to ComEd of $506 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation. For the year ended December 31, 2012, intersegment revenues for Generation include revenue from sales to PECO of $543 million and sales to BGE of $322 million in the Mid-Atlantic region, and sales to ComEd of $795 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which eliminate upon consolidation.
[8]	Amounts represent activity recorded at BGE from March 12, 2012, the closing date of the merger, through December 31, 2014.
[9]	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[10]	Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
[11]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
[12]	Generation’s consolidated assets include $8,119 million and $1,695 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $2,507 million and $362 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 2–Variable Interest Entities.
[13]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
[14]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[15]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
[16]	BGE’s consolidated assets include $24 million and $31 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE that can only be used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $197 million and $269 million at December 31, 2014 and December 31, 2013, respectively, of BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2 - Variable Interest Entities.

Segment_Information_Generation

Segment Information - Generation Total Revenues (Details) (USD $)

3 Months Ended

12 Months Ended

In Millions, unless otherwise specified

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2013

Jun. 30, 2013

Mar. 31, 2013

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Segment Reporting Information [Line Items]

Revenues

$7,255

$6,912

$6,024

$7,237

$6,163

$6,502

$6,141

$6,082

$27,429

[1]

$24,888

[1]

$23,489

[1]

Revenue from Related Parties

23

70

48

Amortization of intangible assets related to commodity contracts

289

767

1,505

Generation Mid Atlantic [Member]

Segment Reporting Information [Line Items]

Revenues

5,259

5,204

5,038

Generation Midwest [Member]

Segment Reporting Information [Line Items]

Revenues

4,475

4,270

4,848

Generation New England [Member]

Segment Reporting Information [Line Items]

Revenues

1,422

1,237

1,093

Generation New York [Member]

Segment Reporting Information [Line Items]

Revenues

843

714

557

Generation ERCOT [Member]

Segment Reporting Information [Line Items]

Revenues

935

1,216

1,367

Generation Other Regions [Member]

Segment Reporting Information [Line Items]

Revenues

1,309

[2]

968

[2]

833

[2]

Generation Reportable Segments Total [Member]

Segment Reporting Information [Line Items]

Revenues

14,243

13,609

13,736

Generation All Other Segments [Member]

Segment Reporting Information [Line Items]

Revenues

3,150

[3]

2,021

[3]

701

[3]

Generation Total Consolidated Group [Member]

Segment Reporting Information [Line Items]

Revenues

17,393

15,630

14,437

Operating Segments [Member] | Generation Mid Atlantic [Member]

Segment Reporting Information [Line Items]

Revenues

5,265

[4]

5,182

[4]

5,082

[4]

Operating Segments [Member] | Generation Midwest [Member]

Segment Reporting Information [Line Items]

Revenues

4,467

[4]

4,280

[4]

4,824

[4]

Operating Segments [Member] | Generation New England [Member]

Segment Reporting Information [Line Items]

Revenues

1,417

[4]

1,245

[4]

1,048

[4]

Operating Segments [Member] | Generation New York [Member]

Segment Reporting Information [Line Items]

Revenues

843

[4]

735

[4]

582

[4]

Operating Segments [Member] | Generation ERCOT [Member]

Segment Reporting Information [Line Items]

Revenues

938

[4]

1,222

[4]

1,365

[4]

Operating Segments [Member] | Generation Other Regions [Member]

Segment Reporting Information [Line Items]

Revenues

1,319

[2],[4]

946

[2],[4]

755

[2],[4]

Operating Segments [Member] | Generation Reportable Segments Total [Member]

Segment Reporting Information [Line Items]

Revenues

14,249

[4]

13,610

[4]

13,656

[4]

Operating Segments [Member] | Generation All Other Segments [Member]

Segment Reporting Information [Line Items]

Revenues

3,144

[3],[4]

2,020

[3],[4]

781

[3],[4]

Operating Segments [Member] | Generation Total Consolidated Group [Member]

Segment Reporting Information [Line Items]

Revenues

17,393

[4]

15,630

[4]

14,437

[4]

Intersegment Eliminations [Member]

Segment Reporting Information [Line Items]

Revenues

-2,072

[1]

-2,612

[1]

-3,064

[1]

Revenue from Related Parties

6

[5]

14

[5]

6

[5]

Intersegment Eliminations [Member] | Generation Mid Atlantic [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

-6

22

-44

Intersegment Eliminations [Member] | Generation Midwest [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

8

-10

24

Intersegment Eliminations [Member] | Generation New England [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

5

-8

45

Intersegment Eliminations [Member] | Generation New York [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

0

-21

-25

Intersegment Eliminations [Member] | Generation ERCOT [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

-3

-6

2

Intersegment Eliminations [Member] | Generation Other Regions [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

-10

[2]

22

[2]

78

[2]

Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

-6

-1

80

Intersegment Eliminations [Member] | Generation All Other Segments [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

6

[3]

1

[3]

-80

[3]

Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]

Segment Reporting Information [Line Items]

Revenue from Related Parties

$0

$0

$0

[1]

For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.

[2]

Other regions include the South, West and Canada, which are not considered individually significant.

[3]

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 $289 million, $767 million, and $1,505 million for the years ended December 31, 2014, 2013, and 2012, respectively, and elimination of intersegment revenues.

