Exelon (EXC) 10-Q29 Oct 142014 Q3 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
Document and Entity Information	Sep. 30, 2014
Entity Registrant Name	'EXELON CORP
Entity Central Index Key	'0001109357
Document Type	'10-Q
Document Period End Date	30-Sep-14
Amendment Flag	'false
Document Fiscal Year Focus	'2014
Document Fiscal Period Focus	'Q3
Current Fiscal Year End Date	'--12-31
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	859,464,772
Exelon Generation Co L L C [Member]	'
Entity Registrant Name	'EXELON GENERATION CO LLC
Entity Central Index Key	'0001168165
Entity Filer Category	'Non-accelerated Filer
Commonwealth Edison Co [Member]	'
Entity Registrant Name	'COMMONWEALTH EDISON CO
Entity Central Index Key	'0000022606
Entity Filer Category	'Non-accelerated Filer
Entity Common Stock Shares Outstanding	127,016,934
PECO Energy Co [Member]	'
Entity Registrant Name	'PECO ENERGY CO
Entity Central Index Key	'0000078100
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	'0000009466
Entity Filer Category	'Non-accelerated Filer
Entity Common Stock Shares Outstanding	1,000

Consolidated_Statements_of_Ope

Consolidated Statements of Operations and Comprehensive Income (Unaudited) (USD $)	3 Months Ended				9 Months Ended
In Millions, except Per Share data, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Operating revenues [Abstract]	'		'		'		'
Operating revenues	'		'		'		$133
Operating revenues from affiliates	0	[1]	2	[1]	0	[2]	2	[2]
Operating revenues	6,912	[3]	6,502	[3]	20,173	[4]	18,725	[4]
Operating expenses	'		'		'		'
Purchased power and fuel	2,591		2,404		8,943		7,199
Purchased power and fuel from affiliates	57		339		456		944
Operating and maintenance	1,982		1,735		6,005		5,391
Depreciation and amortization	577		530		1,732		1,606
Taxes other than income	306		277		887		825
Total operating expenses	5,513		5,285		18,023		15,965
Equity in earnings (loss) of unconsolidated affiliates	1		37		-20		7
Gain on consolidation of CENG	0		0		261		0
Operating income	1,400		1,254		2,391		2,767
Other income and (deductions)	'		'		'		'
Interest expense, net	-247		-228		-691		-1,091
Interest expense to affiliates, net	-11		-6		-31		-19
Other, net	354		155		702		311
Total other income and (deductions)	96		-79		-20		-799
Income before income taxes	1,496		1,175		2,371		1,968
Income taxes	422		439		646		733
Net income	1,074		736		1,725		1,235
Net income (loss) attributable to noncontrolling interest, preferred security dividends and redemption and preference stock dividends	81		-2		121		11
Net income attributable to common shareholders	993		738		1,604		1,224
Pension and non-pension postretirement benefit plans:	'		'		'		'
Prior service (benefit) cost reclassified to periodic benefit cost	-11		1		-18		0
Actuarial loss reclassified to periodic cost	38		49		109		151
Pension and non-pension postretirement benefit plans valuation adjustment	-8		-8		240		69
Deferred compensation unit valuation adjustment	0		0		0		10
Unrealized (loss) on cash flow hedges	-19		-46		-92		-169
Unrealized gain (loss) on equity investments	-3		16		8		51
Unrealized (loss) on foreign currency translation	-5		0		-6		-5
Unrealized (loss) on marketable securities	-3		0		-2		-1
Reversal of CENG equity method AOCI	0		0		-116		0
Other comprehensive income (loss)	-11		12		123	[5]	106	[5]
Comprehensive income	1,063		748		1,848		1,341
Average shares of common stock outstanding:	'		'		'		'
Average common shares outstanding â€” basic	861		857		860		856
Average common shares outstanding â€” diluted	863		860		863		860
Earnings per average common share:	'		'		'		'
Earnings per share - basic (in usd per share)	$1.15		$0.86		$1.87		$1.43
Earnings per average common share - diluted	'		'		'		'
Earnings per share - diluted (in usd per share)	$1.15		$0.86		$1.86		$1.42
Dividends per common share (in usd per share)	$0.31		$0.31		$0.93		$1.15
Exelon Generation Co L L C [Member]	'		'		'		'
Operating revenues [Abstract]	'		'		'		'
Operating revenues	4,300		3,871		11,944		10,729
Operating revenues from affiliates	112		384		647		1,129
Operating revenues	4,412		4,255		12,591		11,858
Operating expenses	'		'		'		'
Purchased power and fuel from affiliates	59		342		476		953
Purchased power and fuel	1,821		1,837		6,595		5,341
Operating and maintenance	1,114		936		3,308		2,943
Operating and maintenance from affiliates	152		140		457		434
Depreciation and amortization	253		218		719		643
Taxes other than income	127		98		350		292
Total operating expenses	3,526		3,571		11,905		10,606
Equity in earnings (loss) of unconsolidated affiliates	1		37		-20		7
Gain on consolidation of CENG	0		0		261		0
Operating income	887		721		927		1,259
Other income and (deductions)	'		'		'		'
Interest expense, net	-77		-69		-224		-210
Interest expense to affiliates, net	-12		-13		-37		-47
Other, net	342		134		661		229
Total other income and (deductions)	253		52		400		-28
Income before income taxes	1,140		773		1,327		1,231
Income taxes	291		288		290		436
Net income	849		485		1,037		795
Net income (loss) attributable to noncontrolling interests	78		-5		111		-6
Net income attributable to membership interest	771		490		926		801
Pension and non-pension postretirement benefit plans:	'		'		'		'
Unrealized (loss) on cash flow hedges	-16		-49		-86		-316
Unrealized gain (loss) on equity investments	-3		16		8		52
Unrealized (loss) on foreign currency translation	-5		1		-6		-5
Unrealized (loss) on marketable securities	-2		0		-3		-1
Reversal of CENG equity method AOCI	0		0		-116		0
Other comprehensive income (loss)	-26		-32		-203	[5]	-270	[5]
Comprehensive income	823		453		834		525
Commonwealth Edison Co [Member]	'		'		'		'
Operating revenues [Abstract]	'		'		'		'
Operating revenues	1,221		1,155		3,482		3,393
Operating revenues from affiliates	1		1		2		2
Operating revenues	1,222		1,156		3,484		3,395
Operating expenses	'		'		'		'
Purchased power and fuel	325		158		741		522
Purchased power and fuel from affiliates	1		143		174		409
Operating and maintenance	320		296		923		907
Operating and maintenance from affiliates	39		37		117		113
Depreciation and amortization	174		164		521		501
Taxes other than income	76		80		225		225
Total operating expenses	935		878		2,701		2,677
Operating income	287		278		783		718
Other income and (deductions)	'		'		'		'
Interest expense, net	-78		-71		-231		-493
Interest expense to affiliates, net	-3		-3		-10		-10
Other, net	4		7		14		18
Total other income and (deductions)	-77		-67		-227		-485
Income before income taxes	210		211		556		233
Income taxes	84		85		221		93
Net income	126		126		335		140
Pension and non-pension postretirement benefit plans:	'		'		'		'
Comprehensive income	126		126		335		140
PECO Energy Co [Member]	'		'		'		'
Operating revenues [Abstract]	'		'		'		'
Operating revenues	693		727		2,342		2,294
Operating revenues from affiliates	0		1		1		1
Operating revenues	693		728		2,343		2,295
Operating expenses	'		'		'		'
Purchased power and fuel	228		207		798		632
Purchased power and fuel from affiliates	27		82		162		321
Operating and maintenance	181		162		597		480
Operating and maintenance from affiliates	23		24		71		74
Depreciation and amortization	59		57		176		171
Taxes other than income	42		41		122		121
Total operating expenses	560		573		1,926		1,799
Equity in earnings (loss) of unconsolidated affiliates	'		'		'		0
Operating income	133		155		417		496
Other income and (deductions)	'		'		'		'
Interest expense, net	-26		-26		-76		-77
Interest expense to affiliates, net	-3		-3		-9		-9
Other, net	2		1		5		4
Total other income and (deductions)	-27		-28		-80		-82
Income before income taxes	106		127		337		414
Income taxes	25		35		82		122
Net income	81		92		255		292
Preferred security dividends and redemption	0		0		0		7
Net income attributable to common shareholders	81		92		255		285
Pension and non-pension postretirement benefit plans:	'		'		'		'
Comprehensive income	81		92		255		292
Baltimore Gas and Electric Company [Member]	'		'		'		'
Operating revenues [Abstract]	'		'		'		'
Operating revenues	694		735		2,383		2,261
Operating revenues from affiliates	3		2		21		10
Operating revenues	697		737		2,404		2,271
Operating expenses	'		'		'		'
Purchased power and fuel	216		202		808		703
Purchased power and fuel from affiliates	81		144		286		356
Operating and maintenance	142		125		468		391
Operating and maintenance from affiliates	23		21		73		59
Depreciation and amortization	78		78		275		252
Taxes other than income	55		53		168		162
Total operating expenses	595		623		2,078		1,923
Equity in earnings (loss) of unconsolidated affiliates	'		'		'		0
Operating income	102		114		326		348
Other income and (deductions)	'		'		'		'
Interest expense, net	-22		-25		-69		-82
Interest expense to affiliates, net	-4		-4		-12		-12
Other, net	4		4		14		13
Total other income and (deductions)	-22		-25		-67		-81
Income before income taxes	80		89		259		267
Income taxes	31		36		103		107
Net income	49		53		156		160
Preferred security dividends and redemption	3		3		10		10
Net income attributable to common shareholders	46		50		146		150
Pension and non-pension postretirement benefit plans:	'		'		'		'
Comprehensive income	$49		$53		$156		$160

[1]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generationâ€™s sale of certain products and services by and between Exelonâ€™s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
[2]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generationâ€™s sale of certain products and services by and between Exelonâ€™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.
[3]	For the three months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.
[4]	For the nine months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended SeptemberÂ 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.
[5]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (Unaudited) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
	Sep. 30, 2014	Sep. 30, 2013	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Commonwealth Edison Co [Member]	Commonwealth Edison Co [Member]	PECO Energy Co [Member]	PECO Energy Co [Member]	Baltimore Gas and Electric Company [Member]	Baltimore Gas and Electric Company [Member]
Net Cash Provided by (Used in) Operating Activities [Abstract]	'	'	'	'	'	'	'	'	'	'
Net income	$1,725	$1,235	$1,037	$795	$335	$140	$255	$292	$156	$160
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	2,856	2,844	1,853	1,937	521	501	176	171	275	252
Impairment of long-lived assets	162	171	138	157	'	'	'	'	'	'
Gain on consolidation of CENG	-268	0	-268	0	'	'	'	'	'	'
Gain on sale of assets	-356	-17	-355	-13	'	'	'	'	'	'
Deferred income taxes and amortization of investment tax credits	459	-164	154	183	154	-152	7	35	57	105
Net fair value changes related to derivatives	522	-229	509	-222	'	'	'	'	'	'
Net realized and unrealized gains on nuclear decommissioning trust fund investments	-141	-95	-141	-95	'	'	'	'	'	'
Other non-cash operating activities	698	584	251	231	116	26	70	84	129	105
Changes in assets and liabilities:	'	'	'	'	'	'	'	'	'	'
Accounts receivable	198	54	153	57	-109	-21	63	41	101	-28
Receivables from and payables to affiliates, net	'	'	72	2	-55	-32	-20	-25	-11	-12
Inventories	-316	-103	-286	-81	-12	-12	5	4	-21	-15
Accounts payable, accrued expenses and other current liabilities	-322	-243	-311	-162	59	48	19	9	-50	-5
Option premiums received (paid), net	21	-38	21	-38	'	'	'	'	'	'
Counterparty collateral posted, net	-615	-73	-634	-123	'	'	'	'	16	0
Income taxes	72	863	172	315	15	262	16	66	53	6
Pension and non-pension postretirement benefit contributions	-516	-360	-214	-123	-237	-120	-12	-10	-13	-16
Other assets and liabilities	-536	-35	-367	-163	62	210	-75	-47	-67	-119
Net cash flows provided by operating activities	3,643	4,394	1,784	2,657	849	850	504	620	625	433
Cash flows from investing activities	'	'	'	'	'	'	'	'	'	'
Capital expenditures	-4,114	-3,887	-1,961	-1,995	-1,173	-1,074	-461	-374	-458	-391
Proceeds from nuclear decommissioning trust fund sales	5,464	3,344	5,464	3,344	'	'	'	'	'	'
Investment in nuclear decommissioning trust funds	-5,550	-3,518	-5,550	-3,518	'	'	'	'	'	'
Acquisition of businesses	-67	0	-67	0	'	'	'	'	'	'
Changes in intercompany money pool	'	'	'	'	'	'	0	-1	'	'
Proceeds from sale of long-lived assets	660	32	660	32	'	'	'	'	'	'
Proceeds from termination of direct financing lease investment	335	0	'	'	'	'	'	'	'	'
Proceeds from sale of investments	7	20	'	'	7	5	'	'	'	'
Purchases of investments	-3	-3	'	'	-3	-3	'	'	'	'
Cash consolidated from CENG	129	0	129	0	'	'	'	'	'	'
Change in restricted cash	-151	-23	-116	-30	-2	-3	0	-1	-37	-20
Other investing activities	-86	65	-34	18	23	33	9	8	15	2
Changes in Exelon intercompany money pool	'	'	44	0	'	'	'	'	'	'
Net cash flows used in investing activities	-3,376	-3,970	-1,431	-2,149	-1,148	-1,042	-452	-368	-480	-409
Net Cash Provided by (Used in) Financing Activities [Abstract]	'	'	'	'	'	'	'	'	'	'
Payment of accounts receivable agreement	0	-210	'	'	'	'	'	'	'	'
Changes in short-term borrowings	236	205	7	12	344	153	'	'	-115	40
Issuance of long-term debt	3,212	2,031	1,112	831	650	350	300	550	0	300
Retirement of long-term debt	-1,214	-1,156	-552	-471	-617	-252	'	'	-35	-433
Redemption of preferred securities	0	-93	'	'	'	'	0	-93	'	'
Distributions to noncontrolling interest of consolidated VIE	-415	0	-415	0	'	'	'	'	'	'
Dividends paid on common stock	-799	-981	'	'	-230	-165	-240	-248	'	'
Proceeds from employee stock plans	25	40	'	'	'	'	'	'	'	'
Other financing activities	-158	-102	-67	-73	-8	-4	-7	-3	11	-3
Payment of accounts receivable agreement	'	'	'	'	'	'	0	-210	'	'
Distribution to member	'	'	-440	-550	'	'	'	'	'	'
Contributions from parent	'	'	'	'	168	0	24	0	0	'
Dividends paid on preferred securities	'	'	'	'	'	'	0	-1	-10	-10
Contribution from member	'	'	55	0	'	'	'	'	'	'
Net cash flows provided by (used in) financing activities	887	-266	-300	-251	307	82	77	-5	-149	-106
Increase in cash and cash equivalents	1,154	158	53	257	8	-110	129	247	-4	-82
Cash and cash equivalents at beginning of period	1,609	1,486	1,258	671	36	144	217	362	31	89
Cash and cash equivalents at end of period	$2,763	$1,644	$1,311	$928	$44	$34	$346	$609	$27	$7

Consolidated_Balance_Sheets_Un

Consolidated Balance Sheets (Unaudited) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Assets, Current [Abstract]	'		'
Cash and cash equivalents	$2,763		$1,609
Restricted cash and cash equivalents	318		167
Accounts receivable, net	'		'
Customer	2,815		2,981
Other	898		1,175
Mark-to-market derivative assets	744		727
Unamortized energy contract assets	225		374
Inventories, net	'		'
Fossil fuel	546		276
Materials and supplies	1,045		829
Deferred income taxes	38		573
Regulatory assets	774		760
Assets held for sale	649		14
Other	1,022		652
Total current assets	11,837		10,137
Property, plant and equipment, net	51,630		47,330
Deferred debits and other assets	'		'
Regulatory assets	5,589		5,910
Nuclear decommissioning trust funds	10,349		8,071
Investments	562		1,165
Investments in affiliates	26		22
Investment in CENG	0		1,925
Goodwill	2,672		2,625
Mark-to-market derivative assets	524		607
Unamortized energy contracts assets	571		710
Pledged assets for Zion Station decommissioning	365		458
Other	1,139		964
Total deferred debits and other assets	21,797		22,457
Total assets	85,264		79,924
Liabilities, Current [Abstract]	'		'
Short-term borrowings	562		341
Long-term debt due within one year	2,064		1,509
Accounts payable	2,502		2,484
Accrued expenses	1,462		1,633
Payables to affiliates	22		116
Deferred income taxes	26		40
Regulatory liabilities	364		327
Mark-to-market derivative liabilities (current liabilities)	249		159
Unamortized energy contract liabilities	195		261
Other	985		858
Total current liabilities	8,431		7,728
Long-term debt	19,200		17,623
Long-term debt to financing trusts	648		648
Deferred credits and other liabilities	'		'
Deferred income taxes and unamortized investment tax credits	13,181		12,905
Asset retirement obligations	7,003		5,194
Pension obligations	1,809		1,876
Non-pension postretirement benefit obligations	1,459		2,190
Spent nuclear fuel obligation	1,021		1,021
Regulatory liabilities	4,593		4,388
Mark-to-market derivative liabilities (noncurrent liabilities)	291		300
Unamortized energy contract liabilities	214		266
Payable for Zion Station decommissioning	260		305
Other	2,104		2,540
Total deferred credits and other liabilities	31,935		30,985
Total liabilities	60,214	[1]	56,984	[1]
Commitments and contingencies	'		'
Stockholders' Equity Attributable to Parent [Abstract]	'		'
Common stock	16,679		16,741
Treasury stock, at cost (35 shares at both September 30, 2014 and December 31, 2013)	-2,327		-2,327
Retained earnings	11,160		10,358
Accumulated other comprehensive loss, net	-1,917	[2]	-2,040	[2]
Total shareholdersb equity	23,595		22,732
BGE preference stock not subject to mandatory redemption	193		193
Noncontrolling interest	1,262		15
Total equity	25,050		22,940
Total liabilities and shareholdersb equity	85,264		79,924
Memberbs equity	'		'
Accumulated other comprehensive loss, net	-1,917	[2]	-2,040	[2]
Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]	'		'
Deferred debits and other assets	'		'
Total assets	7,773		1,755
Deferred credits and other liabilities	'		'
Total liabilities	2,594		658
Exelon Generation Co L L C [Member]	'		'
Assets, Current [Abstract]	'		'
Cash and cash equivalents	1,311		1,258
Restricted cash and cash equivalents	187		71
Accounts receivable, net	'		'
Customer	1,705		1,689
Other	325		353
Mark-to-market derivative assets	744		727
Unamortized energy contract assets	225		374
Receivables from affiliates	56		108
Receivable from Exelon intercompany money pool	0		44
Inventories, net	'		'
Fossil fuel	426		164
Materials and supplies	865		671
Deferred income taxes	144		475
Assets held for sale	649		14
Other	821		491
Total current assets	7,458		6,439
Property, plant and equipment, net	23,143		20,111
Deferred debits and other assets	'		'
Nuclear decommissioning trust funds	10,349		8,071
Investments	154		400
Investment in CENG	0		1,925
Goodwill	47		0
Mark-to-market derivative assets	507		600
Unamortized energy contracts assets	571		710
Pledged assets for Zion Station decommissioning	365		458
Other	714		645
Prepaid pension asset	1,711		1,873
Total deferred debits and other assets	14,418		14,682
Total assets	45,019		41,232
Liabilities, Current [Abstract]	'		'
Short-term borrowings	14		22
Long-term debt due within one year	73		561
Accounts payable	1,318		1,322
Accrued expenses	840		976
Payables to affiliates	560		0
Deferred income taxes	1		25
Mark-to-market derivative liabilities (current liabilities)	235		142
Unamortized energy contract liabilities	192		249
Other	478		389
Payables to affiliates	124		181
Total current liabilities	3,835		3,867
Long-term debt	6,741		5,645
Long-term debt to affiliate	946		1,523
Deferred credits and other liabilities	'		'
Deferred income taxes and unamortized investment tax credits	6,202		6,295
Asset retirement obligations	6,853		5,047
Non-pension postretirement benefit obligations	949		850
Spent nuclear fuel obligation	1,021		1,021
Mark-to-market derivative liabilities (noncurrent liabilities)	104		120
Unamortized energy contract liabilities	214		266
Payable for Zion Station decommissioning	260		305
Other	718		811
Payables to affiliates	2,850		2,740
Total deferred credits and other liabilities	19,171		17,455
Total liabilities	30,693	[3]	28,490	[3]
Commitments and contingencies	'		'
Stockholders' Equity Attributable to Parent [Abstract]	'		'
Accumulated other comprehensive loss, net	11	[2]	214	[2]
Noncontrolling interest	1,263		17
Memberbs equity	'		'
Membership interest	8,953		8,898
Undistributed earnings	4,099		3,613
Accumulated other comprehensive loss, net	11	[2]	214	[2]
Total member's equity	13,063		12,725
Total equity	14,326		12,742
Total liabilities and equity	45,019		41,232
Exelon Generation Co L L C [Member] \| Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]	'		'
Deferred debits and other assets	'		'
Total assets	7,703		1,695
Deferred credits and other liabilities	'		'
Total liabilities	2,338		362
Commonwealth Edison Co [Member]	'		'
Assets, Current [Abstract]	'		'
Cash and cash equivalents	44		36
Restricted cash and cash equivalents	4		2
Accounts receivable, net	'		'
Customer	486		451
Other	455		581
Receivables from affiliates	3		3
Inventories, net	'		'
Regulatory assets	330		329
Other	37		29
Inventories, net	121		109
Total current assets	1,480		1,540
Property, plant and equipment, net	15,389		14,666
Deferred debits and other assets	'		'
Regulatory assets	928		933
Investments	0		5
Investments in affiliates	6		6
Goodwill	2,625		2,625
Other	278		291
Receivable from affiliate	2,551		2,469
Prepaid pension asset	1,588		1,583
Total deferred debits and other assets	7,976		7,912
Total assets	24,845		24,118
Liabilities, Current [Abstract]	'		'
Short-term borrowings	528		184
Long-term debt due within one year	260		617
Accounts payable	571		449
Accrued expenses	254		307
Payables to affiliates	28		83
Deferred income taxes	117		16
Regulatory liabilities	187		170
Mark-to-market derivative liabilities (current liabilities)	14		17
Other	73		72
Customer deposits	128		133
Total current liabilities	2,160		2,048
Long-term debt	5,448		5,058
Long-term debt to financing trusts	206		206
Deferred credits and other liabilities	'		'
Deferred income taxes and unamortized investment tax credits	4,170		4,116
Asset retirement obligations	103		99
Non-pension postretirement benefit obligations	278		381
Regulatory liabilities	3,643		3,512
Mark-to-market derivative liabilities (noncurrent liabilities)	164		176
Other	868		994
Total deferred credits and other liabilities	9,226		9,278
Total liabilities	17,040		16,590
Commitments and contingencies	'		'
Stockholders' Equity Attributable to Parent [Abstract]	'		'
Common stock	1,588		1,588
Retained earnings	855		750
Other paid-in capital	5,362		5,190
Total shareholdersb equity	7,805		7,528
Total liabilities and shareholdersb equity	24,845		24,118
PECO Energy Co [Member]	'		'
Assets, Current [Abstract]	'		'
Cash and cash equivalents	346		217
Restricted cash and cash equivalents	2		2
Accounts receivable, net	'		'
Customer	258		360
Other	105		103
Receivables from affiliates	3		4
Inventories, net	'		'
Fossil fuel	52		60
Materials and supplies	24		21
Deferred income taxes	83		83
Regulatory assets	21		17
Other	44		36
Prepaid utility taxes	44		3
Total current assets	982		906
Property, plant and equipment, net	6,648		6,384
Deferred debits and other assets	'		'
Regulatory assets	1,520		1,448
Investments	23		23
Investments in affiliates	8		8
Other	39		38
Receivable from affiliate	479		447
Prepaid pension asset	352		363
Total deferred debits and other assets	2,421		2,327
Total assets	10,051		9,617
Liabilities, Current [Abstract]	'		'
Long-term debt due within one year	250		250
Accounts payable	303		285
Accrued expenses	121		106
Payables to affiliates	38		58
Regulatory liabilities	79		106
Other	26		37
Customer deposits	53		49
Total current liabilities	870		891
Long-term debt	2,246		1,947
Long-term debt to financing trusts	184		184
Deferred credits and other liabilities	'		'
Deferred income taxes and unamortized investment tax credits	2,574		2,487
Asset retirement obligations	30		29
Non-pension postretirement benefit obligations	291		286
Regulatory liabilities	655		629
Other	97		99
Total deferred credits and other liabilities	3,647		3,530
Total liabilities	6,947		6,552
Commitments and contingencies	'		'
Stockholders' Equity Attributable to Parent [Abstract]	'		'
Common stock	2,439		2,415
Retained earnings	664		649
Accumulated other comprehensive loss, net	1	[2]	1	[2]
Total shareholdersb equity	3,104		3,065
Total liabilities and shareholdersb equity	10,051		9,617
Memberbs equity	'		'
Accumulated other comprehensive loss, net	1	[2]	1	[2]
Baltimore Gas and Electric Company [Member]	'		'
Assets, Current [Abstract]	'		'
Cash and cash equivalents	27		31
Restricted cash and cash equivalents	65		28
Accounts receivable, net	'		'
Customer	366		480
Other	90		114
Income taxes receivable	0		30
Inventories, net	'		'
Fossil fuel	68		53
Materials and supplies	34		28
Deferred income taxes	5		2
Regulatory assets	206		181
Other	6		7
Prepaid utility taxes	2		57
Total current assets	869		1,011
Property, plant and equipment, net	6,126		5,864
Deferred debits and other assets	'		'
Regulatory assets	500		524
Investments	4		5
Investments in affiliates	8		8
Other	26		26
Prepaid pension asset	382		423
Total deferred debits and other assets	920		986
Total assets	7,915		7,861
Liabilities, Current [Abstract]	'		'
Short-term borrowings	20		135
Long-term debt due within one year	72		70
Accounts payable	207		270
Accrued expenses	167		111
Payables to affiliates	56		55
Deferred income taxes	52		27
Regulatory liabilities	45		48
Other	45		35
Customer deposits	93		76
Total current liabilities	757		827
Long-term debt	1,904		1,941
Long-term debt to financing trusts	258		258
Deferred credits and other liabilities	'		'
Deferred income taxes and unamortized investment tax credits	1,805		1,773
Asset retirement obligations	18		19
Non-pension postretirement benefit obligations	213		217
Regulatory liabilities	199		204
Other	60		67
Total deferred credits and other liabilities	2,295		2,280
Total liabilities	5,214	[4]	5,306	[4]
Stockholders' Equity Attributable to Parent [Abstract]	'		'
Common stock	1,360		1,360
Retained earnings	1,151		1,005
Total shareholdersb equity	2,511		2,365
BGE preference stock not subject to mandatory redemption	190		190
Total equity	2,701		2,555
Total liabilities and shareholders' equity	7,915		7,861
Baltimore Gas and Electric Company [Member] \| Variable Interest Entity, Primary Beneficiary, Aggregated Disclosure [Member]	'		'
Deferred debits and other assets	'		'
Total assets	50		31
Deferred credits and other liabilities	'		'
Total liabilities	$237		$269

[1]	Exelonbs consolidated assets include $7,773 million and $1,755 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelonbs consolidated liabilities include $2,594 million and $658 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.
[2]	All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
[3]	Generationbs consolidated assets include $7,703 million and $1,695 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generationbs consolidated liabilities include $2,338 million and $362 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.
[4]	BGEbs consolidated assets include $50 million and $31 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of BGEbs consolidated VIE that can only be used to settle the liabilities of the VIE. BGEbs consolidated liabilities include $237 million and $269 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of BGEbs consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Consolidated_Balance_Sheets_Un1

Consolidated Balance Sheets (Unaudited) (Parenthetical)	Sep. 30, 2014	Dec. 31, 2013
Stockholders' Equity Attributable to Parent [Abstract]	'	'
Common Stock, Shares Authorized	2,000,000,000	2,000,000,000
Treasury Stock, Shares held	35,000,000	35,000,000

Consolidated_Statement_of_Chan

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

Total

Common Stock [Member]

Treasury Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Preference Stock Not Subject To Mandatory Redemption [Member]

Exelon Generation Co L L C [Member]

PECO Energy Co [Member]

Commonwealth Edison Co [Member]

Baltimore Gas and Electric Company [Member]

In Millions, except Share data in Thousands, unless otherwise specified

Undistributed Earnings [Member]

Membership Interest [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Noncontrolling Interest [Member]

Common Stock [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income (Loss) [Member]

Common Stock [Member]

Other Additional Capital [Member]

Retained Earnings, Unappropriated [Member]

Retained Earnings, Appropriated [Member]

Common Stock [Member]

Nonredeemable Preferred Stock [Member]

Retained Earnings [Member]

Beginning Balance at Dec. 31, 2013

$22,732

$3,065

$2,415

$649

$7,528

$1,588

$5,190

($1,639)

$2,389

$2,365

$1,360

$190

$1,005

Beginning Balance at Dec. 31, 2013

22,940

16,741

-2,327

10,358

-2,040

193

2,555

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

892,034

Beginning Balance at Dec. 31, 2013

12,742

3,613

8,898

214

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

Net income

1,725

1,604

111

1,037

926

111

255

335

156

Noncontrolling Interest, Increase from Sale of Parent Equity Interest

Long-term incentive plan activity (in shares)

1,439

Long-term incentive plan activity

Employee stock purchase plan issuances (in shares)

735

Employee stock purchase plan issuances

Appropriation of retained earnings for future dividends

-335

335

Tax benefit on stock compensation

-7

Common stock dividends

-802

-10

-240

-230

Contribution from parent

168

Distribution to members

-440

Allocation of tax benefit from members

Preferred stock redemption premium

-6

Allocation of tax benefit from parent

Consolidated VIE dividend to non-controlling interest

415

-415

Reversal of CENG equity method AOCI, net of income taxes of $77

-116

Minority Interest Increase From Acquisition

Reversal of CENG equity method AOCI

-116

Preferred security dividends

-10

Long-term Debt, Excluding Current Maturities

-131

Noncontrolling interest acquired

1,548

Increase (Decrease) in Pension and Postretirement Obligations

Other comprehensive loss, net of income taxes of $53

239

-87

Other comprehensive income (loss), net of tax

[1]

123

-203

Ending Balance at Sep. 30, 2014

23,595

3,104

2,439

664

7,805

1,588

5,362

-1,639

2,494

2,511

1,360

190

1,151

Ending Balance at Sep. 30, 2014

25,050

16,679

-2,327

11,160

-1,917

1,262

193

2,701

Ending Balance (in shares) at Sep. 30, 2014

894,208

Ending Balance at Sep. 30, 2014

14,326

4,099

8,953

1,263

Beginning Balance at Jun. 30, 2014

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

Net income

1,074

849

126

Reversal of CENG equity method AOCI

Other comprehensive income (loss), net of tax

-11

-26

Ending Balance at Sep. 30, 2014

23,595

3,104

7,805

1,588

2,511

1,360

Ending Balance at Sep. 30, 2014

25,050

-2,327

2,701

Ending Balance (in shares) at Sep. 30, 2014

894,208

Ending Balance at Sep. 30, 2014

$14,326

[1]

All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

Consolidated_Statement_of_Chan1

Consolidated Statement of Changes in Shareholders Equity (Unaudited) (Parenthetical) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
Income taxes	$646
Accumulated Other Comprehensive Income (Loss) [Member]	'
Income taxes	-154
Exelon Generation Co L L C [Member]	'
Income taxes	290
Exelon Generation Co L L C [Member] \| Accumulated Other Comprehensive Income (Loss) [Member]	'
Income taxes	53
PECO Energy Co [Member]	'
Income taxes	82
Commonwealth Edison Co [Member]	'
Income taxes	221
Baltimore Gas and Electric Company [Member]	'
Income taxes	103
Constellation Energy Group LLC [Member] \| Accumulated Other Comprehensive Income (Loss) [Member]	'
Income taxes	77
Constellation Energy Group LLC [Member] \| Exelon Generation Co L L C [Member] \| Accumulated Other Comprehensive Income (Loss) [Member]	'
Income taxes	$77

Basis_of_Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)	'
	Basis of Presentation (Exelon, Generation, ComEd, PECO and BGE)
	Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution businesses. 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 6 — 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.
	Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
	Certain prior year amounts in ComEd's and PECO's Consolidated Balance Sheets have been reclassified between line items for comparative purposes. The reclassifications did not affect any of the Registrants' net income or cash flows from operating activities.
	Certain prior year amounts in the Exelon, Generation and BGE Consolidated Statement of Operations have been reclassified between line items for correction of prior period classification errors. Exelon corrected the presentation of Purchased power and fuel from affiliates of $339 million and $944 million on its Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2013, respectively. Generation corrected the presentation of Purchased power and fuel from affiliates of $342 million and $953 million on its Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2013, respectively. Generation also corrected the presentation of Interest expense to affiliates, net of $13 million and $47 million on its Statement of Operations and Comprehensive Income for the three and nine months ended September 30, 2013, respectively. BGE corrected its presentation of Interest expense to affiliates, net of $4 million and $12 million on the Statement of Operations and Comprehensive Income for the three and nine months ended September 30, 2013, respectively.
	The accompanying consolidated financial statements as of September 30, 2014 and 2013 and for the nine months then ended are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise disclosed. The December 31, 2013 Consolidated Balance Sheets were obtained from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2014. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. These notes should be read in conjunction with the Notes to Combined Consolidated Financial Statements of all Registrants included in ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA of their respective 2013 Form 10-K Reports.

New_Accounting_Pronouncements_

New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)	'
	New Accounting Pronouncements (Exelon, Generation, ComEd, PECO and BGE)
	The following recently issued accounting standards were adopted by or are effective for the Registrants during 2014.
	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.

	The following recently issued accounting standards are 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)	9 Months Ended
	Sep. 30, 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 September 30, 2014 and December 31, 2013, Exelon, Generation, and BGE collectively consolidated six and four VIEs or VIE groups, respectively, for which the applicable Registrant was the primary beneficiary (see Consolidated Variable Interest Entities below). As of September 30, 2014 and December 31, 2013, the Registrants had significant interests in eight other VIEs for which the Registrants do not have the power to direct the entities’ activities and, accordingly, were not the primary beneficiary.
	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 nine months ended September 30, 2014. For additional information on this transaction refer to Note 6 — Investment in Constellation Energy Nuclear Group, LLC.
	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. 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.
	Consolidated Variable Interest Entities
	Exelon, Generation and BGE’s consolidated VIEs consist of:


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


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


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


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


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


	•	CENG.
	As of September 30, 2014 and December 31, 2013, ComEd and PECO do not have any material consolidated VIEs.

	As of September 30, 2014 and December 31, 2013, Exelon, Generation, and BGE provided the following support to their respective consolidated VIEs:


	•	In the case of BondCo, BGE is required to remit all payments it receives from all residential customers through non-bypassable, rate stabilization charges to BondCo. During the three and nine months ended September 30, 2014, BGE remitted $21 million and $63 million, respectively, to BondCo. During the three and nine months ended September 30, 2013, BGE remitted $24 million and $63 million, respectively, to BondCo.


	•	Generation provides operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and provides limited recourse related to the Antelope Valley project.


	•	Generation and Exelon, where indicated, provide the following support to CENG (see Note 25—Related Party Transactions of the Exelon 2013 Form 10-K and Note 6—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 will purchase 85% of the available output generated by the CENG nuclear plants for the remainder of 2014 and 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 6 — 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 18 — Commitments and Contingencies for more details),


	•	in connection with CENG’s severance obligations, Generation has agreed to reimburse CENG for a total of approximately $6 million of the severance benefits paid or to be paid in 2013 through 2016. As of September 30, 2014, the remaining obligation is approximately $4 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 18 — 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 18 — Commitments and Contingencies for more details), and


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


•	Generation provides approximately $4 million in credit support for the retail power companies for which Generation is the sole supplier of energy, and


•	Generation provides a $75 million parental guarantee to the third-party gas supplier in support of its retail gas group.

For each of the consolidated VIEs, except as otherwise noted:


•	The assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;


•	Exelon, Generation and BGE did not provide any additional material financial support to the VIEs;


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


•	the creditors of the VIEs did not have recourse to Exelon’s, Generation’s or BGE’s general credit.
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in Exelon’s, Generation’s, and BGE’s consolidated financial statements at September 30, 2014 and December 31, 2013 are as follows:


	30-Sep-14									31-Dec-13
	Exelon(a)(b)			Generation(b)			BGE			Exelon(a)			Generation			BGE
Current assets	$	1,071		$	1,018		$	47		$	484		$	446		$	28

Noncurrent assets	7,384			7,367			3			1,905			1,884			3

Total assets	$	8,455		$	8,385		$	50		$	2,389		$	2,330		$	31


Current liabilities	$	545		$	460		$	79		$	566		$	481		$	74

Noncurrent liabilities	2,671			2,499			158			774			562			195

Total liabilities	$	3,216		$	2,959		$	237		$	1,340		$	1,043		$	269

_______________________

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

(b)	Includes total assets of $6.0 billion and total liabilities of $2.0 billion due to the consolidation of CENG beginning April 1, 2014. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of September 30, 2014 and December 31, 2013, these assets and liabilities primarily consisted of the following:


		September 30, 2014									December 31, 2013
		Exelon			Generation			BGE			Exelon			Generation				BGE
Cash and cash equivalents		$	372		$	372		$	—		$	62		$	62		$	—

Restricted cash			142			95			47			80			52			28

Accounts receivable, net
	Customer		213			213			—			260			260			—

	Other		53			53			—			—			—			—

Mark-to-market derivatives assets			40			40			—			21			21			—

Inventory

	Materials and supplies		171			171			—			—			—			—

Other current assets			53			47			—			34			23			—

	Total current assets		1,044			991			47			457			418			28


	Property, plant and equipment, net		4,517			4,517			—			1,171			1,171			—

	Nuclear decommissioning trust funds		2,034			2,034			—			—			—			—

	Goodwill		46			46			—			—			—			—

	Other noncurrent assets		132			115			3			127			106			3

	Total noncurrent assets		6,729			6,712			3			1,298			1,277			3

	Total assets	$	7,773		$	7,703		$	50		$	1,755		$	1,695		$	31


Short-term borrowings		$	1		$	1		$	—		$	—		$	—		$	—

Long-term debt due within one year			83			5			72			85			5			70

Accounts payable			264			264			—			170			170			—

Accrued expenses			78			72			7			26			22			4

Mark-to-market derivative liabilities			18			18			—			29			29			—

Other current liabilities			53			53			—			10			10			—

	Total current liabilities		497			413			79			320			236			74


	Long-term debt		256			84			158			298			86			195

	Asset retirement obligations		1,654			1,654			—			—			—			—

	Pension obligation(a)		8			8			—			—			—			—

	Other noncurrent liabilities		179			179			—			40			40			—

	Noncurrent liabilities		2,097			1,925			158			338			126			195

	Total liabilities	$	2,594		$	2,338		$	237		$	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 — 13 - Retirement Benefits for additional details.

Unconsolidated Variable Interest Entities
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected on Exelon’s and Generation’s Consolidated Balance Sheets in Investments in affiliates, 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.

The Registrants’ unconsolidated VIEs consist of:


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


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


•	Equity investments in energy development projects and energy generating facilities for which Generation has concluded that consolidation is not required.
As of September 30, 2014 and December 31, 2013, Exelon and Generation had significant unconsolidated variable interests in eight VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. The number of unconsolidated VIEs did not change overall; however, during the nine months ended September 30, 2014 Generation made an investment in a new unconsolidated VIE and executed an energy purchase and sale agreement with a new unconsolidated VIE, offset by the sale of Generation’s ownership interest in two unconsolidated VIEs. The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:


30-Sep-14	Commercial			Equity			Total
	Agreement			Investment
	VIEs			VIEs
Total assets(a)	$	115		$	307		$	422

Total liabilities(a)	2			115			117

Exelon's ownership interest in VIE(a)	—			62			62

Other ownership interests in VIE(a)	113			130			243

Registrants’ maximum exposure to loss:

Carrying amount of equity method investments	—			66			66

Contract intangible asset	9			—			9

Debt and payment guarantees	—			3			3

Net assets pledged for Zion Station decommissioning(b)	31			—			31



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 $365 million and $458 million as of September 30, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $334 million and $414 million as of September 30, 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 of the unconsolidated VIEs, Exelon and Generation assess the risk of a loss equal to their maximum exposure to be remote and, accordingly, Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss. In addition, there are no material agreements with, or commitments by, third parties that would affect the fair value or risk of their variable interests in these VIEs.

Mergers_Acquisitions_and_Dispo

Mergers, Acquisitions, and Dispositions	9 Months Ended
	Sep. 30, 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 purchased $90 million of a new class of nonvoting, nonconvertible and nontransferable preferred securities of PHI, in the second quarter of 2014, with additional investments of $18 million to be made quarterly up to a maximum aggregate investment of $180 million. PHI has the right to redeem the preferred securities at its option for the purchase price paid plus accrued dividends, if any. The $108 million of PHI preferred securities are included in Other non-current assets on Exelon's Consolidated Balance Sheet as of September 30, 2014. 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.

	On September 23, 2014, PHI stockholders overwhelmingly approved the merger of PHI and Exelon. Completion of the transaction is also conditioned upon approval by the FERC and the public service commissions of the District of Columbia, Delaware, New Jersey and Virginia. Under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR Act), the transaction cannot be completed until Exelon has made required notifications and given certain information and materials to the Antitrust Division of the DOJ and until specified waiting period requirements have expired. In addition, the transfer of certain PHI communications licenses requires approval by the Federal Communication Commission.

	During the second quarter of 2014, Exelon and PHI (“Joint Applicants”) filed approval applications with the FERC and the public service commissions of the District of Columbia, Delaware, New Jersey and Virginia. On August 19, 2014, the Joint Applicants filed their approval application in Maryland. The Joint Applicants also filed notifications with the DOJ in compliance with the requirements of the HSR Act. Exelon’s notification was voluntarily withdrawn and refiled in the third quarter.

	On October 7, 2014, the Virginia State Corporation Commission issued its Order, granting approval to transfer control of Delmarva Power & Light Company and Potomac Electric Power Company to Exelon. FERC approval is expected in the fourth quarter of 2014, while procedural schedules have been set in the remaining state 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 has the effect of extending the DOJ review period until 30 days after PHI and Exelon each has certified that it has substantially complied with the request. Exelon and PHI will continue to work cooperatively with the DOJ as it conducts its review of 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 intends to vigorously defend these suits. 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 September 30, 2014, Exelon has incurred approximately $57 million of expense associated with the transaction, primarily related to acquisition and integration costs. As part of the applications for approval of the merger, Exelon and PHI have proposed a package of benefits to the PHI utilities’ respective customers, which would result in a direct investment of more than $100 million. 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, as a result of PHI redeeming 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 $3.9 billion facility as a result of the equity issuances and applicable asset divestitures. See Note 10 — Debt and Credit Agreements and Note 16 — Common Stock for more information.

	Integrys Energy Group, Inc. (Exelon and Generation)

	On July 29, 2014, Generation entered into a Stock Purchase Agreement (the Purchase Agreement) with Integrys Energy Group, Inc. (Integrys). Pursuant to the Purchase Agreement, Integrys agreed to sell its competitive retail electric and natural gas businesses through a sale of all of the stock of its wholly-owned subsidiary, Integrys Energy Services, Inc. (IES), to Generation for an all cash purchase price of $60 million plus adjusted net working capital at the time of the closing. IES’s adjusted net working capital balance was approximately $260 million as of September 30, 2014. Pursuant to the Purchase Agreement, Generation has agreed to use its commercially reasonable efforts to replace the guarantees and other credit support currently being provided by Integrys for IES in support of the ongoing competitive retail businesses and to reimburse Integrys for any payments arising pursuant to such arrangements continuing for any post-closing period. The generation and solar asset businesses of IES are excluded from the transaction.

	The transaction is expected to close November 1, 2014. The closing of the transaction is subject to certain conditions, including, among others, approval by the FERC and expiration or termination of the applicable waiting period under the HSR Act. The FERC approved the sale of IES to Exelon on September 16, 2014; additionally, the DOJ granted early termination of the HSR Act waiting period effective October 10, 2014. Either party may terminate the Purchase Agreement if the transaction has not been consummated within 6 months after the date of the Purchase Agreement. The Purchase Agreement also includes various representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature. The total costs directly related to the closing of the transaction are not expected to have a material impact on the financial results of Exelon and Generation.

	Asset Divestitures (Exelon and Generation)

	As of September 30, 2014, Generation has entered into agreements with various counterparties to divest certain generating assets with total expected pre-tax proceeds of $1.3 billion (approximately $975 million after-tax) which are expected to be used primarily to finance a portion of the acquisition of PHI. The net book value of these assets was approximately $900 million.

	On August 8, 2014 Generation closed on the sale of its 67% economic equity interest in the 417 MW Safe Harbor Water Power Corporation hydroelectric facility on the Susquehanna River in Pennsylvania for a purchase price of approximately $615 million. Generation recorded a pre-tax gain on the sale of approximately $329 million within Other, net on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.