[4]

Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

[5]

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

Segment_Information_Generation1

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting Information [Line Items]
Amortization Of Intangible Assets Related To Commodity Contracts For Revenue Net Purchased Power And Fuel	$124		$488		$1,098
Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	3,417		3,270		3,433
Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	2,594		2,586		2,998
Generation New England [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	351		185		196
Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	483		-4		76
Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	317		436		405
Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	327	[1]	201	[1]	131	[1]
Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	7,489		6,674		7,239
Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	-21	[2]	759	[2]	137	[2]
Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense, Total	7,468		7,433		7,376
Operating Segments [Member] | Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	3,466	[3]	3,273	[3]	3,477	[3]
Operating Segments [Member] | Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	2,580	[3]	2,585	[3]	2,974	[3]
Operating Segments [Member] | Generation New England [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	432	[3]	217	[3]	151	[3]
Operating Segments [Member] | Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	457	[3]	14	[3]	101	[3]
Operating Segments [Member] | Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	573	[3]	604	[3]	403	[3]
Operating Segments [Member] | Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	611	[1],[3]	334	[1],[3]	53	[1],[3]
Operating Segments [Member] | Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	8,119	[3]	7,027	[3]	7,159	[3]
Operating Segments [Member] | Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	-651	[2],[3]	406	[2],[3]	217	[2],[3]
Operating Segments [Member] | Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from external customers	7,468	[3]	7,433	[3]	7,376	[3]
Intersegment Eliminations [Member] | Generation Mid Atlantic [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	-49		-3		-44
Intersegment Eliminations [Member] | Generation Midwest [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	14		1		24
Intersegment Eliminations [Member] | Generation New England [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	-81		-32		45
Intersegment Eliminations [Member] | Generation New York [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	26		-18		-25
Intersegment Eliminations [Member] | Generation ERCOT [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	-256		-168		2
Intersegment Eliminations [Member] | Generation Other Regions [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	-284	[1]	-133	[1]	78	[1]
Intersegment Eliminations [Member] | Generation Reportable Segments Total [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	-630		-353		80
Intersegment Eliminations [Member] | Generation All Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	630	[2]	353	[2]	-80	[2]
Intersegment Eliminations [Member] | Generation Total Consolidated Group [Member]
Segment Reporting Information [Line Items]
Revenue net of purchased power and fuel expense from transactions with other operating segments of the same entity	$0		$0		$0
[1]	Other regions include the South, West and Canada, which are not considered individually significant.
[2]	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 $124 million, $488 million, and $1,098 million, for the years ended December 31, 2014, 2013, and 2012, respectively, and the elimination of intersegment revenue net of purchased power and fuel expense.
[3]	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

Related_Party_Transactions_Rel

Related Party Transactions - Related Party Transactions included in Consolidated Income Statement (Details) (USD $)	3 Months Ended								12 Months Ended						0 Months Ended	3 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Apr. 01, 2014	Mar. 11, 2012
Related Party Transaction [Line Items]
Operating revenues from affiliates									$23		$70		$48
Revenues	7,255	6,912	6,024	7,237	6,163	6,502	6,141	6,082	27,429	[1]	24,888	[1]	23,489	[1]
Purchase power and fuel from affiliates									531		1,256		1,036
Total interest expense to affiliates, net									41		41		37
Total income (loss) in equity method investments									-20		10		-91
Cash dividends paid to parent									1,065		1,249		1,716
Required purchases of power from CENG's nuclear plants not sold to third parties									85.00%
Purchase of nuclear output of CENG									50.01%
Purchase of nuclear output by EDF									49.99%
PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									1	[2]	10	[2]	6	[2]
Constellation Energy Nuclear Group Llc Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									17	[3]	56	[3]	42	[3]
Purchase power and fuel from affiliates									282	[4]	992	[4]	793	[4]
Baltimore Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									5		4		0
Keystone Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Purchase power and fuel from affiliates									138	[5]	144	[5]	119	[5]
Conemaugh Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Purchase power and fuel from affiliates									99	[5]	98	[5]	101	[5]
SafeHarborWaterPowerCorp [Member]
Related Party Transaction [Line Items]
Purchase power and fuel from affiliates									12	[5]	22	[5]	23	[5]
ComEd Financing Three Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									13		13		13
PECO Trust Three Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									6		6		6
PECO Trust Four Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									6		6		6
BGE Capital Trust II [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									16	[6]	16	[6]	12	[6]
CENG Equity Investment Income Affiliate [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments									-19	[7]	9	[7]	-99	[7]
Other Affiliate [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments									-1		1		8
Exelon Generation Co L L C [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									779		1,423		1,702
Revenues	4,802	4,412	3,789	4,390	3,772	4,255	4,070	3,533	17,393		15,630		14,437
Purchase power and fuel from affiliates									557		1,270		1,044
Operating and maintenance from affiliates									623		574		630
Total interest expense to affiliates, net									53		59		75
Total income (loss) in equity method investments									-20		10		-91
Cash distribution paid to member									645		625		1,626
Contribution from member									53		26		48
Required purchases of power from CENG's nuclear plants not sold to third parties									85.00%						85.00%
Purchase of nuclear output by EDF															49.99%
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates											506	[8]	795	[8]
Revenues									176	[8]
Purchase power and fuel from affiliates									1		1		0
Operating and maintenance from affiliates									3	[9]	2	[9]	2	[9]
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates											405	[10]	543	[10]
Revenues									198	[10]
Operating and maintenance from affiliates									2	[9]	1	[9]	3	[9]
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates											455	[11]	322	[11]
Revenues									387	[11]
Purchase power and fuel from affiliates									25		13		8
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									17	[3]	56	[3]	42	[3]
Purchase power and fuel from affiliates									282	[4]	992	[4]	793	[4]
Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									1		1		0
Operating and maintenance from affiliates									618	[12]	571	[12]	625	[12]
Capitalized Costs									91	[13]	93	[13]	80	[13]
Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									53		59		75
Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Purchase power and fuel from affiliates									138	[5]	144	[5]	119	[5]
Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Purchase power and fuel from affiliates									99	[5]	98	[5]	101	[5]
Exelon Generation Co L L C [Member] | SafeHarborWaterPowerCorp [Member]
Related Party Transaction [Line Items]
Purchase power and fuel from affiliates									12		22		23
Exelon Generation Co L L C [Member] | CENG Equity Investment Income Affiliate [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments									-19	[14]	9	[14]	-99	[14]
Exelon Generation Co L L C [Member] | Qualifying Facilities And Domestic Power Projects Affiliate [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments									-1		1		8
Exelon Generation Co L L C [Member] | Exelon Generation Co L L C [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments									-20
Commonwealth Edison Co [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									4		3		2
Revenues	1,079	1,222	1,128	1,134	1,068	1,156	1,080	1,160	4,564		4,464		5,443
Operating and maintenance from affiliates									166		157		163
Total interest expense to affiliates, net									13		13		13
Total income (loss) in equity method investments									0		0
Cash dividends paid to parent									307		220		105
Non-cash contribution to equity									273		0		11
Contributions from parent									273		0		0
Amortization of energy contract assets and liabilities											0	[15]	0	[15]
Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									4		3		2
Purchase power and fuel from affiliates									176	[16]	512	[16]	789	[16]
Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating and maintenance from affiliates									166	[13]	157	[13]	163	[13]
Capitalized Costs									77	[13]	69	[13]	92	[13]
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									13		13		13
Baltimore Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									25		13		10
Revenues	761	697	653	1,054	794	737	653	880	3,165		3,065		2,735
Operating and maintenance from affiliates									103		83		106
Total interest expense to affiliates, net									16		16		16			4
Total income (loss) in equity method investments									0		0		0
Contributions from parent									0		0		66
Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									25	[17]	13	[17]	10	[17]
Purchase power and fuel from affiliates									382	[18]	452	[18]	396	[18]
Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating and maintenance from affiliates									103	[19]	83	[19]	106	[19]
Capitalized Costs									19	[19]	15	[19]	21	[19]
Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									16		16		16
PECO Energy Co [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									2		1		3
Revenues	750	693	656	993	805	728	672	895	3,094		3,100		3,186
Operating and maintenance from affiliates									99		101		111
Total interest expense to affiliates, net									12		12		12
Total income (loss) in equity method investments									0		0		0
Cash dividends paid to parent									320		332		343
Contributions from parent									24		27		9
PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Operating revenues from affiliates									2	[20]	1	[20]	3	[20]
Purchase power and fuel from affiliates									194	[21]	392	[21]	533	[21]
Operating and maintenance from affiliates									3		3		4
PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Operating and maintenance from affiliates									96	[22]	98	[22]	107	[22]
Capitalized Costs									39	[22]	46	[22]	54	[22]
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									6		6		6
PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]
Related Party Transaction [Line Items]
Total interest expense to affiliates, net									$6		$6		$6
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated Statement of Operations. See Note 3—Regulatory Matters for additional information.
[3]	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[4]	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[5]	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
[6]	The BGE Capital Trust II portion of Exelon’s interest expense to affiliates, net, for December 31, 2012 excludes $4 million of expense incurred in 2012 prior to the closing of Exelon’s merger with Constellation on March 12, 2012.
[7]	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC
[8]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
[9]	Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
[10]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
[11]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[12]	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[13]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[14]	Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[15]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[16]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information.
[17]	BGE provides energy to Generation for Generation’s own use.
[18]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[19]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[20]	PECO provides energy to Generation for Generation’s own use.
[21]	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.
[22]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Related_Party_Transactions_Rel1

Related Party Transactions - Related Party Transactions included in Consolidated Balance Sheet (Details) (USD $)	12 Months Ended		0 Months Ended	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Apr. 01, 2014	Dec. 31, 2013		Dec. 31, 2012
Related Party Transaction [Line Items]
Total payables to affiliates (current)	($8)			($116)
Long-term debt to financing trusts	648			648
Required purchases of power from CENG's nuclear plants not sold to third parties	85.00%
Purchase of nuclear output of CENG	50.01%
Purchase of nuclear output by EDF	49.99%
CENG Equity Investment Income Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	0	[1]		3	[1]
ComEd Financing Three Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-4			-4
Long-term debt to financing trusts	206			206
PECO Trust Three Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-1			-1
Long-term debt to financing trusts	81			81
PECO Trust Four Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	103			103
BGE Capital Trust II [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-3			-4
Long-term debt to financing trusts	258			258
Constellation Energy Nuclear Group Llc Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	0	[1]		3	[1]
Total payables to affiliates (current)	0	[2]		-85	[2]
Keystone Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	0	[3]		-12	[3]
Conemaugh Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	0	[3]		-9	[3]
Other Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	0			-1
Exelon Generation Co L L C [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	113			108
Total payables to affiliates (current)	-107			-181
Total payables to affiliates (noncurrent)	2,880			2,740
Required purchases of power from CENG's nuclear plants not sold to third parties	85.00%		85.00%
Purchase of nuclear output by EDF			49.99%
Exelon Generation Co L L C [Member] | Commonwealth Edison Co Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	43	[4]		38	[4]
Total payables to affiliates (current)	-12			0
Total payables to affiliates (noncurrent)	2,389	[5]		2,293	[5]
Exelon Generation Co L L C [Member] | Constellation Energy Nuclear Group Llc Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	0	[2]		-85	[2]
Exelon Generation Co L L C [Member] | Keystone Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	0	[3]		-12	[3]
Exelon Generation Co L L C [Member] | Conemaugh Fuels LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	0	[3]		-9	[3]
Exelon Generation Co L L C [Member] | Other Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	1			2
Total payables to affiliates (current)	0			-2
Exelon Generation Co L L C [Member] | PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	29	[6]		38	[6]
Total payables to affiliates (noncurrent)	490	[5]		447	[5]
Exelon Generation Co L L C [Member] | Baltimore Gas And Electric Company Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	40	[7]		27	[7]
Exelon Generation Co L L C [Member] | Exelon Corporation Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-12	[8]		-7	[8]
Exelon Generation Co L L C [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-83	[9]		-66	[9]
Total payables to affiliates (noncurrent)	1	[9]		0	[9]
Baltimore Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-66			-55
Prepaid voluntary employee beneficiary association trust	1	[10]		1	[10]
Baltimore Gas and Electric Company [Member] | BGE Capital Trust II [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-3			-4
Long-term debt to financing trusts	258			258
Baltimore Gas and Electric Company [Member] | PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-1			-3
Baltimore Gas and Electric Company [Member] | Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-40	[11]		-27	[11]
Baltimore Gas and Electric Company [Member] | Exelon Corporation Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-5	[10]		-1	[10]
Baltimore Gas and Electric Company [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-17	[12]		-20	[12]
PECO Energy Co [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	3			3
Total receivable from affiliates (noncurrent)	490			447
Total payables to affiliates (current)	-52			-58
Long-term debt to financing trusts	184			184
Prepaid voluntary employee beneficiary association trust	3	[13]		3	[13]
PECO Energy Co [Member] | Commonwealth Edison Co Affiliate [Member]
Related Party Transaction [Line Items]
Total receivable from affiliates (noncurrent)	2			0
PECO Energy Co [Member] | PECO Trust Three Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-1			-1
Long-term debt to financing trusts	81			81
PECO Energy Co [Member] | PECO Trust Four Affiliate [Member]
Related Party Transaction [Line Items]
Long-term debt to financing trusts	103			103
PECO Energy Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]
Related Party Transaction [Line Items]
Total receivable from affiliates (noncurrent)	1			3
PECO Energy Co [Member] | Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total receivable from affiliates (noncurrent)	490	[14]		447	[14]
Total payables to affiliates (current)	-29	[15]		-38	[15]
PECO Energy Co [Member] | Exelon Corporation Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-2			-2
PECO Energy Co [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-20	[16]		-17	[16]
Commonwealth Edison Co [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	14			3
Total receivable from affiliates (noncurrent)	2,571			2,469
Total payables to affiliates (current)	-84			-83
Prepaid voluntary employee beneficiary association trust	13	[17]		13	[17]
Energy Contract Amortization				0	[18]	0	[18]
Commonwealth Edison Co [Member] | ComEd Financing Three Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-4			-4
Long-term debt to financing trusts	206			206
Commonwealth Edison Co [Member] | Voluntary Employee Beneficiary Association Trust [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	2			3
Commonwealth Edison Co [Member] | Other Affiliate [Member]
Related Party Transaction [Line Items]
Total receivable from affiliates (noncurrent)	182	[19]		176	[19]
Total payables to affiliates (current)	0			-2
Commonwealth Edison Co [Member] | PECO Energy Co Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-2			0
Commonwealth Edison Co [Member] | Baltimore Gas And Electric Company Affiliate [Member]
Related Party Transaction [Line Items]
Total receivables from affiliates (current)	12			0
Commonwealth Edison Co [Member] | Exelon Generation Co LLC Affiliate [Member]
Related Party Transaction [Line Items]
Total receivable from affiliates (noncurrent)	2,389	[20]		2,293	[20]
Total payables to affiliates (current)	-43	[21]		-38	[21]
Commonwealth Edison Co [Member] | Exelon Corporation Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	-3			-9
Commonwealth Edison Co [Member] | Exelon Business Services Co Affiliate [Member]
Related Party Transaction [Line Items]
Total payables to affiliates (current)	($32)	[22]		($30)	[22]
[1]	Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[2]	CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA). Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
[3]	During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers, Acquisitions, and Dispositions for more information.
[4]	Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—Regulatory Matters for additional information.
[5]	Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 15—Asset Retirement Obligations
[6]	Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has five-year and ten-year agreements with PECO to sell non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information.
[7]	Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[8]	The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation processed on behalf of Generation.
[9]	Generation receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[10]	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for BGE’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
[11]	BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory Matters for additional information.
[12]	BGE receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[13]	The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than actual claim expense incurred by the plans over time.
[14]	PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.
[15]	PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year agreements with Generation to purchase non-solar and solar AECs, respectively. See Note 3—Regulatory Matters for additional information on AECs.
[16]	PECO receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
[17]	The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual claim expense incurred by the plans over time. The prepayment is included in other current assets.
[18]	Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
[19]	Represents indemnification from Exelon Corporate related to the like-kind exchange transaction.
[20]	ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd. To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for payment to ComEd’s customers.
[21]	ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters and Note 12—Derivative Financial Instruments for additional information.
[22]	ComEd receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.