	During the third quarter of 2014, Generation also entered into purchase and sale agreements with separate counterparties to divest the following long-lived assets:


	Station		Net Generation Capacity		Location	Operating Segment
	Fore River		726 MW		North Weymouth, MA	New England
	West Valley		185 MW		Salt Lake City, UT	Other
	Quail Run		488 MW		Odessa, TX	ERCOT


	The assets and liabilities of the three power plants are 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 September 30, 2014.


			30-Sep-14
	Assets:
	Property, plant and equipment, net (a)		$	617

	Inventory		31

	Current assets		1

	Total assets held for sale		$	649

	Liabilities:
	Accounts payable		$	1

	Accrued expenses		4

	Other current liabilities		13

Total liabilities held for sale (b)		$	18


(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 7 - Impairment of Long-Lived Assets for further information.
(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.


The transactions, which are subject to customary closing conditions and regulatory approvals, are expected to be completed by the end of the first quarter of 2015.

Regulatory_Matters_Exelon_Gene

Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
Regulated Operations [Abstract]	'
Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)	'
	Regulatory Matters (Exelon, Generation, ComEd, PECO and BGE)
	Regulatory and Legislative Proceedings (Exelon, Generation, ComEd, PECO and BGE)
	Except for the matters noted below, the disclosures set forth in Note 3 - Regulatory Matters of the Exelon 2013 Form 10-K appropriately represent, in all material respects, the current status of regulatory and legislative proceedings of the Registrants. The following is an update to that discussion.
	Illinois Regulatory Matters
	Energy Infrastructure Modernization Act (Exelon and ComEd). Since 2011, ComEd’s distribution rates are established through a performance-based rate formula, pursuant to EIMA. 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. ComEd's earned rate of return on common equity is required to be within plus or minus 50 basis points ("the collar") of the target rate of return determined as the annual average rate on 30-year treasury notes plus 580 basis points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on distribution revenue. In addition, ComEd's target rate of return on common equity is subject to reduction if ComEd does not deliver the reliability and customer service benefits, as defined, it has committed to over the ten-year life of the investment program. 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 September 30, 2014, and December 31, 2013, ComEd had recorded a net regulatory asset associated with the distribution formula rate of $466 million and $463 million, respectively. The regulatory asset associated with the distribution true-up will be amortized as the associated amounts are recovered through rates.
	On April 16, 2014, ComEd filed its annual distribution formula rate update with the ICC. The filing establishes the revenue requirement used to set the rates that will take effect in January 2015 after the ICC’s review and approval, which is due by December 2014. The revenue requirement requested is based on 2013 actual costs plus projected 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect in 2013 to the actual costs incurred that year. ComEd's 2014 filing request includes a total increase to the net revenue requirement of $269 million, reflecting an increase of $174 million for the initial revenue requirement for 2014 and an increase of $95 million related to the annual reconciliation for 2013. The revenue requirement for 2014 provides for a weighted average debt and equity return on distribution rate base of 7.06% inclusive of an allowed return on common equity of 9.25%, reflecting the average rate on 30-year treasury notes plus 580 basis points. The annual reconciliation for 2013 provided for a weighted average debt and equity return on distribution rate base of 7.04% inclusive of an allowed return on common equity of 9.20%, reflecting the average rate on 30-year treasury notes plus 580 basis points less a performance metrics penalty of 5 basis points.

	On October 15, 2014, the ALJ issued its proposed order in ComEd’s current distribution formula rate proceeding, recommending an increase to the net revenue requirement of $239 million as compared to ComEd’s request of $269 million discussed above. The $30 million reduction, a portion of which may be recoverable through other recovery mechanisms, consisted of a decrease of $20 million for the initial revenue requirement for 2014 and a decrease of $10 million related to the annual reconciliation for 2013. The ALJs proposed order has no independent legal effect as the ICC must vote on a final order by mid December 2014, which may materially vary from the findings and conclusions in the proposed order. If the ICC provides significant changes to ComEd’s filed revenue requirement request, it could have a material impact on ComEd’s current and future results of operations and cash flows.
	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. On April 1, 2014, ComEd filed an annual progress report on its AMI Implementation Plan with the ICC. The ICC ruled that no investigation would be opened in regards to that April filing. 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 500,000 smart meters have been installed in the Chicago area.
	Appeal of the 2012 Formula Rate Tariff (Exelon and ComEd). On April 30, 2012, ComEd filed its annual distribution formula rate update. The filing established the revenue requirement used to set the rates that were effective in January 2013. On December 20, 2012, the ICC issued its final order, which increased the revenue requirement by $73 million. The $73 million reflected 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.
	On June 30, 2014, the Illinois Appellate Court issued its opinion, finding against ComEd on two issues and for ComEd on a third issue. The two issues (billing determinants and the use of certain allocators) were the same issues previously rejected by the Court in the Appeal of Initial Formula Rate Tariff (see Appeal of Initial Formula Rate Tariff discussed below). The Court re-affirmed the ICC’s order and rejected ComEd’s arguments. However, on the third issue (rate case expenses), the Court allowed for the possibility of future recovery. The Court’s opinion has no accounting impact as ComEd recorded the distribution formula regulatory asset consistent with the ICC’s final Order.
	Appeal of Initial Formula Rate Tariff (Exelon and ComEd). 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 has 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.
	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 which modified the timing of the refund, now to occur in November 2014, rather than the eight month period previously approved. The refund will be included with the Rider AMP refund discussed below. Former ComEd customers also are eligible for a refund. As of September 30, 2014, and December 31, 2013, ComEd had fully reserved for this liability.
	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 September 30, 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. ComEd believes no refund is appropriate and that any refund obligation associated with Rider AMP should be prospective from no earlier than the date of the Illinois Appellate Court’s order on Rider AMP, or March 19, 2012, which would represent a refund of approximately $0.4 million. 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 are eligible for a refund. As of September 30, 2014, ComEd had fully reserved for this liability.

	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. Those parties now have 30 days to request that the ICC reconsider its decision and subsequently file an appeal with the Illinois Appellate Court. 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.
	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, as a result of the Illinois Settlement Legislation, 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. On December 18, 2013, the ICC approved the IPA’s procurement plan covering the period June 2014 through May 2019.
	The Illinois Settlement Legislation requires ComEd 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. Under the Illinois Settlement Legislation, all associated costs are recoverable from customers. The ICC did not require the acquisition of additional renewable resources for the period June 2014 through May 2015 due to ComEd expecting to exceed the renewable cost cap established by the Illinois Settlement Legislation.
	The IPA’s 2014-2019 plan provides for two separate energy procurements during 2014 to address potential fluctuations in energy demand due to customer switching between ComEd and competitive electric generation suppliers. The ICC also approved the IPA’s expansion of energy efficiency programs for both ComEd and Ameren. As of September 30, 2014, ComEd has completed both of the scheduled 2014 energy procurements, which cover a portion of its energy requirements through the periods ending May 31, 2015, 2016 and 2017. See Note 18 - 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 to enter into a 20-year sourcing agreement 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 have reserved their right to appeal the Illinois Appellate Court’s decision.

	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.
	Pennsylvania Regulatory Matters
	Pennsylvania Procurement Proceedings (Exelon and PECO). On October 12, 2012, the PAPUC issued its Opinion and Order approving PECO’s second DSP Program, which was filed with the PAPUC in January 2012. The program, which has a 24-month term from June 1, 2013 through May 31, 2015, complies with electric generation procurement guidelines set forth in Act 129.
	In the second DSP Program, PECO is procuring 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. In December 2012 and February 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential class and its small and medium commercial classes that began in June 2013. In September 2013, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential class and its small and medium commercial classes that began in December 2013. In January 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its residential class and its and small, medium, and large commercial classes that began in June 2014. In September 2014, PECO entered into contracts with PAPUC-approved bidders, including Generation, for its final competitive procurements of electric supply for its residential class and its small and medium commercial classes commencing December 2014. 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 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, 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 early 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 and reserved two issues for litigation: certain non-bypassable transmission charges and the default service product for Medium Commercial customers (including hourly pricing). On September 30, 2014, the ALJ issued a Recommended Decision to the PAPUC that PECO’s third DSP Program be approved, as modified by the Joint Petition for Partial Settlement, but also recommending that the Large C&I class should be excluded from the recommended non-bypassable charge for non-market-based charges. A final ruling from the PAPUC is expected by December 2014.
	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 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 substantially all of the 1.6 million smart meters on an accelerated basis by the end of 2014. In total, PECO currently expects to spend up to $595 million, excluding the cost of the original meters (as further described below), on its smart meter infrastructure and approximately $120 million on smart grid investments through 2014 of which $200 million will be funded by SGIG as discussed below. As of September 30, 2014, PECO has spent $516 million and $119 million on smart meter and smart grid infrastructure, respectively, not including the DOE reimbursements received to date.
	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 are being used to offset the total impact to ratepayers of the smart meter deployment required by Act 129. As of September 30, 2014, PECO has received substantially 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 continued to be allowable costs and that any settlement with the vendor would not be considered project income. In addition, PECO remains 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 received $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. As of December 31, 2013, $5 million was recorded on Exelon’s and PECO’s Consolidated Balance Sheets. Pursuant to the January 23, 2014, vendor agreement, PECO reclassified the regulatory asset balance as a receivable, which was fully collected as of September 30, 2014, 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.
	PECO filed its final compliance report on Phase 1 targets with the PAPUC on November 15, 2013. On March 20, 2014, the PAPUC issued its final report stating that PECO was in full compliance with all Phase I targets.
	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.
	Pennsylvania Retail Electricity Market (Exelon and PECO). The extreme weather experienced in early 2014 resulted in increased 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 are to be in place within 30 days and six months of approval of the orders, respectively. The Independent Regulatory Review Commission granted approval of the orders on May 22, 2014. The orders became final on June 14, 2014. PECO is in process of implementing compliance with the order.
	Maryland Regulatory Matters
	2014 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On July 2, 2014, BGE filed an application for increases of $118 million and $68 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.65% and 10.55% for electric and gas distribution, respectively. On September 15, 2014, BGE filed an update to its rate request which altered the requested increase to electric base rates from $118 million to $99 million. The requested increase to gas base rates did not change.
	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. The Settlement Agreement remains subject to MDPSC approval. If approved by the MDPSC, rates would go into effect no sooner than December 15, 2014, and no later than late January 2015. BGE is uncertain if the MDPSC will unconditionally approve the Settlement Agreement or if further proceedings will be required.
	2013 Maryland Electric and Gas Distribution Rate Case (Exelon and BGE). On May 17, 2013, BGE filed an application for increases of $101 million and $30 million to its electric and gas base rates, respectively, with the MDPSC. The requested rates of return on equity in the application were 10.50% and 10.35% for electric and gas distribution, respectively. In addition to these requested rate increases, BGE’s application also included a request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan (the “ERI initiative”) in response to a MDPSC order through a surcharge separate from base rates. On August 23, 2013, BGE filed an update to its rate request which altered the requested increase to electric base rates from $101 million to $83 million and the requested increase to gas base rates from $30 million to $24 million. 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. The electric distribution rate increase was set using an allowed return on equity of 9.75% and the gas distribution rate increase was set using an allowed return on equity of 9.60%. The approved electric and natural gas distribution rates became effective for services rendered on or after December 13, 2013. As part of its December 13, 2013 decision granting BGE increases for its gas and electric distribution rates, the MDPSC also authorized BGE to recover through a surcharge mechanism costs associated with five ERI initiative programs designed to accelerate electric reliability improvements. Such a decision, however, was premised upon the condition that the MDPSC approve specific projects scheduled for each year of the five-year program in advance of cost recovery through the surcharge mechanism. 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. As a result of the MDPSC’s decision, BGE estimates 2014 capital and operating and maintenance costs associated with the ERI initiative of $14.8 million and a revenue requirement of $1.4 million. The ERI initiative surcharge became effective June 1, 2014. BGE is required to file an update on the 2014 work plan and reliability performance information for the specific projects, along with its work plan and cost estimates for 2015, on or before November 1, 2014.
	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 has been scheduled for November 17, 2014. BGE cannot predict the outcome of this appeal.
	Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that includes 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 has been 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 September 30, 2014 and December 31, 2013, BGE recorded a regulatory asset of $111 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. However, as discussed above, the settlement is still subject to MDPSC approval.
	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 smart meter replacement, 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. As of September 30, 2014, BGE is awaiting the MDPSC's decision regarding BGE's proposal to automatically enroll unresponsive customers into the opt-out program. The proposal, if approved, would allow BGE to begin charging these customers opt-out fees. 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.
	The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In February 2013, the Maryland General Assembly passed legislation intended to accelerate gas infrastructure replacements in Maryland by establishing a mechanism for gas companies to recover promptly reasonable and prudent costs of eligible infrastructure replacement projects separate from base rate proceedings. On May 2, 2013, the Governor of Maryland signed the legislation into law, which took effect June 1, 2013. Under the new law, following a proceeding before the MDPSC and with the MDPSC’s approval of the eligible infrastructure replacement projects along with a corresponding surcharge, BGE could begin charging gas customers a monthly surcharge for infrastructure costs incurred after June 1, 2013. The legislation includes caps on the monthly surcharges to residential and non-residential customers, and would require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be included in 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. BGE will defer the difference between the surcharge revenues and program costs as a regulated asset or liability, which was immaterial to BGE and Exelon as of September 30, 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. The residential consumer advocate filed its related legal memorandum on July 7, 2014, claiming that the MDPSC did not apply the appropriate consideration in approving BGE’s infrastructure replacement plan and associated surcharge. BGE submitted a response to the appeal on August 6, 2014. 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.
	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 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 September 30, 2014 and December 31, 2013, ComEd had recorded a net regulatory asset associated with the transmission formula rate of $19 million and $17 million, respectively. BGE recorded a net regulatory asset associated with the transmission formula rate of $3 million at September 30, 2014, and a net regulatory liability which was not material as of December 31, 2013. The regulatory asset associated with the transmission true-up will be amortized as the associated amounts are recovered through rates.
	On April 16, 2014, ComEd filed its annual formula rate update with the FERC. The filing establishes the revenue requirement used to set rates that took effect in June 2014, subject to review by the FERC and other parties, which is due by November 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $524 million plus an $11 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $535 million. This compares to the 2013 revenue requirement of $488 million plus a $25 million adjustment related to the reconciliation of 2012 actual costs for a total revenue requirement of $513 million. The increase in the revenue requirement was primarily driven by increased capital investment and higher operating and maintenance costs.
	ComEd’s updated formula transmission rate currently provides for a weighted average debt and equity return on transmission rate base of 8.62%, which is inclusive of an allowed return on common equity of 11.50%, a decrease from the 8.70% average debt and equity return previously authorized. As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55%.
	On April 28, 2014, BGE filed its annual formula rate update with the FERC. The filing established the revenue requirement used to set rates that took effect in June 2014, subject to review by the FERC and other parties, which is due by October 2014. The revenue requirement is based on 2013 actual costs plus forecasted 2014 capital additions as well as an annual reconciliation of the revenue requirement in effect starting in June 2013 to the actual cost incurred in 2013. The update resulted in a revenue requirement of $167 million plus a $4 million adjustment related to the reconciliation of 2013 actual costs for a total revenue requirement of $171 million. This compares to the 2013 revenue requirement of $158 million offset by a $1 million reduction related to the reconciliation of 2012 actual costs for a net revenue requirement of $157 million. The increase in the revenue requirement is primarily driven by higher depreciation expense and an increased level of return on investment associated with a higher equity ratio and increased rate base.
	BGE’s updated formula transmission rate currently 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%, which is inclusive of a 50 basis point incentive for participating in PJM.
	FERC Transmission Complaint (Exelon and BGE). On February 27, 2013, consumer advocates and regulators from the District of Columbia, New Jersey, Delaware and Maryland, and the Delaware Electric Municipal Cooperatives (the parties), filed a complaint at FERC against BGE and the PHI companies relating to their respective transmission formula rates. BGE’s formula rate includes a 10.8% base rate of return on common equity (ROE) for most investments included in its rate base and 11.3% for the remaining transmission investment (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 return on equity 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 June 19, 2014, FERC issued an order in another case involving New England Transmission Owners (NETOs), changing its methodology to determine ROE rates for public utilities. The result was a reduction in the NETO’s ROE from 11.14% to 10.57%, with a possible further adjustment in either direction based on additional paper hearing submissions. On July 21, 2014, the NETOs filed a Request for Rehearing and Clarification with FERC of the June 19, 2014 order. Among other things, the NETOs assert that the 11.14% is reasonable based on the new methodology. Following the paper submissions, FERC again approved a base ROE of 10.57% on October 16, 2014.
	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 and the discussions are expected to continue at least through November. While it is too early in the process to predict the outcome of the settlement discussions, if the parties cannot resolve their differences, the matter will proceed to hearing.
	Based on the current status of the settlement discussions, 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 maximum fifteen month period will be required. However, BGE is unable to estimate the most likely refund amount 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. If FERC were to order a reduction of BGE’s base return on equity to 8.7% as sought in the original 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 would be a refund to customers of approximately $13 million, as well as an estimated ongoing annual reduction in revenues of approximately $10 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. 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.
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 determine whether to appeal the decision to the U.S. Supreme Court. Therefore, FERC will not be required to implement the D.C. Circuit Decision until a determination is made on the stay request. FERC and other parties will have until December 2014 to appeal the decision to the U.S. Supreme Court. FERC or other parties may also petition the U.S. Supreme Court to review the decision of the D.C. Circuit Court. 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. FERC's response to the FirstEnergy 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. 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.
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. It is not clear whether any party will seek rehearing or appeal of that notice or whether any such rehearing or 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, if any, FERC or a court may take concerning the results of that auction, but any FERC or 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”) recognizes 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 removed the hold on final licensing decisions and 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. The rule was issued September 19, 2014.
On October 20, 2014, the NRC approved Generation's request to extend the operating licenses of Limerick Units 1 and 2 by 20 years. The extended operating licenses for Limerick Units 1 and 2 will expire in 2044 and 2049, respectively.
On May 29, 2013, Generation submitted applications to the NRC to extend the operating licenses of Byron Units 1 and 2 and Braidwood Units 1 and 2 by 20 years. The current operating licenses for Byron Units 1 and 2 expire in 2024 and 2026, respectively. The current operating licenses for Braidwood Units 1 and 2 expire in 2026 and 2027, respectively. Generation does not expect the NRC to issue license renewals for Byron and Braidwood until 2015 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, Exelon 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. Resolution of these issues relating to Conowingo may have a material effect on Generation’s results of operations and financial position through an increase in capital expenditures and operating costs.
On June 3, 2014, 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. On July 3, 2014, PPL Holtwood, LLC, the owner of the next upstream dam from Muddy Run, filed an appeal of PA DEP's issuance of its water quality certificate. Exelon is working with PA DEP and PPL to resolve PPL's concerns.
Based on the FERC procedural schedule, the FERC licensing process was not scheduled to be completed prior to the expiration of Muddy Run’s current license on August 31, 2014, and the expiration of Conowingo’s license on September 1, 2014. 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 current 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 September 30, 2014, $38 million of direct costs associated with licensing efforts have been capitalized.
Regulatory Assets and Liabilities (Exelon, ComEd, PECO and BGE)
Exelon, ComEd, PECO and BGE each prepare their consolidated financial statements in accordance with the authoritative guidance for accounting for certain types of regulation. Under this guidance, regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO and BGE as of September 30, 2014 and December 31, 2013. For additional information on the specific regulatory assets and liabilities, refer to Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K.



30-Sep-14	Exelon						ComEd						PECO					BGE
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent		Current			Noncurrent
Regulatory assets
Pension and other postretirement	$	208		$	2,455		$	—		$	—		$	—		$	—	$	—		$	—
benefits
Deferred income taxes	7			1,517			1			67			—			1,377		6			73

AMI programs	9			254			9			69			—			74		—			111

Under-recovered distribution service	243			223			243			223			—			—		—			—
costs
Debt costs	9			50			7			48			2			2		1			8

Fair value of BGE long-term debt(a)	6			192			—			—			—			—		—			—

Fair value of BGE supply contract(b)	3			—			—			—			—			—		—			—

Severance	4			9			—			—			—			—		4			9

Asset retirement obligations	1			111			1			73			—			26		—			12

MGP remediation costs	39			220			32			186			6			33		1			1

RTO start-up costs	1			—			1			—			—			—		—			—

Under-recovered uncollectible accounts	—			70			—			70			—			—		—			—

Renewable energy	14			164			14			164			—			—		—			—

Energy and transmission programs	22			5			19			—			—			—		3		(f)	5

Deferred storm costs	3			—			—			—			—			—		3			—

Electric generation-related	12			21			—			—			—			—		12			21
regulatory asset
Rate stabilization deferral	75			101			—			—			—			—		75			101

Energy efficiency and demand	84			151			—			—			—			—		84			151
response programs
Merger integration costs	2			7			—			—			—			—		2			7

Conservation voltage reduction	1			1			—			—			—			—		1			1

Under-recovered revenue decoupling(e)	14			—			—			—			—			—		14			—

Other	17			38			3			28			13			8		—			—

Total regulatory assets	$	774		$	5,589		$	330		$	928		$	21		$	1,520	$	206		$	500



30-Sep-14	Exelon						ComEd						PECO					BGE
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent		Current			Noncurrent
Regulatory liabilities
Other postretirement benefits	$	53		$	96		$	—		$	—		$	—		$	—	$	—		$	—

Nuclear decommissioning	—			2,850			—			2,371			—			479		—			—

Removal costs	110			1,455			86			1,257			—			—		24			198

Energy efficiency and demand	28			2			28			—			—			2		—			—
response programs
DLC Program Costs	—			10			—			—			—			10		—			—

Energy efficiency Phase 2	—			32			—			—			—			32		—			—

Electric distribution tax repairs	20			100			—			—			20			100		—			—

Gas distribution tax repairs	8			32			—			—			8			32		—			—

Energy and transmission programs	73			13			26			13			44		(c)	—		3		(f)	—

Over-recovered gas and electric	4			—			—			—			4			—		—			—
universal service fund costs
Revenue subject to refund(d)	47			—			47			—			—			—		—			—

Over-recovered revenue decoupling(e)	16			—			—			—			—			—		16			—

Other	5			3			—			2			3			—		2			1

Total regulatory liabilities	$	364		$	4,593		$	187		$	3,643		$	79		$	655	$	45		$	199



31-Dec-13	Exelon						ComEd						PECO					BGE
	Current			Noncurrent			Current			Noncurrent			Current			Noncurrent		Current			Noncurrent
Regulatory assets
Pension and other postretirement	$	221		$	2,794		$	—		$	—		$	—		$	—	$	—		$	—
benefits
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	178			285			178			285			—			—		—			—
costs
Debt costs	12			56			9			53			3			3		1			8

Fair value of BGE long-term debt(a)	—			219			—			—			—			—		—			—

Fair value of BGE supply contract(b)	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			—			52			—			—			—		1		(f)	—

Deferred storm costs	3			3			—			—			—			—		3			3

Electric generation-related regulatory	13			30			—			—			—			—		13			30
asset
Rate stabilization deferral	71			154			—			—			—			—		71			154

Energy efficiency and demand	73			148			—			—			—			—		73			148
response programs
Merger integration costs	2			9			—			—			—			—		2			9

Other	31			39			18			26			8			7		4			6

Total regulatory assets	$	760		$	5,910		$	329		$	933		$	17		$	1,448	$	181		$	524



31-Dec-13	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	53			—			45			—			8			—		—			—
response programs
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		(c)	—		11		(f)	—

Over-recovered gas and electric	8			—			—			—			8			—		—			—
universal service fund costs
Revenue subject to refund(d)	38			—			38			—			—			—		—			—

Over-recovered revenue decoupling(e)	16			—			—			—			—			—		16			—

Other	4			—			—			—			3			—		—			—

Total regulatory liabilities	$	327		$	4,388		$	170		$	3,512		$	106		$	629	$	48		$	204

________________

(a)	Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt.

(b)	Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.

(c)	Includes $28 million related to the DSP program, $11 million related to the over-recovered natural gas costs under the PGC and $5 million related to over-recovered electric transmission costs as of September 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.

(d)	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC’s order in the 2007 Rate Case. See Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K. for further information.

(e)	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2014, BGE had a regulatory asset of $14 million related to under-recovered electric revenue decoupling and a regulatory liability of $16 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.

(f)	Relates to $3 million associated with the transmission formula rate and $3 million of over-recovered natural gas supply costs as of September 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs.
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 and BGE purchase receivables at a discount to primarily recover uncollectible accounts expense from the suppliers. PECO is required to purchase receivables at face value and permitted to recover uncollectible accounts expense from customers through distribution rates. Exelon, ComEd, PECO and BGE do not record unbilled commodity receivables under the POR programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s and BGE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of the Registrants as of September 30, 2014 and December 31, 2013.


As of September 30, 2014	Exelon			ComEd			PECO			BGE
Purchased receivables(a)	$	306		$	152		$	78		$	76

Allowance for uncollectible accounts(b)	(36		)	(21		)	(8		)	(7		)
Purchased receivables, net	$	270		$	131		$	70		$	69



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.

Investment_in_Constellation_En

Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)	9 Months Ended
	Sep. 30, 2014
Equity Method Investments and Joint Ventures [Abstract]	'
Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)	'
	Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)

	As a result of the Constellation merger, Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENG to purchase power and to provide certain services. For further information regarding these agreements, see Note 25 — Related Party Transactions of the Exelon 2013 Form 10-K.

	On April 1, 2014, Generation, CENG, and subsidiaries of 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 and decommissioning of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to EDF, Inc.'s (EDFI) 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 the 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 (Operating Agreement) 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 Generation or one of its affiliates (the Generation Parties) and Exelon's assumption of sponsorship of the employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their related trust funds as of July 14, 2014. The EMA also generally requires CENG to fund obligations 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 the CENG plants (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 as of April 1, 2014 when the NRC licenses were transferred to Generation. No liability has been recognized by Exelon for the Exelon Support Agreement or the guarantee.

	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 three and nine months ended September 30, 2013, Generation recorded $37 million and $5 million, respectively, of equity in earnings of unconsolidated affiliates related to its investment in CENG and $12 million and $45 million, respectively, 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, there are several 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 of the Exelon 2013 Form 10-K, EDF and Generation have a PPA with CENG under which they purchase 15% and 85%, respectively, of the nuclear output owned by CENG that is 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 three and nine months ended September 30, 2014, Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income include sales to EDF of $52 million and $90 million, respectively. See discussion above and Note 3 — Variable Interest Entities for additional information regarding other related party transactions, between CENG and EDF included within Exelon and Generation’s financial statements.

	See Note 3 — Variable Interest Entities for additional information about the Registrants 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 Generation's ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing transactions between CENG and Generation. The net gain on the consolidation of CENG of $261 million is net of a $7 million payment to EDF.

	The fair value of CENG’s assets and liabilities recorded in consolidation was determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows (including timing); discount rates reflecting risk inherent in the future cash flows; and future market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and duration of liabilities assumed.

	The valuations necessary to assess the fair values of certain assets and liabilities 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 are expected to be revised include the asset retirement obligation liabilities and related asset retirement costs. These items are expected to be updated with inputs from a third party engineering firm with corresponding adjustments recorded by the end of 2014. See Note 12 — Nuclear Decommissioning for discussion of the impacts of adjustments recorded during the third quarter of 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 could result in adjustments to the amounts recorded upon consolidation, including the overall gain recorded by Generation. In addition, any asset or liability adjustments impacting depreciation and/or accretion expense recorded after the consolidation date would impact Generation’s post-consolidation results of operations.

	Generation recorded the assets and liabilities of CENG at fair value as of April 1, 2014. The following assets and liabilities of CENG were recorded within Generation’s Consolidated Balance Sheets as of the date of integration:



	Preliminary Fair Values	Exelon and Generation
	Current assets	$	499

	Nuclear decommissioning trust fund	1,955

	Property, plant and equipment	2,941

	Nuclear fuel	482

	Other assets	10

	Total assets	5,887


	Current liabilities	237

	Asset retirement obligation	1,684

	Pension and other employee benefit obligations	281

	Unamortized energy contract liabilities	171

	Other liabilities	114

	Total liabilities	2,487

	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 Non-controlling interest on the Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’s net assets. For the three and nine months ended September 30, 2014, Generation reduced by $4 million and $8 million, respectively, the amount of Net income attributable to noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental operating revenues of $58 million and $155 million and CENG’s net income, prior to any intercompany eliminations and any adjustments for noncontrolling interest, of $171 million and $248 million during the three and nine months ended September 30, 2014, respectively.

Exelon and Generation both incurred integration-related costs of $4 million and $22 million during the three and nine months ended September 30, 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 three and nine months ended September 30, 2014.

See Note 14 — Severance for integration-related severance costs related to CENG incurred by Exelon and Generation during the three and nine months ended September 30, 2014.

Impairment_of_Longlived_Assets

Impairment of Long-lived Assets (Exelon and Generation)	9 Months Ended
	Sep. 30, 2014
Property, Plant and Equipment [Abstract]	'
Impairment of Long-Lived Assets (Exelon and Generation)	'
	7. 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 the second quarter of 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 merchant wind assets may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014. As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million and a pre-tax impairment charge of $86 million was recorded during the second quarter of 2014 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

	In the third quarter of 2013, lower projected wind production and a decline in power prices suggested that the carrying value of certain wind projects 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 $39 million, net of the impairment amount attributable to noncontrolling interests for certain of the projects, was recorded during the third quarter of 2013 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

	The fair value analysis in both quarters was primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation 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.

	During the third quarter of 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. At September 30, 2014, in connection with the approved asset sales agreements, a $50 million pre-tax impairment loss was recorded within Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 4 — Mergers, Acquisitions, and Dispositions for further information on assets held for sale.

	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 in both the first and second quarters of 2013 to cancel certain projects. During the first quarter of 2013, 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. For these cancelled projects, Generation recorded approximately $21 million to Operating and maintenance expense during the first quarter of 2013 to accrue remaining costs and reverse previously capitalized costs. During the second quarter of 2013, market conditions prompted Generation to cancel the previously deferred extended power uprate projects at the LaSalle and Limerick nuclear stations. For these cancelled projects, Generation recorded a pre-tax charge during the second quarter of 2013 to Operating and maintenance expense and Interest expense of approximately $92 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 11 — 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 the fourth quarter of 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 lease on the generating station located in Texas prior to its expiration date. As a result of the lease termination, UII received a net early termination amount of $335 million from CPS and wrote off the net investment in the CPS long-term lease of $336 million in Investments in the Consolidated Balance Sheet in the first quarter of 2014 resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the Consolidated Statement of Operations and Comprehensive Income in the first quarter of 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 the second quarter of 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 the second quarter of 2014 and 2013, respectively, for these stations. These impairment charges were recorded in Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheet and the Consolidated Statement 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.

	At September 30, 2014 and December 31, 2013, the components of the net investment in long-term leases were as follows:



		September 30, 2014		December 31, 2013
	Estimated residual value of leased assets	$	685	$	1,465

	Less: unearned income		328		767

	Net investment in long-term leases	$	357	$	698

Fair_Value_of_Financial_Assets

Fair Value of Financial Assets and Liabilities (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 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 September 30, 2014 and December 31, 2013:
	Exelon


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	565			$	3			$	562			$	—			$	565
	Short-term liabilities	$	565			$	3			$	562			$	—			$	565
	Long-term debt (including amounts due within one year)	21,264				1,168				20,278				1,297				22,743
	Long-term debt (including amounts due within one year)	21,264				1,168				20,278				1,297				22,743
	Long-term debt to financing trusts	648				—				—				677				677
	Long-term debt to financing trusts	648				—				—				677				677
	SNF obligation	1,021				—				849				—				849
	SNF obligation	1,021				—				849				—				849



		31-Dec-13
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	344			$	3			$	341			$	—			$	344
	Short-term liabilities	$	344			$	3			$	341			$	—			$	344
	Long-term debt (including amounts due within one year)	19,132				—				18,672				1,079				19,751
	Long-term debt (including amounts due within one year)	19,132				—				18,672				1,079				19,751
	Long-term debt to financing trusts	648				—				—				631				631
	Long-term debt to financing trusts	648				—				—				631				631
	SNF obligation	1,021				—				790				—				790
	SNF obligation	1,021				—				790				—				790
	Generation


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	14			$	—			$	14			$	—			$	14
	Short-term liabilities	$	14			$	—			$	14			$	—			$	14
	Long-term debt (including amounts due within one year)	8,320				—				7,543				1,297				8,840
	Long-term debt (including amounts due within one year)	8,320				—				7,543				1,297				8,840
	SNF obligation	1,021				—				849				—				849
	SNF obligation	1,021				—				849				—				849



		December 31, 2013
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	22			$	—			$	22			$	—			$	22
	Short-term liabilities	$	22			$	—			$	22			$	—			$	22
	Long-term debt (including amounts due within one year)	7,729				—				6,586				1,062				7,648
	Long-term debt (including amounts due within one year)	7,729				—				6,586				1,062				7,648
	SNF obligation	1,021				—				790				—				790
	SNF obligation	1,021				—				790				—				790

	ComEd


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
Short-term liabilities	$	528			$	—			$	528			$	—			$	528
Short-term liabilities	$	528			$	—			$	528			$	—			$	528
Long-term debt (including amounts due within one year)	5,708				—				6,422				—				6,422
Long-term debt (including amounts due within one year)	5,708				—				6,422				—				6,422
Long-term debt to financing trust	206				—				—				214				214
Long-term debt to financing trust	206				—				—				214				214


	December 31, 2013
	Carrying				Fair Value
	Amount				Level 1				Level 2				Level 3				Total
Short-term liabilities	$	184			$	—			$	184			$	—			$	184
Short-term liabilities	$	184			$	—			$	184			$	—			$	184
Long-term debt (including amounts due within one year)	5,675				—				6,238				17				6,255
Long-term debt (including amounts due within one year)	5,675				—				6,238				17				6,255
Long-term debt to financing trust	206				—				—				202				202
Long-term debt to financing trust	206				—				—				202				202
PECO


	30-Sep-14
	Carrying				Fair Value
	Amount				Level 1				Level 2				Level 3				Total
Long-term debt (including amounts due within one year)	$	2,496			$	—			$	2,720			$	—			$	2,720
Long-term debt (including amounts due within one year)	$	2,496			$	—			$	2,720			$	—			$	2,720
Long-term debt to financing trusts	184				—				—				204				204
Long-term debt to financing trusts	184				—				—				204				204



	December 31, 2013
	Carrying				Fair Value
	Amount				Level 1				Level 2				Level 3				Total
Long-term debt (including amounts due within one year)	$	2,197			$	—			$	2,358			$	—			$	2,358
Long-term debt (including amounts due within one year)	$	2,197			$	—			$	2,358			$	—			$	2,358
Long-term debt to financing trusts	184				—				—				180				180
Long-term debt to financing trusts	184				—				—				180				180
BGE


	30-Sep-14
	Carrying				Fair Value
	Amount				Level 1				Level 2				Level 3				Total
Short-term liabilities	$	23			$	3			$	20			$	—			$	23
Short-term liabilities	$	23			$	3			$	20			$	—			$	23
Long-term debt (including amounts due within one year)	1,976				—				2,196				—				2,196
Long-term debt (including amounts due within one year)	1,976				—				2,196				—				2,196
Long-term debt to financing trusts	258				—				—				259				259
Long-term debt to financing trusts	258				—				—				259				259



	December 31, 2013
	Carrying				Fair Value
	Amount				Level 1				Level 2				Level 3				Total
Short-term liabilities	$	138			$	3			$	135			$	—			$	138
Short-term liabilities	$	138			$	3			$	135			$	—			$	138
Long-term debt (including amounts due within one year)	2,011				—				2,148				—				2,148
Long-term debt (including amounts due within one year)	2,011				—				2,148				—				2,148
Long-term debt to financing trusts	258				—				—				249				249
Long-term debt to financing trusts	258				—				—				249				249
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of short-term borrowings (Level 2) and dividends payable (included in other current liabilities) (Level 1). 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 Generation’s non-government-backed fixed rate project financing debt (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. Financial assets and liabilities utilizing Level 1 inputs include active exchange-traded corporate units, equity securities and funds, certain exchange-based derivatives, and money market funds.


•	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. Financial assets and liabilities utilizing Level 2 inputs include fixed income securities, derivatives, commingled and mutual investment funds priced at NAV per fund share and fair value hedges.


•	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. Financial assets and liabilities utilizing Level 3 inputs include infrequently traded securities and derivatives, and investments priced using an alternative pricing mechanism or third party valuation.
Transfers in and out of levels are recognized as of the end of the reporting period 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 nine months ended September 30, 2014 for cash equivalents, nuclear decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation obligations.
Exelon and Generation
The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2014 and December 31, 2013:



		Generation																Exelon
As of September 30, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
Assets
Cash equivalents(a)		$	944			$	—			$	—			$	944			$	1,876				$	—				$	—				$	1,876
Cash equivalents(a)		$	944			$	—			$	—			$	944			$	1,876				$	—				$	—				$	1,876
Nuclear decommissioning trust fund investments
Cash equivalents		261				62				—				323				261					62					—					323
Cash equivalents		261				62				—				323				261					62					—					323
Equity
Individually held		2,569				—				—				2,569				2,569					—					—					2,569
Individually held		2,569				—				—				2,569				2,569					—					—					2,569
Exchange traded funds		170				—				—				170				170					—					—					170
Exchange traded funds		170				—				—				170				170					—					—					170
Commingled funds		—				2,365				—				2,365				—					2,365					—					2,365
Commingled funds		—				2,365				—				2,365				—					2,365					—					2,365
Equity funds subtotal		2,739				2,365				—				5,104				2,739					2,365					—					5,104
Equity funds subtotal		2,739				2,365				—				5,104				2,739					2,365					—					5,104
Balanced funds - commingled funds		—				273				—				273				—					273					—					273
Balanced funds - commingled funds		—				273				—				273				—					273					—					273
Fixed income
Debt securities issued by the U.S.		967				—				—				967				967					—					—					967
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				429				—				429				—					429					—					429
United States and political
subdivisions of the states
Debt securities issued by foreign		—				105				—				105				—					105					—					105
governments		—				105				—				105				—					105					—					105
Corporate debt securities		—				2,001				235				2,236				—					2,001					235					2,236
Corporate debt securities		—				2,001				235				2,236				—					2,001					235					2,236
Federal agency mortgage-backed		—				79				—				79				—					79					—					79
securities		—				79				—				79				—					79					—					79
Commercial mortgage-backed		—				39				—				39				—					39					—					39
securities (non-agency)		—				39				—				39				—					39					—					39
Residential mortgage-backed securities		—				3				—				3				—					3					—					3
(non-agency)		—				3				—				3				—					3					—					3
Mutual funds		—				21				—				21				—					21					—					21
Mutual funds		—				21				—				21				—					21					—					21
Commingled funds		—				328				—				328				—					328			—		—					328
Commingled funds		—				328				—				328				—					328			—		—					328
Fixed income subtotal		967				3,005				235				4,207				967					3,005					235					4,207
Fixed income subtotal		967				3,005				235				4,207				967					3,005					235					4,207
Middle market lending		—				—				354				354				—					—					354					354
Middle market lending		—				—				354				354				—					—					354					354
Private Equity		—				—				54				54				—					—					54					54
Private Equity		—				—				54				54				—					—					54					54
Other debt obligations		—				19				—				19				—					19					—					19
Other debt obligations		—				19				—				19				—					19					—					19
Real Estate		—				—				1				1				—			—		—			—		1					1
Real Estate		—				—				1				1				—			—		—			—		1					1
Nuclear decommissioning trust fund investments subtotal(b)		3,967				5,724				644				10,335				3,967					5,724					644					10,335
Nuclear decommissioning trust fund investments subtotal(b)		3,967				5,724				644				10,335				3,967					5,724					644					10,335


		Generation																Exelon
As of September 30, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
Pledged assets for Zion Station decommissioning
Pledged assets for Zion Station decommissioning
Cash equivalents		—				12				—				12				—					12					—					12
Cash equivalents		—				12				—				12				—					12					—					12
Equity
Equity
Individually held		5				2				—				7				5					2					—					7
Individually held		5				2				—				7				5					2					—					7
Equity funds subtotal		5				2				—				7				5					2					—					7
Equity funds subtotal		5				2				—				7				5					2					—					7
Fixed income
Fixed income
Debt securities issued by the U.S.		13				2				—				15				13					2					—					15
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				19				—				19				—					19					—					19
United States and political
subdivisions of the states
Corporate debt securities		—				138				—				138				—					138					—					138
Corporate debt securities		—				138				—				138				—					138					—					138
Commingled funds		—				4				—				4				—			—		4			—		—			—		4
Commingled funds		—				4				—				4				—			—		4			—		—			—		4
Fixed income subtotal		13				163				—				176				13					163					—					176
Fixed income subtotal		13				163				—				176				13					163					—					176
Middle market lending		—				—				166				166				—					—					166					166
Middle market lending		—				—				166				166				—					—					166					166
Pledged assets for Zion Station		18				177				166				361				18					177					166					361
decommissioning subtotal(c)		18				177				166				361				18					177					166					361
Rabbi trust investments(e)
Mutual funds(d)		15				—				—				15				46					—					—					46
Mutual funds(d)		15				—				—				15				46					—					—					46
Rabbi trust investments subtotal		15				—				—				15				46					—					—					46
Rabbi trust investments subtotal		15				—				—				15				46					—					—					46
Commodity derivative assets
Economic hedges		396				2,523				1,683				4,602				396					2,523					1,683					4,602
Economic hedges		396				2,523				1,683				4,602				396					2,523					1,683					4,602
Proprietary trading		129				537				214				880				129					537					214					880
Proprietary trading		129				537				214				880				129					537					214					880
Effect of netting and allocation of collateral(f)		(563		)		(2,472		)		(1,213		)		(4,248		)		(563		)			(2,472		)			(1,213		)			(4,248		)
Commodity derivative assets subtotal		(38		)		588				684				1,234				(38		)			588					684					1,234
Commodity derivative assets subtotal		(38		)		588				684				1,234				(38		)			588					684					1,234
Interest rate and foreign currency derivative
assets
Derivatives designated as hedging instruments		—				13				—				13				—					25					—					25
Derivatives designated as hedging instruments		—				13				—				13				—					25					—					25
Economic hedges		—				7				—				7				—					12					—					12
Economic hedges		—				7				—				7				—					12					—					12
Proprietary trading		18				3				—				21				18					3					—					21
Proprietary trading		18				3				—				21				18					3					—					21
Effect of netting and allocation of collateral		(19		)		(5		)		—				(24		)		(19		)			(5		)			—					(24		)
Effect of netting and allocation of collateral		(19		)		(5		)		—				(24		)		(19		)			(5		)			—					(24		)
Interest rate and foreign currency derivative		(1		)		18				—				17				(1		)			35					—					34
assets subtotal		(1		)		18				—				17				(1		)			35					—					34
Other investments		13				—				3				16				13					—					3					16
Other investments		13				—				3				16				13					—					3					16
Total assets		4,918				6,507				1,497				12,922				5,881					6,524					1,497					13,902
Total assets		4,918				6,507				1,497				12,922				5,881					6,524					1,497					13,902
Liabilities
Commodity derivative liabilities
Economic hedges		(458		)		(2,194		)		(1,494		)		(4,146		)		(458		)			(2,194		)			(1,672		)			(4,324		)
Proprietary trading		(133		)		(555		)		(203		)		(891		)		(133		)			(555		)			(203		)			(891		)
Effect of netting and allocation of collateral(f)		591				2,672				1,444				4,707				591					2,672					1,444					4,707
Effect of netting and allocation of collateral(f)		591				2,672				1,444				4,707				591					2,672					1,444					4,707
Commodity derivative liabilities subtotal		—				(77		)		(253		)		(330		)		—					(77		)			(431		)			(508		)
Commodity derivative liabilities subtotal		—				(77		)		(253		)		(330		)		—					(77		)			(431		)			(508		)
Interest rate and foreign currency derivative
liabilities
Derivatives designated as hedging instruments		—				(2		)		—				(2		)		—					(12		)			—					(12		)
Derivatives designated as hedging instruments		—				(2		)		—				(2		)		—					(12		)			—					(12		)
Economic hedges		—				(9		)		—				(9		)		—					(22		)			—					(22		)
Economic hedges		—				(9		)		—				(9		)		—					(22		)			—					(22		)
Proprietary trading		(17		)		(3		)		—				(20		)		(17		)			(3		)			—					(20		)
Proprietary trading		(17		)		(3		)		—				(20		)		(17		)			(3		)			—					(20		)
Effect of netting and allocation of collateral		17				5				—				22				17					5					—					22
Effect of netting and allocation of collateral		17				5				—				22				17					5					—					22
Interest rate and foreign currency derivative		—				(9		)		—				(9		)		—					(32		)			—					(32		)
liabilities subtotal		—				(9		)		—				(9		)		—					(32		)			—					(32		)
Deferred compensation obligation		—				(29		)		—				(29		)		—					(105		)			—					(105		)
Deferred compensation obligation		—				(29		)		—				(29		)		—					(105		)			—					(105		)
Total liabilities		—				(115		)		(253		)		(368		)		—					(214		)			(431		)			(645		)
Total liabilities		—				(115		)		(253		)		(368		)		—					(214		)			(431		)			(645		)
Total net assets		$	4,918			$	6,392			$	1,244			$	12,554			$	5,881				$	6,310				$	1,066				$	13,257
Total net assets		$	4,918			$	6,392			$	1,244			$	12,554			$	5,881				$	6,310				$	1,066				$	13,257