Quarterly_Data_Unaudited_Quart

Quarterly Data (Unaudited) - Quarterly Operating Results (Details) (USD $)	3 Months Ended													12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013		Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Selected Quarterly Financial Information [Line Items]
Operating Revenues	$7,255		$6,912		$6,024		$7,237		$6,163	$6,502	$6,141	$6,082		$27,429	[1]	$24,888	[1]	$23,489	[1]
Operating Income	348		1,739	[2]	842	[2]	168	[2]
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	18	[3]	993		522		90		495	738	490	-4	[4]	1,820		1,729		1,171
Reclassifications to Operating Income (Loss)			339		13		5
Unrecognized Tax Benefits, Interest on Income Taxes Accrued												265
Exelon Generation Co L L C [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	4,802		4,412		3,789		4,390		3,772	4,255	4,070	3,533		17,393		15,630		14,437
Operating Income	-105		1,225	[5]	441	[5]	-384	[5]	405
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	-91		771		340		-185		269	490	330	-18		1,019		1,060		558
Reclassifications to Operating Income (Loss)			338		12		5			8		5
Commonwealth Edison Co [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	1,079		1,222		1,128		1,134		1,068	1,156	1,080	1,160		4,564		4,464		5,443
Operating Income	196		288	[6]	259	[6]	238		236	278	232	209
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	73		126		111		98		109	126	96	-81		408		249		379
Reclassifications to Operating Income (Loss)			1		1
Unrecognized Tax Benefits, Interest on Income Taxes Accrued												170
PECO Energy Co [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	750		693		656		993		805	728	672	895		3,094		3,100		3,186
Operating Income	156		133		134		149		168	155	138	203
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	98		81		84		89		102	92	72	121		352		395		381
Baltimore Gas and Electric Company [Member]
Selected Quarterly Financial Information [Line Items]
Operating Revenues	761		697		653		1,054		794	737	653	880		3,165		3,065		2,735
Operating Income	113		102		55		169		101	114	69	163
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$52		$46		$16		$85		$47	$50	$22	$77		$211		$210		$4
[1]	For the years ended December 31, 2014, 2013 and 2012, utility taxes of $89 million, $79 million and $82 million, respectively, are included in revenues and expenses for Generation. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $238 million, $241 million and $239 million, respectively, are included in revenues and expenses for ComEd. For the years ended December 31, 2014, 2013 and 2012, utility taxes of $128 million, $129 million and $141 million, respectively, are included in revenues and expenses for PECO. For the years ended December 31, 2014, December 31, 2013 and for the period of March 12, 2012 through December 31, 2012, utility taxes of $86 million, $82 million and $59 million are included in revenues and expenses for BGE, respectively.
[2]	In the first, second, and third quarter of 2014, Exelon reclassified $5 million, $13 million, and $339 million, respectively, to Operating income for presentation purposes in Exelon's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Exelon's Net (Loss) Income on Common Stock.
[3]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[4]	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
[5]	In the first, second, and third quarter of 2014, Generation reclassified $5 million, $12 million, and $338 million, respectively, to Operating (loss) income for presentation purposes in Generation's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect Generation's Net (Loss) Income on Membership Interest.
[6]	In both the second and third quarter of 2014, ComEd reclassified $1 million to Operating income for presentation purposes in ComEd's Consolidated Statements of Operations and Comprehensive Income. The reclassifications did not affect ComEd's Net (Loss) Income.