		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
Cash equivalents(a)		$	1,006			$	—			$	—			$	1,006			$	1,230			$	—			$	—			$	1,230
Nuclear decommissioning trust fund investments
Cash equivalents		459				—				—				459				459				—				—				459
Cash equivalents		459				—				—				459				459				—				—				459
Equity
Individually held		1,776				—				—				1,776				1,776				—				—				1,776
Individually held		1,776				—				—				1,776				1,776				—				—				1,776
Exchange traded funds		115				—				—				115				115				—				—				115
Exchange traded funds		115				—				—				115				115				—				—				115
Commingled funds		—				2,271				—				2,271				—				2,271				—				2,271
Commingled funds		—				2,271				—				2,271				—				2,271				—				2,271
Equity funds subtotal		1,891				2,271				—				4,162				1,891				2,271				—				4,162
Equity funds subtotal		1,891				2,271				—				4,162				1,891				2,271				—				4,162
Fixed income
Debt securities issued by the U.S.		882				—				—				882				882				—				—				882
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				294				—				294				—				294				—				294
United States and political
subdivisions of the states
Debt securities issued by foreign		—				87				—				87				—				87				—				87
governments		—				87				—				87				—				87				—				87
Corporate debt securities		—				1,753				31				1,784				—				1,753				31				1,784
Corporate debt securities		—				1,753				31				1,784				—				1,753				31				1,784
Federal agency mortgage-backed		—				10				—				10				—				10				—				10
securities		—				10				—				10				—				10				—				10
Commercial mortgage-backed		—				40				—				40				—				40				—				40
securities (non-agency)		—				40				—				40				—				40				—				40
Residential mortgage-backed securities		—				7				—				7				—				7				—				7
(non-agency)		—				7				—				7				—				7				—				7
Mutual funds		—				18				—				18				—				18				—				18
Mutual funds		—				18				—				18				—				18				—				18
Fixed income subtotal		882				2,209				31				3,122				882				2,209				31				3,122
Fixed income subtotal		882				2,209				31				3,122				882				2,209				31				3,122
Middle market lending		—				—				314				314				—				—				314				314
Middle market lending		—				—				314				314				—				—				314				314
Private Equity		—				—				5				5				—				—				5				5
Private Equity		—				—				5				5				—				—				5				5
Other debt obligations		—				14				—				14				—				14				—				14
Other debt obligations		—				14				—				14				—				14				—				14
Nuclear decommissioning trust fund investments		3,232				4,494				350				8,076				3,232				4,494				350				8,076
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
Cash equivalents		—				26				—				26				—				26				—				26
Equity
Individually held		16				—				—				16				16				—				—				16
Individually held		16				—				—				16				16				—				—				16
Equity funds subtotal		16				—				—				16				16				—				—				16
Equity funds subtotal		16				—				—				16				16				—				—				16
Fixed income
Debt securities issued by the U.S.		45				4				—				49				45				4				—				49
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				20				—				20				—				20				—				20
United States and political
subdivisions of the states
Corporate debt securities		—				227				—				227				—				227				—				227
Corporate debt securities		—				227				—				227				—				227				—				227
Fixed income subtotal		45				251				—				296				45				251				—				296
Fixed income subtotal		45				251				—				296				45				251				—				296
Middle market lending		—				—				112				112				—				—				112				112
Middle market lending		—				—				112				112				—				—				112				112
Other debt obligations		—				1				—				1				—				1				—				1
Other debt obligations		—				1				—				1				—				1				—				1
Pledged assets for Zion Station		61				278				112				451				61				278				112				451
decommissioning subtotal(c)		61				278				112				451				61				278				112				451
Rabbi trust investments(e)
Cash equivalents		—				—				—				—				2				—				—				2
Cash equivalents		—				—				—				—				2				—				—				2
Mutual funds(d)		13				—				—				13				54				—				—				54
Mutual funds(d)		13				—				—				13				54				—				—				54
Rabbi trust investments subtotal		13				—				—				13				56				—				—				56
Rabbi trust investments subtotal		13				—				—				13				56				—				—				56




		Generation																Exelon
As of December 31, 2013		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Commodity derivative assets
Economic hedges		493				2,582				885				3,960				493				2,582				885				3,960
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
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
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		30				32				—				62				30				39				—				69
Effect of netting and allocation of collateral		(30		)		(2		)		—				(32		)		(30		)		(2		)		—				(32		)
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		—				30				—				30				—				37				—				37
Other investments		—				—				15				15				—				—				15				15
Other investments		—				—				15				15				—				—				15				15
Total assets		4,266				5,568				1,054				10,888				4,533				5,575				1,054				11,162
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
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		)
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		(31		)		(13		)		—				(44		)		(31		)		(17		)		—				(48		)
Effect of netting and allocation of collateral		31				1				—				32				31				1				—				32
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		—				(12		)		—				(12		)		—				(16		)		—				(16		)
Deferred compensation obligation		—				(29		)		—				(29		)		—				(114		)		—				(114		)
Deferred compensation obligation		—				(29		)		—				(29		)		—				(114		)		—				(114		)
Total liabilities		1				(180		)		(112		)		(291		)		1				(269		)		(305		)		(573		)
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
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 assets (liabilities) of $14 million and $(5) million at September 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(c)	Excludes net assets of $4 million and $7 million at September 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d)	The mutual funds held by the Rabbi trusts at Exelon include $45 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at September 30, 2014, and $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013.

(e)	Excludes $11 million and $35 million of cash surrender value of life insurance investment at September 30, 2014 and $10 million and $32 million of cash surrender value of life insurance investment at December 31, 2013 at Generation and Exelon, respectively.

(f)	Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties for commodity positions, net of collateral paid to counterparties, totaled $28 million, $200 million and $231 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2014. Collateral posted (received) 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 ComEd, PECO and BGE Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2014 and December 31, 2013:


		ComEd																PECO																BGE
As of September 30, 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		$	—			$	—			$	—			$	—			$	304			$	—			$	—			$	304			$	5	$	—		$	—	$	5
Cash equivalents		$	—			$	—			$	—			$	—			$	304			$	—			$	—			$	304			$	5	$	—		$	—	$	5
Rabbi trust investments
Mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		5
Mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		5
Rabbi trust investments		—				—				—				—				9				—				—				9				5		—			—		5
subtotal		—				—				—				—				9				—				—				9				5		—			—		5
Total assets		—				—				—				—				313				—				—				313				10		—			—		10
Total assets		—				—				—				—				313				—				—				313				10		—			—		10
Liabilities
Deferred compensation		—				(8		)		—				(8		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
obligation		—				(8		)		—				(8		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Mark-to-market derivative		—				—				(178		)		(178		)		—				—				—				—				—		—			—		—
liabilities (b)		—				—				(178		)		(178		)		—				—				—				—				—		—			—		—
Total liabilities		—				(8		)		(178		)		(186		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Total liabilities		—				(8		)		(178		)		(186		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Total net assets (liabilities)		$	—			$	(8	)		$	(178	)		$	(186	)		$	313			$	(15	)		$	—			$	298			$	10	$	(5	)	$	—	$	5
Total net assets (liabilities)		$	—			$	(8	)		$	(178	)		$	(186	)		$	313			$	(15	)		$	—			$	298			$	10	$	(5	)	$	—	$	5



		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
Cash equivalents		$	—			$	—			$	—			$	—			$	175			$	—			$	—			$	175			$	31	$	—		$	—	$	31
Rabbi trust investments
Mutual funds (a)		5				—				—				5				9				—				—				9				6		—			—		6
Mutual funds (a)		5				—				—				5				9				—				—				9				6		—			—		6
Rabbi trust investments subtotal		5				—				—				5				9				—				—				9				6		—			—		6
Rabbi trust investments subtotal		5				—				—				5				9				—				—				9				6		—			—		6
Total assets		5				—				—				5				184				—				—				184				37		—			—		37
Total assets		5				—				—				5				184				—				—				184				37		—			—		37
Liabilities
Deferred compensation obligation		—				(8		)		—				(8		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Deferred compensation obligation		—				(8		)		—				(8		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Mark-to-market derivative liabilities (b)		—				—				(193		)		(193		)		—				—				—				—				—		—			—		—
Mark-to-market derivative liabilities (b)		—				—				(193		)		(193		)		—				—				—				—				—		—			—		—
Total liabilities		—				(8		)		(193		)		(201		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Total liabilities		—				(8		)		(193		)		(201		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Total net assets (liabilities)		$	5			$	(8	)		$	(193	)		$	(196	)		$	184			$	(17	)		$	—			$	167			$	37	$	(6	)	$	—	$	31
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 September 30, 2014 and December 31, 2013.

(b)	The Level 3 balance includes the current and noncurrent liability of $14 million and $164 million at September 30, 2014, respectively, and $17 million and $176 million at December 31, 2013, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2014 and 2013:



		Generation																				ComEd				Exelon
Three Months Ended September 30, 2014		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of June 30, 2014		$	592			$	133			$	242			$	10			$	977			$	(134	)		$	843
Balance as of June 30, 2014		$	592			$	133			$	242			$	10			$	977			$	(134	)		$	843
Total realized / unrealized gains
(losses)
Included in net income		1				—				76			(a)	—				77				—				77
Included in net income		1				—				76			(a)	—				77				—				77
Included in noncurrent		3				—				—				—				3				—				3
payables to affiliates		3				—				—				—				3				—				3
Included in payable for Zion		—				(2		)		—				—				(2		)		—				(2		)
Station decommissioning		—				(2		)		—				—				(2		)		—				(2		)
Included in regulatory assets		—				—				—				—				—				(44		)		(44		)
Included in regulatory assets		—				—				—				—				—				(44		)		(44		)
Change in collateral		—				—				79				—				79				—				79
Change in collateral		—				—				79				—				79				—				79
Purchases, sales, issuances and
settlements
Purchases		83				53				12				—				148				—				148
Purchases		83				53				12				—				148				—				148
Sales		(8		)		(18		)		—				(7		)		(33		)		—				(33		)
Sales		(8		)		(18		)		—				(7		)		(33		)		—				(33		)
Settlements		(27		)		—				—				—				(27		)		—				(27		)
Settlements		(27		)		—				—				—				(27		)		—				(27		)
Transfers into Level 3		—				—				21				—				21				—				21
Transfers into Level 3		—				—				21				—				21				—				21
Transfers out of Level 3		—				—				1				—				1				—				1
Transfers out of Level 3		—				—				1				—				1				—				1
Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2014		$	1			$	—			$	163			$	—			$	164			$	—			$	164
		$	1			$	—			$	163			$	—			$	164			$	—			$	164



		Generation																				ComEd				Exelon
Nine Months Ended September 30, 2014		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of December 31, 2013		$	350			$	112			$	465			$	15			$	942			$	(193	)		$	749
Balance as of December 31, 2013		$	350			$	112			$	465			$	15			$	942			$	(193	)		$	749
Total realized / unrealized gains
(losses)
Included in net income		5				—				(284		)	(a)	—				(279		)		—				(279		)
Included in net income		5				—				(284		)	(a)	—				(279		)		—				(279		)
Included in noncurrent		14				—				—				—				14				—				14
payables to affiliates		14				—				—				—				14				—				14
Included in payable for Zion		—				2				—				—				2				—				2
Station decommissioning		—				2				—				—				2				—				2
Included in regulatory assets		—				—				—				—				—				15				15
Included in regulatory assets		—				—				—				—				—				15				15
Change in collateral		—				—				257				—				257				—				257
Change in collateral		—				—				257				—				257				—				257
Purchases, sales, issuances and
settlements
Purchases		331				95				27				2				455				—				455
Purchases		331				95				27				2				455				—				455
Sales		(10		)		(43		)		(6		)		(7		)		(66		)		—				(66		)
Sales		(10		)		(43		)		(6		)		(7		)		(66		)		—				(66		)
Settlements		(46		)		—				—				—				(46		)		—				(46		)
Settlements		(46		)		—				—				—				(46		)		—				(46		)
Transfers into Level 3		—				—				(9		)		—				(9		)		—				(9		)
Transfers into Level 3		—				—				(9		)		—				(9		)		—				(9		)
Transfers out of Level 3		—				—				(19		)		(7		)		(26		)		—				(26		)
Transfers out of Level 3		—				—				(19		)		(7		)		(26		)		—				(26		)
Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2014		$	3			$	—			$	(264	)		$	—			$	(261	)		$	—			$	(261	)
		$	3			$	—			$	(264	)		$	—			$	(261	)		$	—			$	(261	)


(a)	Includes an increase for the reclassification of $87 million and $20 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2014, respectively.

(b)	Includes $45 million of increases and $19 million of decreases in fair value and realized losses due to settlements of $1 million and realized gains due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2014, respectively.





		Generation																				ComEd				Exelon
Three Months Ended September 30, 2013		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives(c)				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of June 30, 2013		$	240			$	111			$	516			$	11			$	878			$	(85	)		$	793
Balance as of June 30, 2013		$	240			$	111			$	516			$	11			$	878			$	(85	)		$	793
Total realized / unrealized gains
(losses)
Included in net income		—				—				(32		)	(a)	—				(32		)		—				(32		)
Included in net income		—				—				(32		)	(a)	—				(32		)		—				(32		)
Included in noncurrent payables		(1		)		—				—				—				(1		)		—				(1		)
to affiliates		(1		)		—				—				—				(1		)		—				(1		)
Included in payable for Zion		—				—				—				—				—				—				—
Station decommissioning		—				—				—				—				—				—				—
Included in regulatory assets		—				—				—				—				—				(37		)		(37		)
Included in regulatory assets		—				—				—				—				—				(37		)		(37		)
Change in collateral		—				—				(30		)		—				(30		)		—				(30		)
Change in collateral		—				—				(30		)		—				(30		)		—				(30		)
Purchases, sales, issuances and
settlements
Purchases		23				10				8				—				41				—				41
Purchases		23				10				8				—				41				—				41
Sales		(14		)		(15		)		—				—				(29		)		—				(29		)
Sales		(14		)		(15		)		—				—				(29		)		—				(29		)
Settlements		(3		)		—				—				—				(3		)		—				(3		)
Settlements		(3		)		—				—				—				(3		)		—				(3		)
Transfers into Level 3		—				—				4				—				4				—				4
Transfers into Level 3		—				—				4				—				4				—				4
Transfers out of Level 3		—				—				(5		)		—				(5		)		—				(5		)
Transfers out of Level 3		—				—				(5		)		—				(5		)		—				(5		)
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2013		$	—			$	—			$	51			$	—			$	51			$	—			$	51
		$	—			$	—			$	51			$	—			$	51			$	—			$	51




		Generation																				ComEd				Exelon
Nine Months Ended September 30, 2013		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to- Market Derivatives(c)(d)				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of December 31, 2012		$	183			$	89			$	660			$	17			$	949			$	(293	)		$	656
Balance as of December 31, 2012		$	183			$	89			$	660			$	17			$	949			$	(293	)		$	656
Total realized / unrealized gains
(losses)
Included in net income		2				—				(8		)	(a)(b)	—				(6		)		—				(6		)
Included in net income		2				—				(8		)	(a)(b)	—				(6		)		—				(6		)
Included in other		—				—				(219		)	(b)	—				(219		)		—				(219		)
comprehensive income		—				—				(219		)	(b)	—				(219		)		—				(219		)
Included in noncurrent		8				—				—				—				8				226				234
payables to affiliates		8				—				—				—				8				226				234
Included in payable for Zion		—				1				—				—				1				—				1
Station decommissioning		—				1				—				—				1				—				1
Included in regulatory assets		—				—				—				—				—				(55		)		(55		)
Included in regulatory assets		—				—				—				—				—				(55		)		(55		)
Change in collateral		—				—				13				—				13				—				13
Change in collateral		—				—				13				—				13				—				13
Purchases, sales, issuances and
settlements
Purchases		90				43				16				2				151				—				151
Purchases		90				43				16				2				151				—				151
Sales		(27		)		(27		)		(8		)		(8		)		(70		)		—				(70		)
Sales		(27		)		(27		)		(8		)		(8		)		(70		)		—				(70		)
Settlements		(11		)		—				—				—				(11		)		—				(11		)
Settlements		(11		)		—				—				—				(11		)		—				(11		)
Transfers into Level 3		—				—				11				—				11				—				11
Transfers into Level 3		—				—				11				—				11				—				11
Transfers out of Level 3		—				—				(4		)		—				(4		)		—				(4		)
Transfers out of Level 3		—				—				(4		)		—				(4		)		—				(4		)
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2013		$	1			$	—			$	148			$	—			$	149			$	11			$	160
		$	1			$	—			$	148			$	—			$	149			$	11			$	160


(a)	Includes the reclassification of $83 million and $156 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013, respectively.

(b)	Includes $11 million of increases in fair value and realized gains due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the nine months ended September 30, 2013. This position eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	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 nine months ended September 30, 2013. This position eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(d)	Includes $37 million and $57 million of increases in fair value and realized losses due to settlements of $1 million and $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2013, respectively.

The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 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 three months ended September 30, 2014		$	70			$	6			$	1			$	70			$	6			$	1
		$	70			$	6			$	1			$	70			$	6			$	1
Total gains (losses) included in net income for the nine months ended September 30, 2014		(260		)		(24		)		5				(260		)		(24		)		5
		(260		)		(24		)		5				(260		)		(24		)		5
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2014		142				21				1				142				21				1
		142				21				1				142				21				1
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2014		(293		)		29				3				(293		)		29				3
		(293		)		29				3				(293		)		29				3



	Generation												Exelon
	Operating				Purchased				Other, net(a)				Operating				Purchased				Other, net(a)
	Revenues				Power and								Revenues				Power and
					Fuel												Fuel
Total gains (losses) included in net income for the three months ended September 30, 2013	$	(39	)		$	7			$	—			$	(39	)		$	7			$	—
	$	(39	)		$	7			$	—			$	(39	)		$	7			$	—
Total gains (losses) included in net income for the nine months ended September 30, 2013	(67		)		59				2				(61		)		60				2
	(67		)		59				2				(61		)		60				2
Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2013	42				9				—				42				9				—
	42				9				—				42				9				—
Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2013	71				77				1				81				78				1
	71				77				1				81				78				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. 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, 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 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. See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.
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.
As of September 30, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $344 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.

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 9 - 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 varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $3.57 and $0.45 for power and natural gas, respectively. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3. See ITEM 3. — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for information regarding the maturity by year of the Registrant’s mark-to-market derivative assets and liabilities.
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. See Note 9 —Derivative Financial Instruments for more information. The fair value of these swaps has been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk. The table below discloses the significant inputs to the forward curve used to value these positions.



Type of trade		Fair Value at September 30, 2014				Valuation		Unobservable		Range
Type of trade		Fair Value at September 30, 2014				Technique		Input		Range
Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	189			Discounted		Forward power		$13	-	$194	(d)
		$	189			Cash Flow		price		$13	-	$194	(d)
								Forward gas		$2.54	-	$22.15	(d)
								price		$2.54	-	$22.15	(d)
						Option Model		Volatility		8%	-	154%
						Option Model		percentage		8%	-	154%
Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	11			Discounted		Forward power		$14	-	$191	(d)
		$	11			Cash Flow		price		$14	-	$191	(d)
						Option Model		Volatility		8%	-	154%
						Option Model		percentage		8%	-	154%
Mark-to-market derivatives (ComEd)		$	(178	)		Discounted		Forward heat		8x	-	9x
Mark-to-market derivatives (ComEd)		$	(178	)		Cash Flow		rate(b)		8x	-	9x
								Marketability		3.50%	-	8%
								reserve		3.50%	-	8%
								Renewable		86%	-	126%
								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 $231 million as of September 30, 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 economic hedges would be approximately $146 and $10.62, respectively, and would be approximately $104 for power proprietary trading.



Type of trade		Fair Value at December 31, 2013				Valuation		Unobservable		Range
Type of trade		Fair Value at December 31, 2013				Technique		Input		Range
Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	488			Discounted		Forward power		$8	-	$176	(d)
		$	488			Cash Flow		price		$8	-	$176	(d)
								Forward gas		$2.98	-	$16.63	(d)
								price		$2.98	-	$16.63	(d)
						Option Model		Volatility		15%	-	142%
						Option Model		percentage		15%	-	142%
Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	3			Discounted		Forward power		$10	-	$176	(d)
		$	3			Cash Flow		price		$10	-	$176	(d)
						Option Model		Volatility		14%	-	19%
						Option Model		percentage		14%	-	19%
Mark-to-market derivatives (ComEd)		$	(193	)		Discounted		Forward heat		8x	-	9x
Mark-to-market derivatives (ComEd)		$	(193	)		Cash Flow		rate(b)		8x	-	9x
								Marketability		3.50%	-	8%
								reserve		3.50%	-	8%
								Renewable		84%	-	128%
								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)	9 Months Ended
	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments (Exelon, Generation, ComEd, PECO and BGE)	'
	Derivative Financial Instruments (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants use derivative instruments to manage commodity price risk and interest rate risk related to ongoing business operations.
	Commodity Price Risk (Exelon, Generation, ComEd, PECO and BGE)
	To the extent the amount of energy 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, effective with the date of merger with Constellation, 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 merger. Because the underlying forecasted transactions remain at least reasonably possible, the fair value of the effective portion of these cash flow hedges was frozen in accumulated OCI and reclassified to results of operations when the forecasted purchase or sale of the energy commodity occurs, or becomes probable of not occurring. None of Constellation’s designated cash flow hedges for commodity transactions prior to the merger were re-designated as cash flow hedges. The effect of this decision is that all derivative economic hedges for commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power procurement agreements, and natural gas supply agreements. Non-derivative contracts for access to additional generation and certain sales to load-serving entities are accounted for primarily under the accrual method of accounting, which is further discussed in Note 22 — Commitments and Contingencies of the Exelon 2013 Form 10-K. Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities.
	Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil fuels, and other commodities associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon management’s policies and hedging objectives, the market, weather conditions, operational and other factors. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
	In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Exelon's hedging program involves the hedging of commodity risk for Exelon's expected generation, typically on a ratable basis over a three-year period. This strategy has not changed as a result of recent and pending asset divestitures. As of September 30, 2014, the proportion of expected generation hedged is 98%-101%, 86%-89%, and 55%-58% for 2014, 2015, and 2016, respectively. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation. Expected generation is the volume of energy that best represents our financial exposure through owned or contracted capacity and reflects the divestiture impact of Fore River, Quail Run and West Valley; but does not reflect the divestiture impact of Generation's interest in Keystone and Conemaugh. See Note 4 — Mergers, Acquisitions and Dispositions and Note 21 — Subsequent Event for more detail regarding the divestitures. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts including Generation’s sales to ComEd, PECO and BGE to serve their retail load.
	On December 17, 2010, ComEd entered into several 20-year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term renewable energy and associated RECs. Delivery under the contracts began in June 2012. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts for energy and associated RECs were reduced for the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved in March 2014. These contracts are designed to lock in a portion of the long-term commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory asset or liability. See Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K for additional information.
	PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-approved DSP Programs, which are further discussed in Note 5 — Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts and block contracts. PECO has certain full requirements contracts and block contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative authoritative guidance.
	PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing approaches in order to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2014 PAPUC PGC settlement and to reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at least twelve months). Under the terms of the 2014 PGC settlement, PECO is required to lock in (i.e., economically hedge) the price of a minimum volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 30% of planned natural gas purchases in support of projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s financial position or results of operations as natural gas costs are fully recovered from customers under the PGC.
	BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates charged recover BGE’s wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE’s price risk related to electric supply procurement is limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not derivatives.
	BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally between shareholders and customers. BGE must also secure fixed price contracts for at least 10%, but not more than 20%, of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. All of BGE’s natural gas supply and asset management agreements qualify for the NPNS scope exception and result in physical delivery.
	Proprietary Trading. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which included settled physical sales volumes of 3,006 GWhs and 8,129 GWhs for the three and nine months ended September 30, 2014, respectively, and 2,499 GWhs and 6,066 GWhs for the three and nine months ended September 30, 2013, respectively, are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities. ComEd, PECO and BGE do not enter into derivatives for proprietary trading purposes.
	Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO and BGE)
	The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants 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 September 30, 2014, Exelon and Generation had $1,600 million and $700 million of notional amounts of fixed-to-floating hedges outstanding, respectively, and $2,431 million and $781 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 approximately a $7 million decrease in Exelon Consolidated pre-tax income for the nine months ended September 30, 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 currency hedges as of September 30, 2014.