Quarterly_Data_Unaudited_Quart1

Quarterly Data (Unaudited) - Quarterly Per Share Information (Details) (USD $)	3 Months Ended								12 Months Ended
In Millions, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Weighted average common shares outstanding—basic	861	861	860	858	856	857	856	855	860	856	816
Earnings Per Share, Basic	$0.02	$1.15	$0.61	$0.10	$0.60	$0.86	$0.57	($0.01)
Weighted average common shares outstanding—diluted	868	863	864	861	860	860	860	855	864	860	819
Earnings Per Share, Diluted	$0.02	$1.15	$0.60	$0.10	$0.59	$0.86	$0.57	($0.01)	$1.88	$2	$1.42

Quarterly_Data_Unaudited_Quart2

Quarterly Data (Unaudited) - Quarterly Composite Common Stock Prices and Dividends (Details) (USD $)	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013
Quarterly Financial Data [Abstract]
High price	$38.93	$36.26	$37.73	$33.94	$30.59	$32.42	$37.80	$34.56
Low price	$33.07	$30.66	$33.11	$26.45	$26.64	$29.42	$29.84	$29.10
Close	$37.08	$34.09	$36.48	$33.56	$27.39	$29.64	$30.88	$34.48
Dividends	$0.31	$0.31	$0.31	$0.31	$0.31	$0.31	$0.31	$0.53

Schedule_I_Condensed_Financial1

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Operations and Other Comprehensive Income (Details) (USD $)	3 Months Ended										12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013		Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012
Operating Expenses [Abstract]
Operating and maintenance											$8,568	$7,270		$7,961
Total operating expenses											25,039	21,242		21,018
Operating Income (Loss)											3,096	3,669		2,373
Other income and (deductions)
Interest expense, net											-1,024	-1,315		-891
Equity in (losses) earnings of unconsolidated affiliates											-20	10		-91
Other, net											455	460		353
Total other income and (deductions)											-610	-896		-575
Income before income taxes											2,486	2,773		1,798
Income taxes											666	1,044		627
Net income	18	[1]	993	522	90	495	738	490	-4	[2]	1,820	1,729		1,171
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost, net of tax											30	0		-1
Actuarial loss reclassified to periodic cost, net of tax											147	208		168
Transition obligation reclassified to periodic cost, net of tax											0	0		2
Pension and non-pension postretirement benefit plans valuation adjustment, net of tax											-497	669		-371
Unrealized gain (loss) on cash flow hedges, net of taxes											-148	-248		-120
Unrealized gain (loss) on marketable securities, net of taxes											1	2		2
Unrealized gain (loss) on equity investments, net of taxes											8	106		1
Unrealized gain (loss) on foreign currency translation, net of taxes											-9	-10		0
Reversal of CENG equity method AOCI, net of taxes											-116	0		0
Other comprehensive income (loss)											-644	727	[3]	-317
Comprehensive income											1,176	2,456		854
Exelon Corporate [Member]
Operating Expenses [Abstract]
Operating and maintenance											9	9		201
Operating and maintenance from affiliates											38	34		72
Other											3	12		6
Total operating expenses											50	55		279
Operating Income (Loss)											-50	-55		-279
Other income and (deductions)
Interest expense, net											-237	-116		-153
Equity in (losses) earnings of unconsolidated affiliates											1,779	1,903		1,278
Interest income from affiliates, net											53	36		75
Other, net											-2	-78		7
Total other income and (deductions)											1,593	1,745		1,207
Income before income taxes											1,543	1,690		928
Income taxes											-80	-29		-232
Net income											1,623	1,719		1,160
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost, net of tax											30	0		-1
Actuarial loss reclassified to periodic cost, net of tax											147	208		168
Transition obligation reclassified to periodic cost, net of tax											0	0		2
Pension and non-pension postretirement benefit plans valuation adjustment, net of tax											-497	669		-371
Unrealized gain (loss) on cash flow hedges, net of taxes											-148	-248		-120
Unrealized gain (loss) on marketable securities, net of taxes											1	2		2
Unrealized gain (loss) on equity investments, net of taxes											8	106		1
Unrealized gain (loss) on foreign currency translation, net of taxes											-9	-10		0
Reversal of CENG equity method AOCI, net of taxes											-116	0		0
Other comprehensive income (loss)											-644	727		-317
Comprehensive income											$979	$2,446		$843
[1]	Includes charges to earnings related to the impairments of certain generating assets which were held for sale and certain Upstream exploration assets. See Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated Financial Statements for additional information.
[2]	Includes $265 million of interest expense related to the remeasurement of Exelon’s like-kind exchange tax position in the first quarter of 2013. See Note 14—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
[3]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Schedule_I_Condensed_Financial2

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Statements of Cash Flows (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Net cash flows provided by operating activities	$4,457	$6,343	$6,131
Cash flows from investing activities
Proceeds from termination of direct financing lease investment	335	0	0
Capital expenditures	-6,077	-5,395	-5,789
Cash and restricted cash acquired from Constellation	140	0	964
Change in restricted cash	-104	-43	-34
Other investing activities	-88	112	136
Net cash flows used in investing activities	-4,599	-5,394	-4,576
Cash flows from financing activities
Changes in short-term borrowings	122	332	-197
Issuance of long-term debt	3,463	2,055	2,027
Retirement of long-term debt	-1,545	-1,589	-1,145
Dividends paid on common stock	-1,065	-1,249	-1,716
Proceeds from employee stock plans	35	47	72
Other financing activities	-178	-119	-111
Net cash flows provided by (used in) financing activities	411	-826	-1,085
Increase in cash and cash equivalents	269	123	470
Cash and cash equivalents at beginning of period	1,609	1,486	1,016
Cash and cash equivalents at end of period	1,878	1,609	1,486
Exelon Corporate [Member]
Net cash flows provided by operating activities	806	1,053	2,131
Cash flows from investing activities
Proceeds from termination of direct financing lease investment	335	0	0
Changes in Exelon intercompany money pool	-83	-60	0
Note receivable from affiliates	0	484	0
Capital expenditures	1	0	-30
Cash and restricted cash acquired from Constellation	0	0	679
Change in restricted cash	0	38	-38
Investment in affiliates	-70	-38	-67
Other investing activities	-126	15	0
Net cash flows used in investing activities	57	439	544
Cash flows from financing activities
Changes in Exelon intercompany money pool	0	0	-703
Changes in short-term borrowings	0	10	-161
Issuance of long-term debt	1,150	0	0
Retirement of long-term debt	-23	-450	-77
Dividends paid on common stock	-1,065	-1,249	-1,716
Proceeds from employee stock plans	35	47	73
Other financing activities	-84	-6	30
Net cash flows provided by (used in) financing activities	13	-1,648	-2,554
Increase in cash and cash equivalents	876	-156	121
Cash and cash equivalents at beginning of period	3	159	38
Cash and cash equivalents at end of period	$879	$3	$159

Schedule_I_Condensed_Financial3

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet (Details) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
In Millions, unless otherwise specified
Current assets
Cash and cash equivalents	$1,878		$1,609		$1,486		$1,016
Accounts receivable, net
Other	1,227		1,175
Deferred income taxes	244		573
Regulatory assets	847		760
Other	865		652
Total current assets	12,097		10,137
Property, plant and equipment, net	52,087		47,330
Deferred debits and other assets
Regulatory assets	6,076		5,910
Other	1,160		964
Total deferred debits and other assets	22,630		22,457
Total assets	86,814	[1]	79,924	[1]
Current liabilities
Long-term debt due within one year	1,802		1,509
Accounts payable	3,048		2,484
Unamortized energy contract liabilities	238		261
Accrued expenses	1,539		1,633
Deferred income taxes	0		40
Regulatory liabilities	310		327
Other	1,123		858
Total current liabilities	8,762		7,728
Long-term debt	19,362		17,623
Deferred credits and other liabilities
Regulatory liabilities	4,550		4,388
Pension obligations	3,366		1,876
Non-pension postretirement benefit obligations	1,742		2,190
Other	2,147		2,540
Total deferred credits and other liabilities	33,909		30,985
Total liabilities	62,681	[1]	56,984	[1]
Shareholders’ equity
Common stock	16,709		16,741
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013)	-2,327		-2,327
Retained earnings	10,910		10,358
Accumulated other comprehensive loss, net	-2,684		-2,040	[2]	-2,767	[2]
Total shareholders’ equity	22,608		22,732
BGE preference stock not subject to mandatory redemption	193		193
Total liabilities and shareholders’ equity	86,814		79,924
Exelon Corporate [Member]
Current assets
Cash and cash equivalents	879		3		159		38
Accounts receivable, net
Other	209		72
Accounts receivable from affiliates	24		22
Deferred income taxes	20		27
Receivables from affiliates	818		179
Regulatory assets	254		233
Other	22		1
Total current assets	2,226		537
Property, plant and equipment, net	54		57
Deferred debits and other assets
Regulatory assets	3,186		3,005
Investments in affiliates	26,670		26,390
Deferred income taxes	2,187		1,890
Receivable from affiliates	943		1,522
Other	172		17
Total deferred debits and other assets	33,158		32,824
Total assets	35,438		33,418
Current liabilities
Long-term debt due within one year	1,409		10
Accounts payable	2		43
Unamortized energy contract liabilities	0		12
Accrued expenses	25		106
Deferred income taxes	60		26
Regulatory liabilities	51		2
Other	75		54
Total current liabilities	1,622		253
Long-term debt	2,841		3,033
Payables to affiliates	182		176
Deferred credits and other liabilities
Regulatory liabilities	37		43
Pension obligations	7,638		6,444
Non-pension postretirement benefit obligations	16		393
Deferred income taxes	93		70
Other	398		271
Total deferred credits and other liabilities	8,182		7,221
Total liabilities	12,827		10,683
Commitments and Contingencies
Shareholders’ equity
Common stock	16,709		16,741
Treasury stock, at cost (35 shares held at December 31, 2014 and 2013)	-2,327		-2,327
Retained earnings	10,910		10,358
Accumulated other comprehensive loss, net	-2,684		-2,040
Total shareholders’ equity	22,608		22,732
BGE preference stock not subject to mandatory redemption	3		3
Total liabilities and shareholders’ equity	$35,438		$33,418
[1]	Exelon’s consolidated assets include $8,160 million and $1,755 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $2,723 million and $658 million at December 31, 2014 and December 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2–Variable Interest Entities.
[2]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Schedule_I_Condensed_Financial4

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Condensed Balance Sheet - Phantom (Details) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Common stock, par value	$0	$0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	859,833,343	857,290,484
Treasury Stock, Shares held	35,000,000	35,000,000
Exelon Corporate [Member]
Common stock, par value	$0	$0
Common stock, shares authorized	2,000,000,000	2,000,000,000
Common stock, shares outstanding	860,000,000	857,000,000
Treasury Stock, Shares held	35,000,000	35,000,000