			Generation																				Other							Exelon
	Description		Derivatives				Economic				Proprietary				Collateral				Subtotal				Derivatives				Economic			Total
			Designated				Hedges				Trading(a)				and								Designated				Hedges
			as Hedging												Netting(b)								as Hedging
			Instruments																				Instruments
	Mark-to-market derivative		$	—			$	4			$	14			$	(14	)		$	4			$	—			$	—		$	4
	assets (current assets)		$	—			$	4			$	14			$	(14	)		$	4			$	—			$	—		$	4
	Mark-to-market derivative		13				3				7				(10		)		13				12				5			30
	assets (noncurrent
	assets)
	Total mark-to-market		13				7				21				(24		)		17				12				5			34
	derivative assets		13				7				21				(24		)		17				12				5			34
	Mark-to-market derivative		(1		)		(7		)		(11		)		13				(6		)		—				—			(6		)
	liabilities (current
	liabilities)
	Mark-to-market derivative		(1		)		(2		)		(9		)		9				(3		)		(10		)		(13		)	(26		)
	liabilities (noncurrent
	liabilities)
	Total mark-to-market		(2		)		(9		)		(20		)		22				(9		)		(10		)		(13		)	(32		)
	derivative liabilities		(2		)		(9		)		(20		)		22				(9		)		(10		)		(13		)	(32		)
	Total mark-to-market		$	11			$	(2	)		$	1			$	(2	)		$	8			$	2			$	(8	)	$	2
	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				Hedges				Trading(a)				and								Designated
			as Hedging												Netting(b)								as Hedging
			Instruments																				Instruments
	Mark-to-market derivative assets		$	—			$	3			$	15			$	(19	)		$	(1	)		$	—			$	(1	)
	(current assets)		$	—			$	3			$	15			$	(19	)		$	(1	)		$	—			$	(1	)
	Mark-to-market derivative assets		26				3				15				(13		)		31				7				38
	(noncurrent assets)		26				3				15				(13		)		31				7				38
	Total mark-to-market derivative		26				6				30				(32		)		30				7				37
	assets		26				6				30				(32		)		30				7				37
	Mark-to-market derivative liabilities		(1		)		(1		)		(18		)		19				(1		)		—				(1		)
(current liabilities)			(1		)		(1		)		(18		)		19				(1		)		—				(1		)
Mark-to-market derivative liabilities		(10		)		(1		)		(13		)		13				(11		)		(4		)		(15		)
(noncurrent liabilities)		(10		)		(1		)		(13		)		13				(11		)		(4		)		(15		)
Total mark-to-market derivative		(11		)		(2		)		(31		)		32				(12		)		(4		)		(16		)
liabilities		(11		)		(2		)		(31		)		32				(12		)		(4		)		(16		)
Total mark-to-market derivative		$	15			$	4			$	(1	)		$	—			$	18			$	3			$	21
net assets (liabilities)		$	15			$	4			$	(1	)		$	—			$	18			$	3			$	21
_______________

(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:



			Three Months Ended September 30,
	Income Statement		2014				2013				2014				2013
	Location		Gain (Loss) on Swaps								Gain (Loss) on Borrowings
Generation	Interest expense(a)		$	(4	)		$	(4	)		$	1			$	(1	)
Generation	Interest expense(a)		$	(4	)		$	(4	)		$	1			$	(1	)
Exelon	Interest expense		(8		)		—				(6		)		(6		)
Exelon	Interest expense		(8		)		—				(6		)		(6		)

			Nine Months Ended September 30,
	Income Statement		2014				2013				2014				2013
	Location		Gain (Loss) on Swaps								Gain (Loss) on Borrowings
Generation	Interest expense(a)		$	(12	)		$	(13	)		$	1			$	—
Generation	Interest expense(a)		$	(12	)		$	(13	)		$	1			$	—
Exelon	Interest expense		(3		)		(12		)		6				(2		)
Exelon	Interest expense		(3		)		(12		)		6				(2		)
__________

(a)	For the three and nine months ended September 30, 2014, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with $2 million amount excluded from hedge effectiveness testing. For the three and nine months ended September 30, 2013, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with an immaterial excluded from hedge effectiveness testing.
During the first nine months of 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 September 30, 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 $24 million and $12 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 three and nine months ended September 30, 2014, the impact on the results of operations as a result of ineffectiveness from fair value hedges was a $6 million and a $14 million gain, respectively. During the three and nine months ended September 30, 2013, the impact on the results of operations as a result of ineffectiveness from fair value hedges was Immaterial.
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 of the Exelon 2013 Form 10-K, Generation entered into a floating-to-fixed forward starting interest rate swap with an initial notional amount of $485 million and a mandatory early termination date by 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 other comprehensive income, 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 Statement of Operations and Comprehensive Income over the term of the DOE loan.
During the third quarter of 2011, a subsidiary of Constellation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure for anticipated long-term borrowings to finance Sacramento PV Energy. The swaps have a total notional amount of $28 million as of September 30, 2014 and expire in 2027. After the closing of the merger with Constellation, the swaps were re-designated as cash flow hedges. At September 30, 2014, the subsidiary had a $2 million derivative liability related to these swaps.
During the third quarter of 2012, a subsidiary of Exelon Generation entered into a floating-to-fixed interest rate swap to manage a portion of the interest rate exposure of anticipated long-term borrowings to finance Constellation Solar Horizons. The swap has a notional amount of $26 million as of September 30, 2014 and expires in 2030. This swap is designated as a cash flow hedge. At September 30, 2014, the subsidiary had a $1 million derivative asset related to the swap.
During the first quarter of 2014, a subsidiary of Exelon Generation entered into floating-to-fixed interest rate swaps to manage a portion of the interest rate exposure with long-term borrowings to finance ExGen Renewables I, LLC. See Note 10 — Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $222 million as of September 30, 2014 and expire in 2020. The swaps are designated as cash flow hedges. At September 30, 2014, the subsidiary had a $1 million derivative liability related to the swaps.

During the first nine months of 2014, Exelon entered into $400 million of floating-to-fixed interest rate swaps to refinance existing debt. The swaps are designated as cash flow hedges. At September 30, 2014, Exelon had a $10 million derivative liability related to the swaps.
During the three and nine months ended September 30, 2014 and 2013, the impact on the results of operations as a result of ineffectiveness from cash flow hedges was immaterial.

Economic Hedges. During the first nine months of 2014, Exelon entered into $1,250 million of floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed merger with PHI. At September 30, 2014, Exelon had a $9 million derivative liability related to the swaps.

During the third quarter of 2014, a subsidiary of Exelon Generation entered into a floating-to-fixed interest rate swap to manage a portion of the interest rate exposure in connection with the long-term borrowings to finance ExGen Texas Power, LLC. See Note 10 - Debt and Credit Agreements for additional information regarding the financing. The swaps have a notional amount of $505 million as of September 30, 2014 and expire in 2019. At September 30, 2014, the subsidiary had a $3 million derivative liability related to the swaps.
At September 30, 2014, Exelon and Generation had $150 million in notional amounts of fixed-to-floating interest rate swaps that are marked-to-market. At September 30, 2014, Exelon and Generation had an immaterial derivative asset related to the swaps.

At September 30, 2014, Generation had $97 million in notional amounts of interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions and $322 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 and the impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, is aggregated in the collateral and netting column. As of September 30, 2014 and December 31, 2013, $43 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 September 30, 2014:



		Generation																ComEd				Exelon
Derivatives		Economic				Proprietary				Collateral				Subtotal(b)				Economic				Total
		Hedges				Trading				and								Hedges(c)				Derivatives
										Netting(a)
Mark-to-market derivative assets		$	3,230			$	752			$	(3,242	)		$	740			$	—			$	740
(current assets)		$	3,230			$	752			$	(3,242	)		$	740			$	—			$	740
Mark-to-market derivative assets		1,372				128				(1,006		)		494				—				494
(noncurrent assets)		1,372				128				(1,006		)		494				—				494
Total mark-to-market derivative		4,602				880				(4,248		)		1,234				—				1,234
assets		4,602				880				(4,248		)		1,234				—				1,234
Mark-to-market derivative liabilities		(3,017		)		(755		)		3,543				(229		)		(14		)		(243		)
(current liabilities)		(3,017		)		(755		)		3,543				(229		)		(14		)		(243		)
Mark-to-market derivative liabilities		(1,129		)		(136		)		1,164				(101		)		(164		)		(265		)
(noncurrent liabilities)		(1,129		)		(136		)		1,164				(101		)		(164		)		(265		)
Total mark-to-market derivative		(4,146		)		(891		)		4,707				(330		)		(178		)		(508		)
liabilities		(4,146		)		(891		)		4,707				(330		)		(178		)		(508		)
Total mark-to-market derivative		$	456			$	(11	)		$	459			$	904			$	(178	)		$	726
net assets (liabilities)		$	456			$	(11	)		$	459			$	904			$	(178	)		$	726
_________

(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 $(96) million and $(50) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(205) million and $(108) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $459 million at September 30, 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
Description		Economic				Proprietary				Collateral				Subtotal(b)				Economic				Total
		Hedges				Trading				and								Hedges(c)				Derivatives
										Netting(a)
Mark-to-market derivative assets		$	2,616			$	1,476			$	(3,364	)		$	728			$	—			$	728
(current assets)		$	2,616			$	1,476			$	(3,364	)		$	728			$	—			$	728
Mark-to-market derivative assets		1,344				285				(1,060		)		569				—				569
(noncurrent assets)		1,344				285				(1,060		)		569				—				569
Total mark-to-market derivative		3,960				1,761				(4,424		)		1,297				—				1,297
assets		3,960				1,761				(4,424		)		1,297				—				1,297
Mark-to-market derivative liabilities		(2,023		)		(1,410		)		3,292				(141		)		(17		)		(158		)
(current liabilities)		(2,023		)		(1,410		)		3,292				(141		)		(17		)		(158		)
Mark-to-market derivative liabilities		(804		)		(293		)		988				(109		)		(176		)		(285		)
(noncurrent liabilities)		(804		)		(293		)		988				(109		)		(176		)		(285		)
Total mark-to-market derivative		(2,827		)		(1,703		)		4,280				(250		)		(193		)		(443		)
liabilities		(2,827		)		(1,703		)		4,280				(250		)		(193		)		(443		)
Total mark-to-market derivative		$	1,133			$	58			$	(144	)		$	1,047			$	(193	)		$	854
net assets (liabilities)		$	1,133			$	58			$	(144	)		$	1,047			$	(193	)		$	854
________

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

(b)	Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. 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 and Generation). As discussed previously, effective prior to the merger with Constellation, Generation de-designated all of its cash flow hedges relating to commodity price risk. Because the underlying forecasted transactions remain at least reasonably possible, 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 $67 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. Generation expects the settlement of the majority of its cash flow hedges will occur during 2014.
The tables below provide the activity of accumulated OCI related to cash flow hedges for the three months ended September 30, 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.



				Total Cash Flow Hedge OCI Activity, Net of Income Tax
				Generation				Exelon
Three Months Ended September 30, 2014		Income Statement		Energy-Related				Total Cash Flow
Three Months Ended September 30, 2014		Location		Hedges				Hedges
Accumulated OCI derivative gain at June 30, 2014				$	57		(a)	$	47
Accumulated OCI derivative gain at June 30, 2014				$	57		(a)	$	47
Effective portion of changes in fair value				—				(3		)
Effective portion of changes in fair value				—				(3		)
Reclassifications from accumulated OCI to net income		Operating Revenues		(16		)	(b)	(16		)
Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
__________

(a)	Excludes $13 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2014 and June 30, 2014.

(b)	Amount is net of related income tax expense of $12 million for the three months ended September 30, 2014.


				Total Cash Flow Hedge OCI Activity, Net of Income Tax
				Generation				Exelon
Nine Months Ended September 30, 2014		Income Statement		Energy-Related				Total Cash Flow
Nine Months Ended September 30, 2014		Location		Hedges				Hedges
Accumulated OCI derivative gain at December 31, 2013				$	119		(a)	$	120
Accumulated OCI derivative gain at December 31, 2013				$	119		(a)	$	120
Effective portion of changes in fair value				—				(14		)
Effective portion of changes in fair value				—				(14		)
Reclassifications from accumulated OCI to net income		Operating Revenues		(78		)	(b)	(78		)
Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
______

(a)	Excludes $13 million and $5 million of losses, net of taxes, related to interest rate swaps and treasury locks as of September 30, 2014 and December 31, 2013, respectively.

(b)	Amount is net of related income tax expense of $52 million for the nine months ended September 30, 2014.


				Total Cash
				Flow Hedge OCI Activity,
				Net of Income Tax
				Generation				Exelon
Three Months Ended September 30, 2013		Income Statement		Energy-Related				Total Cash Flow
Three Months Ended September 30, 2013		Location		Hedges				Hedges
Accumulated OCI derivative gain at June 30, 2013				$	255		(a)	$	245
Accumulated OCI derivative gain at June 30, 2013				$	255		(a)	$	245
Effective portion of changes in fair value				—				2			(b)
Effective portion of changes in fair value				—				2			(b)
Reclassifications from accumulated OCI to net income		Operating Revenues		(51		)	(c)	(48		)
Accumulated OCI derivative gain at September 30, 2013				$	204		(a)	$	199
Accumulated OCI derivative gain at September 30, 2013				$	204		(a)	$	199
_____________

(a)	Excludes $11 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and June 30, 2013.

(b)	Includes $2 million of gains, 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 three months ended September 30, 2013.

(c)	Amount is net of related income tax expense of $33 million for the three months ended September 30, 2013.


				Total Cash
				Flow Hedge OCI Activity,
				Net of Income Tax
				Generation				Exelon
Nine Months Ended September 30, 2013		Income Statement		Energy-Related				Total Cash Flow
Nine Months Ended September 30, 2013		Location		Hedges				Hedges
Accumulated OCI derivative gain at December 31, 2012				$	532		(a) (c)	$	368
Accumulated OCI derivative gain at December 31, 2012				$	532		(a) (c)	$	368
Effective portion of changes in fair value				—				25			(d)
Effective portion of changes in fair value				—				25			(d)
Reclassifications from accumulated OCI to net income		Operating Revenues		(328		)	(b) (e)	(194		)
Accumulated OCI derivative gain at September 30, 2013				$	204		(c)	$	199
Accumulated OCI derivative gain at September 30, 2013				$	204		(c)	$	199
__________

(a)	Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012.

(b)	Includes $133 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(c)	Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and December 31, 2012, respectively.

(d)	Includes $25 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.

(e)	Amount is net of related income tax expense of $215 million for the nine months ended September 30, 2013.
During the three and nine months ended September 30, 2014 and 2013, 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 $28 million and a $130 million pre-tax gain and a $84 million and a $543 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.
The effect of Exelon’s former energy-related cash flow hedge activity on pre-tax earnings based on the reclassification adjustment from accumulated OCI to earnings was a $28 million and $130 million pre-tax gain for the three and nine months ended September 30, 2014, and a $84 million and $324 million pre-tax gain for the three and nine months ended September 30, 2013. Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods as all energy-related cash flow hedge positions were de-designated prior to the merger date.
Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps ("treasury") to manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other than U.S. Dollars. Exelon entered into floating-to-fixed forward starting interest rate swaps to manage interest rate risks associated with anticipated future debt issuance related to the proposed merger with PHI. For the three and nine months ended September 30, 2014 and 2013, the following pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues, purchased, power and fuel expense, or interest expense. For the three and nine months ended September 30, 2014 and 2013, the following pre-tax mark-to-market gains (losses) of certain purchase and sale contracts were reported in operating revenues or purchased power and fuel expense 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				HoldCo				Exelon
		Generation																Eliminations				HoldCo				Exelon
Three Months Ended September 30, 2014		Operating				Purchased				Interest Expense				Total				Operating				Interest				Total
		Revenues				Power												Revenues (a)				Expense
						and Fuel
Change in fair value of commodity		$	181			$	19			$	—			$	200			$	—			$	—			$	200
positions		$	181			$	19			$	—			$	200			$	—			$	—			$	200
Reclassification to realized at		86				(23		)		—				63				—				—				63
settlement of commodity positions		86				(23		)		—				63				—				—				63
Net commodity mark-to-market gains		267				(4		)		—				263				—				—				263
(losses)		267				(4		)		—				263				—				—				263
Change in fair value of treasury		5				—				(3		)		2				—				(8		)		(6		)
positions		5				—				(3		)		2				—				(8		)		(6		)
Reclassification to realized at		(1		)		—				—				(1		)		—				—				(1		)
settlement of treasury positions		(1		)		—				—				(1		)		—				—				(1		)
Net treasury mark-to-market gains		4				—				(3		)		1				—				(8		)		(7		)
(losses)		4				—				(3		)		1				—				(8		)		(7		)

Net mark-to-market gains (losses)		$	271			$	(4	)		$	(3	)		$	264			$	—			$	(8	)		$	256
Net mark-to-market gains (losses)		$	271			$	(4	)		$	(3	)		$	264			$	—			$	(8	)		$	256



		Generation																Intercompany				HoldCo				Exelon
		Generation																Eliminations				HoldCo				Exelon
Nine Months Ended September 30, 2014		Operating				Purchased				Interest				Total				Operating				Interest				Total
		Revenues				Power				Expense								Revenues(a)				Expense
						and Fuel
Change in fair value of commodity		$	(795	)		$	302			$	—			$	(493	)		$	—			$	—			$	(493	)
positions		$	(795	)		$	302			$	—			$	(493	)		$	—			$	—			$	(493	)
Reclassification to realized at		224				(207		)		—				17				—				—				17
settlement of commodity positions		224				(207		)		—				17				—				—				17
Net commodity mark-to-market gains		(571		)		95				—				(476		)		—				—				(476		)
(losses)		(571		)		95				—				(476		)		—				—				(476		)
Change in fair value of treasury		1				—				(5		)		(4		)		—				(8		)		(12		)
positions		1				—				(5		)		(4		)		—				(8		)		(12		)
Reclassification to realized at		(2		)		—				—				(2		)		—				—				(2		)
settlement of treasury positions		(2		)		—				—				(2		)		—				—				(2		)
Net treasury mark-to-market gains		(1		)		—				(5		)		(6		)		—				(8		)		(14		)
(losses)		(1		)		—				(5		)		(6		)		—				(8		)		(14		)

Net mark-to-market gains (losses)		$	(572	)		$	95			$	(5	)		$	(482	)		$	—			$	(8	)		$	(490	)
Net mark-to-market gains (losses)		$	(572	)		$	95			$	(5	)		$	(482	)		$	—			$	(8	)		$	(490	)




		Generation																Intercompany				HoldCo				Exelon
		Generation																Eliminations				HoldCo				Exelon
Three Months Ended September 30, 2013		Operating				Purchased				Interest Expense				Total				Operating				Interest				Total
		Revenues				Power												Revenues(a)				Expense
						and Fuel
Change in fair value of commodity		$	175			$	5			$	—			$	180			$	—			$	—			$	180
positions		$	175			$	5			$	—			$	180			$	—			$	—			$	180
Reclassification to realized at settlement		41				25				—				66				—				—				66
of commodity positions		41				25				—				66				—				—				66
Net commodity mark-to-market gains		216				30				—				246				—				—				246
(losses)		216				30				—				246				—				—				246
Change in fair value of treasury positions		—				—				—				—				—				—				—
Change in fair value of treasury positions		—				—				—				—				—				—				—
Reclassification to realized at settlement		—				—				—				—				—				—				—
of treasury positions		—				—				—				—				—				—				—
Net treasury mark-to-market gains		—				—				—				—				—				—				—
(losses)		—				—				—				—				—				—				—

Net mark-to-market gains (losses)		$	216			$	30			$	—			$	246			$	—			$	—			$	246
Net mark-to-market gains (losses)		$	216			$	30			$	—			$	246			$	—			$	—			$	246




		Generation																Intercompany				HoldCo				Exelon
		Generation																Eliminations				HoldCo				Exelon
Nine Months Ended September 30, 2013		Operating				Purchased				Interest Expense				Total				Operating				Interest				Total
		Revenues				Power												Revenues(a)				Expense
						and Fuel
Change in fair value of commodity		$	149			$	74			$	—			$	223			$	(6	)		$	—			$	217
positions		$	149			$	74			$	—			$	223			$	(6	)		$	—			$	217
Reclassification to realized at		(15		)		63				—				48				13				—				61
settlement of commodity positions		(15		)		63				—				48				13				—				61
Net commodity mark-to-market gains		134				137				—				271				7				—				278
(losses)		134				137				—				271				7				—				278
Change in fair value of treasury		—				—				(3		)		(3		)		—				—				(3		)
positions		—				—				(3		)		(3		)		—				—				(3		)
Reclassification to realized at		—				—				—				—				—				—				—
settlement of treasury positions		—				—				—				—				—				—				—
Net treasury mark-to-market gains		—				—				(3		)		(3		)		—				—				(3		)
(losses)		—				—				(3		)		(3		)		—				—				(3		)

Net mark-to-market gains (losses)		$	134			$	137			$	(3	)		$	268			$	7			$	—			$	275
Net mark-to-market gains (losses)		$	134			$	137			$	(3	)		$	268			$	7			$	—			$	275
______________

(a)	Prior to the 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 three and nine months ended September 30, 2014 and 2013, Exelon and Generation recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains (losses) (before income taxes) relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes and interest rate derivative contracts to hedge risk associated with the interest rate component of underlying commodity positions. Gains and losses associated with proprietary trading are reported as operating revenue in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.



	Location on Income		Three Months Ended September 30,								Nine Months Ended September 30,
	Statement		2014				2013				2014				2013
Change in fair value of commodity positions	Operating Revenues		$	(2	)		$	—			$	(2	)		$	1
Change in fair value of commodity positions	Operating Revenues		$	(2	)		$	—			$	(2	)		$	1
Reclassification to realized at settlement	Operating Revenues		(10		)		(39		)		(17		)		(34		)
of commodity positions	Operating Revenues		(10		)		(39		)		(17		)		(34		)
Net commodity mark-to-market gains (losses)	Operating Revenues		(12		)		(39		)		(19		)		(33		)

Change in fair value of treasury positions	Operating Revenues		1				—				—				—
Change in fair value of treasury positions	Operating Revenues		1				—				—				—
Reclassification to realized at settlement	Operating Revenues		—				(1		)		1				(2		)
of treasury positions	Operating Revenues		—				(1		)		1				(2		)
Net treasury mark-to-market gains (losses)	Operating Revenues		1				(1		)		1				(2		)
Net treasury mark-to-market gains (losses)	Operating Revenues		1				(1		)		1				(2		)

Net mark-to-market gains (losses)	Operating Revenues		$	(11	)		$	(40	)		$	(18	)		$	(35	)
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 September 30, 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 excludes credit risk exposure from individual retail counterparties, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $11 million, $21 million and $34 million, respectively.



Rating as of September 30, 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		$	1,240			$	88			$	1,152			1			$	423
Investment grade		$	1,240			$	88			$	1,152			1			$	423
Non-investment grade		23				7				16				—			—
Non-investment grade		23				7				16				—			—
No external ratings
Internally rated — investment grade		302				—				302				1			180
Internally rated — investment grade		302				—				302				1			180
Internally rated — non-investment		26				3				23				—			—
grade		26				3				23				—			—
Total		$	1,591			$	98			$	1,493			2			$	603
Total		$	1,591			$	98			$	1,493			2			$	603



Net Credit Exposure by Type of Counterparty		As of September 30, 2014
Financial institutions		$	264
Financial institutions		$	264
Investor-owned utilities, marketers, power producers		470
Investor-owned utilities, marketers, power producers		470
Energy cooperatives and municipalities		749
Energy cooperatives and municipalities		749
Other		10
Other		10
Total		$	1,493
Total		$	1,493
_____

(a)	As of September 30, 2014, credit collateral held from counterparties where Generation had credit exposure included $94 million of cash and $4 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 submittal. If the forward market price of energy exceeds the benchmark price, the suppliers are required to post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of September 30, 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 of the Exelon 2013 Form 10-K for additional information.
PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents PECO’s net credit exposure. As of September 30, 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 5 - Regulatory Matters for additional information.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust rates quarterly to reflect realized natural gas prices. PECO does not obtain collateral from suppliers under its natural gas supply and asset management agreements. As of September 30, 2014, PECO had credit exposure of $6 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 5 — Regulatory Matters for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. The amount of unsecured credit is determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth, subject to an unsecured credit cap. The credit position is based on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of September 30, 2014, BGE had a net credit exposure of $23 million to suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’ demands, which are not covered by the gas cost adjustment clause. At September 30, 2014, BGE's credit exposure related to off-system sales was immaterial.
Collateral and Contingent-Related Features (Exelon, Generation, ComEd, PECO and BGE)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e., NYMEX, ICE). The exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:



Credit-Risk Related Contingent Feature		30-Sep-14				31-Dec-13
Gross Fair Value of Derivative Contracts Containing this Feature(a)		$	(997	)		$	(1,056	)
Offsetting Fair Value of In-the-Money Contracts Under Master		694				846
Netting Arrangements(b)		694				846
Net Fair Value of Derivative Contracts Containing This Feature(c)		$	(303	)		$	(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 $669 million and letters of credit posted of $389 million and cash collateral held of $169 million and letters of credit held of $12 million as of September 30, 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 $2.1 billion and $2.0 billion as of September 30, 2014 and December 31, 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 September 30, 2014, Generation’s and Exelon's swaps were in an asset position, with a fair value of $8 million and $2 million, respectively.
See Note 24 — Segment Information of the Exelon 2013 Form 10-K for further information regarding the letters of credit supporting the cash collateral.
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and benchmark prices exceed established unsecured credit limits outlined in the contracts. As of September 30, 2014, ComEd held approximately $2 million from suppliers for the purpose of collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In addition, under the terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of September 30, 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 of the Exelon 2013 Form 10-K for additional information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2014, PECO was not required to post collateral for any of these agreements. If PECO lost its investment grade credit rating as of September 30, 2014, PECO could have been required to post approximately $25 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
BGE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain provisions that would require BGE to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by contract and by counterparty. As of September 30, 2014, BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade credit rating as of September 30, 2014, BGE could have been required to post approximately $47 million of collateral to its counterparties.

Debt_and_Credit_Agreements_Exe

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

9 Months Ended

Sep. 30, 2014

Debt Disclosure [Abstract]

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

Short-Term Borrowings

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

The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2014 and December 31, 2013:

Commercial Paper Borrowings

30-Sep-14

31-Dec-13

Exelon Corporate

—

Generation

—

ComEd

528

184

PECO

—

BGE

135

Credit Facilities

Exelon had bank lines of credit under committed credit facilities at September 30, 2014 for short-term financial needs, as follows:

Type of Credit Facility

Amount(a)

Expiration Dates

Capacity Type

(In billions)

Exelon Corporate

Syndicated Revolver(b)

0.5

May-19

Letters of credit and cash

Generation

Syndicated Revolver

5.1

May-19

Letters of credit and cash

Syndicated Revolver

0.2

Aug-18

Letters of credit and cash

Bilateral

0.3

December 2015 and March 2016

Letters of credit and cash

Bilateral

0.1

Jan-15

Letters of credit

Bilateral

0.1

Oct-14

Letters of credit and cash

ComEd

Syndicated Revolver

Mar-19

Letters of credit and cash

PECO

Syndicated Revolver(b)

0.6

May-19

Letters of credit and cash

BGE

Syndicated Revolver(b)

0.6

May-19

Letters of credit and cash

Total

8.5

(a)

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities 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 September 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $9 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.9 billion to support the PHI transaction discussed below, as well as, applicable asset divestitures.

(b)

Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.

As of September 30, 2014, there were no borrowings under the Registrants’ 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 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 and obtain letters of credit.

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, $600 million, respectively into May 2019, with the exception of a cumulative amount of $315 million in commitments, which expire in August 2018. Costs incurred to extend the facilities were not material.

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

Credit Agreements

In May 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and provide flexibility for timing of permanent financing. The bridge credit facility was subsequently reduced to $3.9 billion as a result of the June 2014 equity issuances discussed below, as well as, applicable asset divestitures. During the three and nine months ended September 30, 2014, Exelon recorded $11 million and $20 million to interest expense in connection with the bridge facility, respectively. It is not currently expected that Exelon will be required to draw upon this credit facility.

Long-Term Debt

Issuance of Long-Term Debt

During the nine months ended September 30, 2014, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Exelon

Junior Subordinated Notes

2.5

1-Jun-24

1,150

Used to finance a portion of the acquisition of PHI and for general corporate purposes

Generation

Nuclear Fuel Purchase Contract

3.35

30-Jun-18

Used for procurement of uranium

Generation

ExGen Renewables

LIBOR + 4.250%

February 6, 2021

300

Used for general corporate purposes

I Project Financing(a)

Generation

ExGen Texas Power Project Financing (a)

LIBOR + 4.750%

September 18, 2021

675

Used for general corporate purposes

Generation

Energy Efficiency Project Financing

4.12

December 31, 2015

Funding to install energy conservation measures in Washington, DC

Generation

AVSR DOE Project Financing

3.056% - 3.143%

January 5, 2037

125

Used for Antelope Valley solar development

Generation

Nuclear Fuel Purchase Contract

3.25

June 30, 2018

Used for procurement of uranium

ComEd

First Mortgage Bonds

2.15

January 15, 2019

300

Used to refinance existing mortgage bonds

Series 115

ComEd

First Mortgage Bonds

4.7

January 15, 2044

350

Used to refinance existing mortgage bonds

Series 116

PECO

First and Refunding Mortgage Bonds

4.15

October 1, 2044

300

Used to refinance existing mortgage bonds and general corporate purposes

(a) See ExGen Renewables I Project Financing and ExGen Texas Power Project Financing discussed below.

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 2.50% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017. The junior subordinated notes are expected to be remarketed in 2017. 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, the $1.15 billion of junior subordinated notes were 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.

Non-Recourse Debt

The following describes certain indebtedness that was incurred by Generation's project company subsidiaries during the nine months ended September 30, 2014. The indebtedness described below is a component of the total $2.7 billion net book value of certain generating facilities pledged as collateral as of September 30, 2014. All associated project financing liabilities are non-recourse to Exelon and Generation.

ExGen Renewables Energy I, LLC

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 non-recourse senior secured loan, due February 6, 2021. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% LIBOR floor. EGR indirectly owns Continental Wind LLC (Continental Wind). In addition to the financing, EGR entered into interest rate swaps with a 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 9 — Derivative Financial Instruments for additional information regarding interest rate swaps.

ExGen Texas Power, LLC

On September 18, 2014, ExGen Texas Power, LLC (EGTP), an indirect subsidiary of Exelon and Generation, borrowed $675 million aggregate principal amount pursuant to a non-recourse senior secured term loan, scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR floor. 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 a floating-to-fixed interest rate swap with an initial notional amount of approximately $505 million at an interest rate of 2.34% to manage a portion of the interest rate exposure in connection with this financing. See Note 9 — Derivative Financial Instruments for additional information regarding interest rate swaps.

During the nine months ended September 30, 2013, the following long-term debt was issued:

Company

Type

Interest Rate

Maturity

Amount

Use of Proceeds

Generation

Upstream Gas Lending

2.210 - 2.440%

July 22, 2016

Used to fund Upstream gas activities

Agreement

Generation

AVSR DOE Project Financing

2.535 - 3.353 %

January 5, 2037

204

Funding for Antelope Valley Solar Development

Generation

Energy Efficiency Project Financing

4.4

August 31, 2014

Funding to install energy conservation measures in Beckley, West Virginia

Generation

Continental Wind Senior Secured Notes

February 28, 2033

613

Used for general corporate purposes

ComEd

First Mortgage Bonds Series 114

4.6

August 15, 2043

350

Used to repay outstanding commercial paper obligations and for general corporate purposes

PECO

First and Refunding Mortgage Bonds

1.2

October 15, 2016

300

Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes

PECO

First and Refunding Mortgage Bonds

4.8

October 15, 2043

250

Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes

BGE

Senior Notes

3.35

July 1, 2023

300

Used to partially refinance Notes due July 1, 2013 and for general corporate purposes

Retirement and Redemptions of Current and Long-Term Debt

During the nine months ended September 30, 2014, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Generation

2003 Senior Notes

5.35

January 15, 2014

500

Generation

Pollution Control Loan

4.1

July 1, 2014

Generation

Continental Wind Project Financing

February 28, 2033

Generation

Kennett Square Capital Lease

7.83

September 20, 2020

Generation

ExGen Renewables I Project Financing

3mL + 4.25%

6-Feb-21

Generation

AVSR DOE Project Financing

2.33% - 3.55%

5-Jan-37

Generation

Clean Horizons Solar

2.56

7-Sep-30

Generation

Sacramento Solar Project Financing

2.56

31-Dec-30

Generation

Energy Efficiency Project Financing

4.4

31-Aug-14

ComEd

Mortgage Bonds Series 110

1.63

January 15, 2014

600

ComEd

Pollution Control Series 1994C

5.85

January 15, 2014

BGE

Rate Stabilization Bonds

5.72

April 1, 2017

On October 1, 2014, PECO retired $250 million aggregate principal of its 5.000% First and Refunding Mortgage Bonds due October 1, 2014.

On October 6, 2014, Generation paid down $11 million of principal and interest of its 3.056% - 3.143% AVSR Solar loan.

During the nine months ended September 30, 2013, the following long-term debt was retired and/or redeemed:

Company

Type

Interest Rate

Maturity

Amount

Generation

Kennett Square Capital Lease

7.83

September 20, 2020

Generation

Solar Revolver

1.930 - 1.950%

7-Jul-14

Generation

Clean Horizons Solar Project Financing

2.563

7-Sep-30

Generation(a)

Series A Junior Subordinated

8.625

15-Jun-63

450

Debentures

ComEd

First Mortgage Bonds Series 92

7.625

15-Apr-13

125

ComEd

First Mortgage Bonds Series 94

7.5

1-Jul-13

127

BGE

Senior Notes

6.125

1-Jul-13

400

BGE

Rate Stabilization Bonds

5.72

1-Apr-17

(a)

Represents debt obligations assumed by Exelon as part of the Constellation merger on March 12, 2012 that became callable at face value on June 15, 2013. 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, which are eliminated in consolidation on Exelon’s Consolidated Balance Sheets. The debentures were redeemed and the intercompany loan agreements repaid on June 15, 2013.

Income_Taxes_Exelon_Generation

Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)	'
	Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
	The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:



	For the Three Months Ended September 30, 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	1.1			0.7			5			0.1			4.6

	Qualified nuclear decommissioning trust fund income	(0.3	)		(0.4	)		—			—			—

	Domestic production activities deduction	(2.4	)		(3.2	)		—			—			—

	Health care reform legislation	—			—			0.2			—			0.2

	Amortization of investment tax credit, net deferred taxes	(1.0	)		(1.2	)		(0.3	)		(0.1	)		(0.3	)

	Plant basis differences	(0.8	)		—			—			(11.3	)		0.5

	Production tax credits and other credits	(1.9	)		(2.4	)		—			—			—

	Noncontrolling interest	(1.2	)		(1.6	)		—			—			—

	Other	(0.3	)		(1.4	)		0.1			(0.1	)		(1.2	)

	Effective income tax rate	28.2	%		25.5	%		40	%		23.6	%		38.8	%




	For the Nine Months Ended September 30, 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	0.5			(1.4	)		5			0.3			4.9

	Qualified nuclear decommissioning trust fund income	2			3.6			—			—			—

	Domestic production activities deduction	(2.7	)		(4.8	)		—			—			—

	Health care reform legislation	0.1			—			0.2			—			0.2

	Amortization of investment tax credit, net deferred taxes	(1.1	)		(1.7	)		(0.3	)		(0.1	)		(0.3	)
	Plant basis differences	(1.6	)		—			(0.3	)		(11.0	)		0.5

	Production tax credits and other credits	(2.1	)		(3.7	)		—			—			—

	Noncontrolling interest	(1.4	)		(2.6	)		—			—			—

	Other	(1.5	)		(2.5	)		0.1			0.1			(0.5	)

	Effective income tax rate	27.2	%		21.9	%		39.7	%		24.3	%		39.8	%



	For the Three Months Ended September 30, 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	3			2.6			5.4			(0.3	)		5.6

Qualified nuclear decommissioning trust fund income	3.5			5.3			—			—			—

Tax exempt income	(0.2	)		(0.3	)		—			—			—

Health care reform legislation	0.1			—			0.4			—			0.2

Amortization of investment tax credit, net deferred taxes	(1.5	)		(2.1	)		(0.4	)		(0.1	)		(0.3	)
Plant basis differences	(0.8	)		—			(0.4	)		(6.9	)		0.1

Production tax credits and other credits	(2.2	)		(3.3	)		—			—			—

Other	0.5			0.1			0.3			(0.1	)		(0.2	)

Effective income tax rate	37.4	%		37.3	%		40.3	%		27.6	%		40.4	%



For the Nine Months Ended September 30, 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	5.3			1.8			5.2			1.9			5.6

Qualified nuclear decommissioning trust fund income	3.2			5.1			—			—			—

Tax exempt income	(0.2	)		(0.3	)		—			—			—

Health care reform legislation	0.1			—			0.9			—			0.2

Amortization of investment tax credit, net deferred taxes	(2.3	)		(3.4	)		(0.8	)		(0.1	)		(0.3	)
Plant basis differences	(1.7	)		—			(1.2	)		(7.3	)		(0.4	)

Production tax credits and other credits	(2.4	)		(3.9	)		—			—			—

Other	0.2			1.1			0.8			—			—

Effective income tax rate	37.2	%		35.4	%		39.9	%		29.5	%		40.1	%

Accounting for Uncertainty in Income Taxes
Exelon, Generation, ComEd, PECO, and BGE have $1,808 million, $1,342 million, $151 million, $44 million, and $0 million, of unrecognized tax benefits as of September 30, 2014, respectively, and $2,175 million, $1,415 million, $324 million, $44 million, and $0 million, of unrecognized tax benefits as of December 31, 2013, respectively. The unrecognized tax benefits as of September 30, 2014 reflect a decrease at Exelon and ComEd primarily attributable to the like-kind exchange and the lease termination position discussed below and a decrease at Generation primarily due to the expiration of both federal and state statutes of limitation in September 2014.
Reasonably possible the 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.
Due to the possibility of final resolution through an appellate decision, Generation continues to believe that it is reasonably possible that the total amount of unrecognized tax benefits may significantly decrease in the next 12 months.
Settlement of Income Tax Audits
As of September 30, 2014, Exelon and Generation have approximately $180 million of unrecognized state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing federal and state audits and expected statute of limitation expirations that if recognized would decrease the effective tax rate. In September 2014, uncertain income tax positions were effectively settled due to the expiration of both federal and state statutes of limitation resulting in a reduction to unrecognized tax benefit of $75 million at Generation. Through the end of the third quarter, the effective settlement of unrecognized tax benefits has resulted in reduced tax expense of $90 million at Generation.
Other Income Tax Matters
Like-Kind Exchange
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned electric generation facilities which were properly leased back to the municipalities. The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999.
Exelon has been unable to reach agreement with the IRS regarding the dispute over the like-kind exchange position. The IRS has asserted that the Exelon purchase and leaseback transaction is substantially similar to a leasing transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction” that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS has asserted that the sale of the fossil plants followed by the purchase and leaseback of the municipal owned generation facilities does not qualify as a like-kind exchange and the gain on the sale is fully subject to tax. The IRS has also asserted a penalty of approximately $87 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 September 30, 2014 may be as much as $800 million, of which approximately $310 million would be attributable to ComEd after consideration of Exelon’s agreement to hold ComEd harmless, and the balance at Exelon. Litigation could take several years such that the estimated cash and interest impacts would likely change by a material amount.
In the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-owned electric generation properties in exchange for a net early termination amount of $335 million. The termination will result in a 2014 tax payment of approximately $285 million by Exelon, including approximately $155 million by ComEd representing the remaining gain deferred pursuant to the like-kind exchange transaction. In the event of a fully successful IRS challenge to Exelon’s like-kind exchange position, Exelon will be required to pay the full amount of tax and after-tax interest discussed in the preceding paragraph but will ultimately be entitled to a refund of the 2014 tax payment. See Note 7 — 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 estimated that adoption of the new method will result in a non-recurring cash tax detriment of approximately $100 - $120 million.

Nuclear_Decommissioning_Exelon

Nuclear Decommissioning (Exelon and Generation)	9 Months Ended
Nuclear Decommissioning (Exelon and Generation)	Sep. 30, 2014
Environmental Remediation Obligations [Abstract]	'
Nuclear Decommissioning (Exelon and Generation)	'
	Nuclear Decommissioning (Exelon and Generation)
	Nuclear Decommissioning Asset Retirement Obligations
	Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation generally updates its ARO annually during the third quarter, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
	The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2013 to September 30, 2014:



	Nuclear decommissioning ARO at December 31, 2013(a)	$	4,855
	Nuclear decommissioning ARO at December 31, 2013(a)	$	4,855
	Consolidation of CENG(b)	1,684
	Consolidation of CENG(b)	1,684
	Accretion expense	243
	Accretion expense	243
	Net decrease due to changes in, and timing of, estimated cash flows	(125		)
		(125		)
	Costs incurred to decommission retired plants	(5		)
	Nuclear decommissioning ARO at September 30, 2014(a)	$	6,652
	Nuclear decommissioning ARO at September 30, 2014(a)	$	6,652


	(a)	Includes $9 million as the current portion of the ARO at September 30, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

	(b)	Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

	During the nine months ended September 30, 2014, Generation’s ARO increased by approximately $1.8 billion. The increase is largely driven by the recording of an ARO on Exelon’s and Generation’s Consolidated Balance Sheets at fair value upon consolidation of CENG during the second quarter (see Note 6 — Investment in Constellation Energy Nuclear Group, LLC). The fair value of the ARO was considered an initial estimate requiring updates through the use of a third party engineering firm with corresponding adjustments expected to be recorded by the end of 2014. The ARO valuations for the Calvert Cliffs and Nine Mile Point nuclear units were updated during the third quarter of 2014 resulting in a $17 million reduction to the originally recorded ARO. The ARO valuation for the Ginna nuclear unit will be updated during the fourth quarter of 2014 once cost studies are completed. The ARO was also adjusted in the third quarter of 2014 to reflect the impacts of a reduction in estimated escalation rates, primarily for labor and energy costs, offset in part by an increase in the estimated costs to decommission the Byron and Braidwood nuclear units resulting from the completion of updated decommissioning costs studies received during 2014 as part of the annual assessment. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were primarily offset within Property, plant and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. Approximately $16 million of the reduction in the ARO resulted in a credit to income, which is included in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

	During the nine months ended September 30, 2013, Generation's ARO increased by approximately $51 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 CARFRs, which have increased from the prior year. The decrease in the ARO due to the changes in, and timing of, estimated cash flows were 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 the former ComEd, former PECO, former AmerGen and the CENG units have been funded with amounts collected from ComEd customers, PECO customers, and the previous owners of the former AmerGen and the CENG plants, respectively. Based on an ICC order, ComEd ceased collecting amounts from its customers to pay for decommissioning costs. 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. With respect to the former AmerGen and CENG units, Generation does not collect any amounts, nor is there any mechanism by which Generation can seek to collect additional amounts, from 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, on an aggregate basis for all former PECO units, compared to decommissioning obligations, as well as 5% of any additional shortfalls. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to collect additional amounts from ComEd customers for the former ComEd units or from the previous owners of the former AmerGen and CENG units. With respect to the former ComEd and PECO units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to the former AmerGen units and CENG 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 September 30, 2014 and December 31, 2013, Exelon and Generation had NDT fund investments totaling $10,349 million and $8,071 million, respectively.
	The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2014 and 2013:



		Exelon and Generation
		Three Months Ended September 30,						Nine Months Ended September 30,
		2014				2013		2014		2013
	Net unrealized gains (losses) on decommissioning trust	$	(107	)		$	103	$	126	$	196
	funds — Regulatory Agreement Units(a)	$	(107	)		$	103	$	126	$	196
	Net unrealized gains (losses) on decommissioning trust	(41		)		46		100		70
	funds — Non-Regulatory Agreement Units(b)(c)	(41		)		46		100		70



	(a)	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

	(b)	Excludes $7 million of net unrealized gains and $9 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2014 and 2013, respectively, and $27 million of net unrealized gains and $5 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 2014 and 2013, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.