Schedule_I_Condensed_Financial5

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Basis of Presentation - Narrative (Details) (Exelon Corporate [Member])	Dec. 31, 2014
Exelon Generation Co L L C [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	100.00%
Commonwealth Edison Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	99.00%
Baltimore Gas and Electric Company [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	100.00%
Baltimore Gas and Electric Company [Member] | Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	0.00%
PECO Energy Co [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	100.00%
PECO Energy Co [Member] | Preferred Stock [Member]
Schedule of Equity Method Investments [Line Items]
Ownership percentage (more than 99% for ComEd)	0.00%

Schedule_I_Condensed_Financial6

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Narrative (Details) (USD $)	Dec. 31, 2014		30-May-14
Line of Credit Facility [Line Items]
Line of Credit Facility, Capacity Available for Trade Purchases	$6,771,000,000	[1]
Exelon Corporate [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Capacity Available for Trade Purchases	494,000,000	[1]
Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Maximum Program Size	8,500,000,000	[2]
Revolving Credit Facility [Member] | Exelon Corporate [Member]
Line of Credit Facility [Line Items]
Maximum Program Size	$500,000,000	[2]	$500,000,000	[3],[4]
[1]	Excludes $200 million bilateral credit facilities that do not back Generation’s commercial paper program.
[2]	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below
[3]	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 expired on October 17, 2014 and were renewed at the same amount through October 16, 2015. These facilities are solely utilized to issue letters of credit. As of December 31, 2014, letters of credit issued under these agreements totaled $9 million, $16 million, $21 million and $1 million for Generation, ComEd, PECO and BGE, respectively. Also, excludes the unsecured bridge credit facility of $3.2 billion at December 31, 2014, to support the PHI transaction discussed below.
[4]	aggregate bank commitments under the revolving and bilateral credit agreements (with the exception of $200 million bilateral agreements for Generation) that backstop the commercial paper program. See discussion below and Credit Agreements table below for items affecting effective program size.

Schedule_I_Condensed_Financial7

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Outstanding Long-term Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Jun. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt, Gross	$20,756,000,000			$18,760,000,000
Unamortized debt discount and premium, net	-37,000,000			-19,000,000
Long-term debt	19,362,000,000			17,623,000,000
Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	1,150,000,000		1,150,000,000	0
Maximum interest rate on long-term debt	6.50%
Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	7,071,000,000			7,571,000,000
Minimum interest rate on long-term debt	2.00%
Maximum interest rate on long-term debt	7.60%
Exelon Corporate [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	3,808,000,000			2,658,000,000
Unamortized debt discount and premium, net	1,000,000			2,000,000
Fair value adjustment	441,000,000			383,000,000
Long-term debt due within one year	-1,409,000,000			-10,000,000
Long-term debt	2,841,000,000			3,033,000,000
Exelon Corporate [Member] | Junior Subordinated Debt [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	1,150,000,000			0
Maximum interest rate on long-term debt	6.50%
Exelon Corporate [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Unsecured Long Term Debt	$2,658,000,000	[1]		$2,658,000,000	[1]
Minimum interest rate on long-term debt	4.90%	[1]
Maximum interest rate on long-term debt	7.60%	[1]
[1]	{F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmFiYTQ1MWI2ZGYzNjQ3OWM4OTUwZjNhNDE5MzEyMWVmfFRleHRTZWxlY3Rpb246RTczRDE1N0YxNENENzFBMzYxQjc2MDU5RUNERTM1RjkM}

Schedule_I_Condensed_Financial8

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Debt and Credit Agreements - Schedule of Debt Maturities (Details) (USD $)	Dec. 31, 2014		Jun. 30, 2014
Debt Instrument [Line Items]
2015	$1,739,000,000
2016	1,269,000,000
2017	2,400,000,000
2018	1,415,000,000
2019	982,000,000
Thereafter	13,599,000,000	[1]
Total	21,404,000,000		131,000,000
Exelon Corporate [Member]
Debt Instrument [Line Items]
2015	1,350,000,000
2016	0
2017	1,150,000,000
2018	0
2019	0
Thereafter	1,308,000,000
Total	$3,808,000,000
[1]	Includes $648 million due to ComEd, PECO and BGE financing trusts.

Schedule_I_Condensed_Financial9

Schedule I - Condensed Financial Information of Parent (Exelon Corporate) - Related Party Transactions - Summary of Related Party Transactions (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	($20)		$10		($91)
Exelon Corporate [Member]
Related Party Transaction [Line Items]
Operating and maintenance from affiliates	38		34		72
Interest income from affiliates, net	53		36		75
Total income (loss) in equity method investments	1,779		1,903		1,278
Cash contributions received from affiliates	1,370		1,175		2,074
Accounts receivable from affiliates	24		22
Receivables from affiliates	818		179
Investments in affiliates	26,670		26,390
Total receivable from affiliates (noncurrent)	943		1,522
Total payables to affiliates (noncurrent)	182		176
Exelon Corporate [Member] | Business Services Company [Member]
Related Party Transaction [Line Items]
Operating and maintenance from affiliates	38	[1]	34	[1]	72	[1]
Accounts receivable from affiliates	2	[1]	3	[1]
Receivables from affiliates	262	[1]	179	[1]
Investments in affiliates	193	[1]	201	[1]
Exelon Corporate [Member] | Exelon Energy Delivery Company LLC [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	958	[2]	834	[2]	713	[2]
Investments in affiliates	13,590	[2]	12,956	[2]
Exelon Corporate [Member] | Exelon Ventures Company LLC [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	926	[3]	1,076	[3]	564	[3]
Investments in affiliates	0	[3]	12,750	[3]
Exelon Corporate [Member] | UII LLC [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	-6		-2		25
Investments in affiliates	130		470
Exelon Corporate [Member] | Exelon Transmission Company LLC [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	-7		-5		-3
Investments in affiliates	1		3
Exelon Corporate [Member] | ExelonEnterprise [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	-1		0		0
Investments in affiliates	23		0
Exelon Corporate [Member] | Exelon Generation Consolidated [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	-91		0		0
Receivables from affiliates	556		0
Investments in affiliates	12,720		0
Exelon Corporate [Member] | Exelon Consolidations [Member]
Related Party Transaction [Line Items]
Total income (loss) in equity method investments	0	[4]	0	[4]	-21	[4]
Investments in affiliates	4		0
Exelon Corporate [Member] | Exelon Generation Co L L C [Member]
Related Party Transaction [Line Items]
Accounts receivable from affiliates	12		7
Total receivable from affiliates (noncurrent)	943		1,522
Exelon Corporate [Member] | Commonwealth Edison Co [Member]
Related Party Transaction [Line Items]
Accounts receivable from affiliates	3		9
Total payables to affiliates (noncurrent)	182		176
Exelon Corporate [Member] | PECO Energy Co [Member]
Related Party Transaction [Line Items]
Accounts receivable from affiliates	2		2
Exelon Corporate [Member] | Baltimore Gas and Electric Company [Member]
Related Party Transaction [Line Items]
Accounts receivable from affiliates	5		1
Exelon Corporate [Member] | VEBA [Member]
Related Party Transaction [Line Items]
Investments in affiliates	$9		$10
[1]	Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All services are provided at cost, including applicable overhead.
[2]	Exelon Energy Delivery Company, LLC consists of ComEd, PECO and BGE.
[3]	Exelon Ventures Company, LLC primarily consisted of Generation
[4]	Equity in earnings of investments for Exelon Consolidations represents the intercompany income component that offsets the corresponding intercompany expense at Generation for upgrades in transmission assets owned by ComEd, which are reflected as assets at Exelon Corporate.

Schedule_II_Valuation_and_Qual1

Schedule II - Valuation and Qualifying Accounts (Details) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Allowance for Uncollectible Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$272	[1]	$293	[1]	$199	[1]
Charged to Costs and Expenses	175	[1]	121	[1]	144	[1]
Charged to Other Accounts	69	[1]	37	[1],[2]	136	[1],[2],[3]
Deductions	205	[1],[4]	179	[1],[4]	186	[1],[4]
Balance at End of Period	311	[1]	272	[1]	293	[1]
Deferred Tax Valuation Allowance [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	13		36		10
Charged to Costs and Expenses	0		1		18
Charged to Other Accounts	37		0		18	[3]
Deductions	0		24		10
Balance at End of Period	50		13		36
Reserve for Obsolete Materials [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	58		53		60
Charged to Costs and Expenses	5		17		2
Charged to Other Accounts	34		0		2	[3]
Deductions	2		12		11
Balance at End of Period	95		58		53
Exelon Generation Co L L C [Member] | Allowance for Uncollectible Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	57		84		29
Charged to Costs and Expenses	14		-16		0
Charged to Other Accounts	8		0		66	[1]
Deductions	19		11		11
Balance at End of Period	60		57		84
Exelon Generation Co L L C [Member] | Deferred Tax Valuation Allowance [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	11		35		0
Charged to Costs and Expenses	0		1		17
Charged to Other Accounts	37		0		18	[1]
Deductions	0		25		0
Balance at End of Period	48		11		35
Exelon Generation Co L L C [Member] | Reserve for Obsolete Materials [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	55		50		59
Charged to Costs and Expenses	5		16		0
Charged to Other Accounts	32		0		2	[1]
Deductions	-1		11		11
Balance at End of Period	93		55		50
Commonwealth Edison Co [Member] | Allowance for Uncollectible Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	62		70		78
Charged to Costs and Expenses	45		33		42
Charged to Other Accounts	33	[5]	29	[5]	26	[5]
Deductions	56	[4]	70	[4]	76	[4]
Balance at End of Period	84		62		70
Commonwealth Edison Co [Member] | Reserve for Obsolete Materials [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	2		2		1
Charged to Costs and Expenses	0		1		1
Charged to Other Accounts	2		0		0
Deductions	2		1		0
Balance at End of Period	2		2		2
PECO Energy Co [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Noncurrent portion of uncollectible installment plan receivables	8		9		8
PECO Energy Co [Member] | Allowance for Uncollectible Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	107	[1]	99	[1]	92	[1]
Charged to Costs and Expenses	52	[1]	61	[1]	60	[1]
Charged to Other Accounts	11	[1],[6]	7	[1],[6]	8	[1],[6]
Deductions	70	[1],[4]	60	[1],[4]	61	[1],[4]
Balance at End of Period	100	[1]	107	[1]	99	[1]
PECO Energy Co [Member] | Reserve for Obsolete Materials [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	1		1		1
Charged to Costs and Expenses	0		0		0
Charged to Other Accounts	0		0		0
Deductions	0		0		0
Balance at End of Period	1		1		1
Baltimore Gas and Electric Company [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Charged to Costs and Expenses	19
Baltimore Gas and Electric Company [Member] | Allowance for Uncollectible Accounts [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	46		40		38
Charged to Costs and Expenses	64		43		45
Charged to Other Accounts	17	[6]	1		0
Deductions	60	[4]	38	[4]	43	[4]
Balance at End of Period	67		46		40
Baltimore Gas and Electric Company [Member] | Deferred Tax Valuation Allowance [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	1		1		0
Charged to Costs and Expenses	0		0		1
Charged to Other Accounts	0		0		0
Deductions	0		0		0
Balance at End of Period	1		1		1
Baltimore Gas and Electric Company [Member] | Reserve for Obsolete Materials [Member]
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	1		1		0
Charged to Costs and Expenses	0		0		1
Charged to Other Accounts	0		0		0
Deductions	1		0		0
Balance at End of Period	$0		$1		$1
[1]	Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $8 million, $9 million, and $8 million for the years ended December 31, 2014, 2013, and 2012, respectively.
[2]	Includes charges for late payments and non-service receivables.
[3]	Primarily represents the addition of Constellation’s and BGE’s results as of March 12, 2012, the date of the merger.
[4]	Write-off of individual accounts receivable.
[5]	Primarily charges for late payments and non-service receivables.
[6]	Primarily charges for late payments.

Uncategorized_Items

Uncategorized Items
[us-gaap_StockholdersEquity]	-1,000,000	1,588,000,000	5,003,000,000	2,086,000,000	-1,639,000,000	2,379,000,000	559,000,000