	(c)	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
	Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.
	See Note 3 — Regulatory Matters and Note 25 — Related Party Transactions of the Exelon 2013 Form 10-K for information regarding regulatory liabilities at ComEd and PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
	Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, under which ZionSolutions has assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998. See Note 15 — Asset Retirement Obligations of the Exelon 2013 Form 10-K for information regarding the specific treatment of assets, including NDT funds, and decommissioning liabilities transferred in the transaction.
	ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds were reclassified to Pledged assets for Zion Station decommissioning within Generation’s and Exelon’s Consolidated Balance Sheets and will continue to be measured in the same manner as prior to the completion of the transaction. Additionally, the transferred ARO for decommissioning was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of the Zion Station NDT assets, net of applicable taxes, will be recorded as a change in the Payable to ZionSolutions. At no point will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station. Generation has retained its obligation for the SNF. Following ZionSolutions’ completion of its contractual obligations, Generation will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and will complete all remaining decommissioning activities associated with the SNF dry storage facility. Generation has a liability of approximately $85 million, which is included within the nuclear decommissioning ARO at September 30, 2014. Generation also has retained NDT assets to fund its obligation to maintain and transfer the SNF at Zion Station 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 payable to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2014 and December 31, 2013:



		Exelon and Generation
		30-Sep-14				31-Dec-13
	Carrying value of Zion Station pledged assets	$	365			$	458
	Carrying value of Zion Station pledged assets	$	365			$	458
	Payable to Zion Solutions(a)	334				414
	Payable to Zion Solutions(a)	334				414
Current portion of payable to Zion Solutions(b)	74				109
Current portion of payable to Zion Solutions(b)	74				109
Withdrawals by Zion Solutions to pay decommissioning costs(c)	618				498
	618				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.

(c)	Cumulative withdrawals since September 1, 2010.
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. 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 has 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 shutdown reactors. 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. On October 20, 2014, the NRC issued a 20 year renewal of the Limerick Units 1 and 2 operating licenses. With the additional 20 years of operating life for Limerick Unit 1, the parent guarantee is no longer required to provide adequate funding assurance. Generation intends to send to the NRC a notice of cancellation, which is required 120 days prior to cancellation.
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.

Retirement_Benefits_Exelon_Gen

Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)	'
	Retirement Benefits (Exelon, Generation, ComEd, PECO and BGE)
	Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all Generation, ComEd, PECO, BGE and BSC employees.
	As a result of the consolidation of CENG into Generation on April 1, 2014, 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. The plans include essentially all former employees at CENG. Exelon assumed sponsorship of the CENG pension and other postretirement benefit plans on July 14, 2014. CENG will fund the underfunded balances of the pension and other post retirement 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.
	Defined Benefit Pension and Other Postretirement Benefits
	During the first quarter of 2014, Exelon received an updated valuation of several of its 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 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 benefit 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, accumulated other comprehensive loss 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 in the net periodic benefit costs for other postretirement benefits of approximately $149 million for the period May 2014 through December 2014 as compared to the net periodic benefit costs that were anticipated based on the January 1, 2014 valuation. The remeasurement resulted in a decrease in Exelon's non-pension postretirement benefit obligations, regulatory assets, and accumulated other comprehensive loss of approximately $790 million, $240 million , and $259 million (after tax), respectively, and an increase in regulatory liabilities of approximately $125 million .
	The following tables present the components of Exelon’s net periodic benefit costs for the three and nine months ended September 30, 2014 and 2013. 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%. 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 the three and nine months ended September 30, 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 September 30, 2014 and reflect the valuation performed on April 1, 2014. 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 2014 other postretirement benefit cost is calculated using a discount rate of 4.55%. A portion of the net periodic benefit cost is capitalized within the Consolidated Balance Sheets.



		Pension Benefits						Other
		Three Months Ended						Postretirement Benefits
		September 30,						Three Months Ended
								September 30,
		2014(a)			2013(a)			2014(a)			2013(a)
	Service cost	$	74		$	79		$	27		$	41

	Interest cost	189			163			42			48

	Expected return on assets	(251		)	(253		)	(39		)	(33		)
	Amortization of:
	Prior service cost (benefit)	3			3			(44		)	(4		)

	Actuarial loss	106			140			15			20

	Settlement charges	—			9			—			—

	Net periodic benefit cost	$	121		$	141		$	1		$	72



		Pension Benefits						Other
		Nine Months Ended						Postretirement Benefits
		September 30,						Nine Months Ended
								September 30,
		2014(b)			2013(b)			2014(b)			2013(b)
	Service cost	$	218		$	238		$	90		$	122

	Interest cost	561			488			144			145

	Expected return on assets	(743		)	(761		)	(115		)	(99		)
	Amortization of:
	Prior service cost (benefit)	10			10			(79		)	(14		)

	Actuarial loss	316			421			35			62

	Settlement charges	—			9			—			—

	Net periodic benefit cost	$	362		$	405		$	75		$	216

	___________

	(a)	For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. CENG is not included in the 2013 amounts.

	(b)	For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.

	The amounts below represent Generation’s, ComEd’s, PECO’s, BGE’s and BSC's allocated portion of the pension and postretirement benefit plan costs, which were included in Capital expenditures and Operating and maintenance expense during the three and nine months ended September 30, 2014 and 2013.



			Three Months Ended September 30,						Nine Months Ended September 30,
	Pension and Other Postretirement Benefit Costs		2014			2013			2014			2013
	Generation(a)		$	54		$	87		$	193		$	259

ComEd		33			77			129			231

PECO		7			11			28			32

BGE		17			14			50			41

BSC(b)		11			24			37			58

______________

(a)	For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.

(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.
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, management of the pension obligation and regulatory implications. Exelon expects to make qualified pension plan contributions of $308 million to its qualified pension plans in 2014, of which Generation, ComEd, PECO and BGE will contribute $160 million, $119 million, $11 million and $0 million, respectively. Exelon's and Generation's expected qualified pension plan contributions above include $53 million and $51 million, respectively, related to the CENG plans for the period April 1, 2014 to December 31, 2014, of which $43 million will be funded by CENG as agreed to in the EMA. Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded. Exelon expects to make non-qualified pension plan benefit payments of $18 million in 2014, of which Generation, ComEd, PECO and BGE will make payments of $9 million, $1 million, $0 million and $1 million, respectively. Exelon's and Generation's expected non-qualified pension plan benefit payments above include $3 million related to the CENG plans for the period April 1, to December 31, 2014.
Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and certain plans are not funded. Exelon’s management has historically considered several factors in determining the level of contributions to its funded other postretirement benefit plans, including levels of benefit claims paid and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued rate recovery). Exelon expects to make other postretirement benefit plan contributions, including benefit payments related to unfunded plans and reflecting the impact of recent plan design changes, of approximately $290 million in 2014, of which Generation, ComEd, PECO and BGE expect to contribute $128 million, $121 million, $4 million and $18 million, respectively. Exelon's and Generation's expected other postretirement benefit plan payments above include $5 million related to the CENG plans for the period April 1, 2014 to December 31, 2014.

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 may increase or decrease the liability hedging portfolio as the funded status of its plans changes. The overall objective is to achieve long term investment returns that, taking into account projected contributions and liquidity requirements, provide sufficient assets to meet current and future benefit obligations while maintaining acceptable levels of funding status volatility. 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.
Defined Contribution Savings Plans
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2014 and 2013:



		Three Months Ended September 30,						Nine Months Ended September 30,
Savings Plan Matching Contributions		2014			2013			2014			2013
Exelon(a)		$	34		$	18		$	82		$	61

Generation(a)		17			8			41			29

ComEd		8			6			20			16

PECO		2			2			6			6

BGE		3			1			7			5

BSC(b)		4			1			8			5

_______________

(a)	Includes $1 million related to CENG for the three months ended September 30, 2014 and for the period from April 1, 2014 to September, 30 2014. CENG is not included in the 2013 amounts.

(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Severance_Exelon_Generation_Co

Severance (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
Restructuring Charges [Abstract]	'
Severance (Exelon, Generation, ComEd, PECO and BGE)	'
	Severance (Exelon, Generation, ComEd, PECO and BGE)

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

	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. 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 CENG severance liability pursuant to the Master Agreement. Generation adjusts its accrual each quarter to reflect its best estimate of remaining severance costs. The estimated amount of severance payments associated with this plan is expected to be approximately $27 million. As of September 30, 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 September 30, 2014 are not material.

	Amounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration:


	Nine Months Ended September 30, 2014
	Severance Liability		Exelon and Generation
	Balance at December 31, 2013		$	2

	Integration of CENG(a)		19

	Severance charges		2

	Payments		(7		)
	Balance at September 30, 2014		$	16

	_______________

	(a)	Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this does not include $4 million of severance charges that were paid out prior to consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

	Cash payments under the severance plan began by CENG in the first quarter of 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.

	The amount of severance expense associated with the post-merger integration recognized for the three and nine months ended September 30, 2014 and 2013 is not material. Estimated costs to be incurred after September 30, 2014 are not material.

	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:



	Nine Months Ended September 30, 2014
	Severance Liability		Exelon				Generation				ComEd			PECO			BGE
	Balance at December 31, 2013		$	53			$	10			$	—		$	—		$	6

	Payments		(36		)		(5		)		—			—			(4		)

	Balance at September 30, 2014		$	17			$	5			$	—		$	—		$	2

	Substantially all cash payments under the plan are expected to be made by the end of 2016.
	Ongoing Severance Plans

	The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees in the normal course of business, which are not directly related to the merger with Constellation or with the integration of CENG. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.
	For the three and nine months ended September 30, 2014 and 2013, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:



			Exelon				Generation				ComEd			PECO			BGE
	Three Months Ended
	30-Sep-14		$	(2	)		$	(2	)		$	—		$	—		$	—

	30-Sep-13		$	12			$	11			$	1		$	—		$	—



			Exelon				Generation				ComEd			PECO			BGE
	Nine Months Ended
	30-Sep-14		$	4			$	3			$	1		$	—		$	—

30-Sep-13		$	14			$	12			$	2		$	—		$	—

The severance liability balances associated with these ongoing severance benefits as of September 30, 2014 and December 31, 2013 are not material.

Changes_in_Accumulated_Other_C

Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
Changes in Accumulated Other Comprehensive Income [Abstract]	'
Changes in Accumulated Other Comprehensive Income (Exelon, Generation, ComEd, PECO and BGE)	'
	Changes in Accumulated Other Comprehensive Income (Exelon, Generation, and PECO)
	The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the nine months ended September 30, 2014 and 2013:



	Nine Months Ended September 30, 2014		Gains				Unrealized				Pension and				Foreign				AOCI of				Total
			and				Gains and				Non-Pension				Currency				Equity
			(Losses)				(Losses) on				Postretirement				Items				Investments
			on Cash				Marketable				Benefit Plan
			Flow Hedges				Securities				Items
	Exelon(a)
	Beginning balance		$	120			$	2			$	(2,260	)		$	(10	)		$	108			$	(2,040	)

	OCI before reclassifications		(14		)		(2		)		240				(6		)		11				229

	Amounts reclassified from AOCI(b)		(78		)		—				91				—				(119		)		(106		)

	Net current-period OCI		(92		)		(2		)		331				(6		)		(108		)		123

	Ending balance		$	28			$	—			$	(1,929	)		$	(16	)		$	—			$	(1,917	)

	Generation(a)
	Beginning balance		$	114			$	2			$	—			$	(10	)		$	108			$	214

	OCI before reclassifications		(8		)		(3		)		—				(6		)		11				(6		)

	Amounts reclassified from AOCI(b)		(78		)		—				—				—				(119		)		(197		)

	Net current-period OCI		(86		)		(3		)		—				(6		)		(108		)		(203		)

	Ending balance		$	28			$	(1	)		$	—			$	(16	)		$	—			$	11

	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 tables following changes in accumulated other comprehensive income tables for details about these reclassifications.



	Nine Months Ended September 30, 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		25				(1		)		73				(5		)		46				138

	Amounts reclassified from AOCI(b)		(194		)		—				157				—				5				(32		)

Net current-period OCI		(169		)		(1		)		230				(5		)		51				106

Ending balance		$	199			$	(1	)		$	(2,907	)		$	(5	)		$	53			$	(2,661	)

Generation(a)
Beginning balance		$	512			$	—			$	—			$	—			$	1			$	513

OCI before reclassifications		12				(1		)		—				(5		)		47				53

Amounts reclassified from AOCI(b)		(328		)		—				—				—				5				(323		)

Net current-period OCI		(316		)		(1		)		—				(5		)		52				(270		)

Ending balance		$	196			$	(1	)		$	—			$	(5	)		$	53			$	243

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 tables following changes in accumulated other comprehensive income tables for details about these reclassifications.

ComEd, PECO, and BGE did not have any reclassifications out of AOCI to net income during the three and nine months ended September 30, 2014 and 2013. The following tables present amounts reclassified out of AOCI to Net Income for Exelon and Generation during the three and nine months ended September 30, 2014 and 2013.

Three Months Ended September 30, 2014


Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
										where Net Income is presented
		Exelon				Generation
Gains on cash flow hedges
Energy related hedges		$	28			$	28			Operating revenues

		28				28				Total before tax

		(12		)		(12		)		Tax (expense)
		$	16			$	16			Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs		$	19			$	—			(b)

Actuarial losses		(61		)		—				(b)

		(42		)		—				Total before tax

		16				—				Tax benefit

		$	(26	)		$	—			Net of tax

Equity investments
Sale of equity method investment		$	5			$	5			Other, net

		5				5				Total before tax

		(2		)		(2		)		Tax (expense)
		$	3			$	3			Net of tax

Total Reclassifications for the period		$	(7	)		$	19			Net of Tax


Nine Months Ended September 30, 2014


Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
										where Net Income is presented
		Exelon				Generation
Gains on cash flow hedges
Energy related hedges		$	130			$	130			Operating revenues

		130				130				Total before tax

		(52		)		(52		)		Tax (expense)
		$	78			$	78			Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs		$	29			$	—			(b)

Actuarial losses		(178		)		—				(b)

		(149		)		—				Total before tax

		58				—				Tax benefit

		$	(91	)		$	—			Net of tax

Equity investments
Sale of equity method investment		$	5			$	5			Other, net

Reversal of CENG equity method AOCI		193				193				Gain on consolidation of CENG

		198				198				Total before tax

		(79		)		(79		)		Tax (expense)
		$	119			$	119			Net of tax

Total reclassifications for the period		$	106			$	197			Net of Tax

Three Months Ended September 30, 2013


Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
										where Net Income is presented
		Exelon				Generation
Gains on cash flow hedges
Energy related hedges		$	84			$	84			Operating revenues

Other cash flow hedges		(1		)		(1		)		Interest expense
		83				83				Total before tax

		(35		)		(33		)		Tax (expense)
		$	48			$	50			Net of tax

Amortization of pension and other postretirement benefit plan items
Actuarial losses		$	(92	)		$	—			(b)

Deferred compensation unit plan		(1		)		—				(c)

		(93		)		—				Total before tax

		37				—				Tax benefit

		$	(56	)		$	—			Net of tax

Equity investments
Capital Activity		$	—			$	—			Equity in losses of unconsolidated affiliates

		—				—				Total before tax

		—				—				Tax benefit

		$	—			$	—			Net of tax

Total Reclassifications for the period		$	(8	)		$	50			Net of Tax


Nine Months Ended September 30, 2013


Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
										where Net Income is presented
		Exelon				Generation
Gains on cash flow hedges
Energy related hedges		$	324			$	543			Operating revenues

Other cash flow hedges		(2		)		—				Interest (expense) or benefit

		322				543				Total before tax

		(128		)		(215		)		Tax (expense)
		$	194			$	328			Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs		$	(1	)		$	—			(b)

Actuarial losses		(257		)		—				(b)

Deferred compensation unit plan		(1		)		—				(c)

		(259		)		—				Total before tax

		102				—				Tax benefit

		$	(157	)		$	—			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 for the period		$	32			$	323			Net of Tax

____________

(a)	All amounts are net of tax. 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 13— Retirement Benefits for additional details).

(c)	Amortization of deferred compensation unit 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 three and nine months ended September 30, 2014 and 2013:



	Three Months Ended September 30,								Nine Months Ended September 30,
	2014				2013				2014				2013
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	$	8			$	—			11				$	—

Actuarial gain (loss) reclassified to periodic cost	(24		)		33				(69		)		97

Pension and non-pension postretirement benefit plans valuation adjustment	5				(6		)		(153		)		44

Change in unrealized gain (loss) on cash flow hedges	15				(35		)		62				(109		)

Change in unrealized income on equity investments	3				9				73				32

Deferred compensation unit valuation adjustment	—				—				—				6

Change in unrealized loss on marketable securities	1				—				(1		)		—

Total	$	8			$	1			$	(77	)		$	70


Generation
Change in unrealized gain (loss) on cash flow hedges	$	13			$	(36	)		$	57			$	(209	)

Change in unrealized income on equity investments	3				9				73				32

Change in marketable securities	1				—				(1		)		—

Total	$	17			$	(27	)		$	129			$	(177	)

Common_Stock_Exelon_Generation

Common Stock (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
Common Stock (Exelon, Generation, ComEd, PECO and BGE)	Sep. 30, 2014
Common Stock [Abstract]	'
Common Stock (Exelon, Generation, ComEd, PECO and BGE)	'
	16. Common Stock (Exelon, Generation, ComEd, PECO and BGE)
	Equity Securities Offering
	In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such offering, Exelon entered into forward sale agreements requiring Exelon to, 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 $1.85 billion and $1.95 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 September 30, 2014, Exelon would not have been required to issue shares, as the average share price during the quarter was below the forward price of $33.58 per share. 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 10 — Debt and Credit Agreements for further information on the equity units.

Earnings_Per_Share_and_Equity_

Earnings Per Share and Equity (Exelon)	9 Months Ended
	Sep. 30, 2014
Earnings Per Share [Abstract]	'
Earnings Per Share and Equity (Exelon)	'
	Earnings Per Share and Equity (Exelon)
	Earnings per Share (Exelon)

	Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of shares of common stock outstanding adjusted to include the potentially dilutive effect of stock options, performance share awards and restricted stock outstanding under Exelon’s LTIPs. The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share:


		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	Net income attributable to common shareholders	$	993	$	738	$	1,604	$	1,224

	Average common shares outstanding — basic	861		857		860		856

	Potentially dilutive effect of stock options, performance share awards and restricted stock	2		3		3		4

	Average common shares outstanding — diluted	863		860		863		860

	The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 16 million for the three and nine months ended September 30, 2014 and 20 million for the three and nine months ended September 30, 2013. 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 approximately 2 million for the three months ended September 30, 2014 and 1 million since issuance. The number of forward units related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 2 million for the three months ended September 30, 2014 and less than 1 million since issuance.
	Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of September 30, 2014. In 2008, Exelon management decided to defer indefinitely any share repurchases.

	Preferred Securities Redemption (Exelon and PECO)
	On March 25, 2013, PECO announced that it issued a notice of redemption for all of its outstanding preferred securities with a redemption date of May 1, 2013. 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 of securities were issued. The redemption premium of $6 million is 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. As a result of the redemption, PECO is now indirectly, wholly-owned by Exelon.

Commitments_and_Contingencies_

Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 2014
Commitments and Contingencies Disclosure [Abstract]	'
Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)	'
	Commitments and Contingencies (Exelon, Generation, ComEd, PECO and BGE)

	The following is an update to the current status of commitments and contingencies set forth in Note 22 of the Exelon 2013 Form 10-K.

	Commitments

	Energy Commitments

	As of September 30, 2014, Generation’s commitments relating to its purchases from unaffiliated utilities and others of energy, capacity, transmission rights and RECs, are as indicated in the following table:



		Net Capacity				REC				Transmission				Total
		Purchases(a)				Purchases(b)				Rights
										Purchases(c)
	2014	$	91			$	7			$	6			$	104
	2014	$	91			$	7			$	6			$	104
	2015	396				162				20				578
	2015	396				162				20				578
	2016	269				166				15				450
	2016	269				166				15				450
	2017	208				80				15				303
	2017	208				80				15				303
	2018	98				15				16				129
	2018	98				15				16				129
	Thereafter	389				4				51				444
	Thereafter	389				4				51				444
	Total	$	1,451			$	434			$	123			$	2,008
	Total	$	1,451			$	434			$	123			$	2,008

	____________________

	(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 September 30, 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 September 30, 2014, capacity offsets were $23 million, $132, million $133 million, $136, million, $137 million, and $729 million for years 2014, 2015, 2016, 2017, 2018, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.

	(b)	The table excludes renewable energy purchases that are contingent in nature.

	(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
	ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments, as applicable, as of September 30, 2014 are as follows:



						Expiration within
		Total				2014				2015				2016				2017				2018			2019
		Total				2014				2015				2016				2017				2018			and beyond
	ComEd
	Electric supply procurement(a)	$	731			$	111			$	329			$	151			$	140			$	—		$	—
	Electric supply procurement(a)	$	731			$	111			$	329			$	151			$	140			$	—		$	—
	Renewable energy and RECs(b)	1,538				22				73				76				77				78			1,212
	Renewable energy and RECs(b)	1,538				22				73				76				77				78			1,212
	PECO
	Electric supply procurement(c)	498				193				305				—				—				—			—
	Electric supply procurement(c)	498				193				305				—				—				—			—
	AECs(d)	13				1				2				2				2				2			4
	AECs(d)	13				1				2				2				2				2			4
	BGE
	Electric supply procurement(e)	1,055				198				621				236				—				—			—
	Electric supply procurement(e)	1,055				198				621				236				—				—			—
	Curtailment services(f)	125				10				40				34				29				12			—
	Curtailment services(f)	125				10				40				34				29				12			—
	___________________

	(a)	ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of September 30, 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 2014 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 — Regulatory Matters for additional information.

(d)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 5 — Regulatory Matters for additional information.

(e)	BGE entered into various contracts for the procurement of electricity that expire between 2014 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 5 — 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 5 —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, all 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 September 30, 2014, these net commitments were as follows:



					Expiration within
	Total				2014				2015				2016				2017				2018			2019
	Total				2014				2015				2016				2017				2018			and beyond
Generation	$	9,636			$	351			$	1,512			$	1,226			$	1,271			$	1,003		$	4,273
Generation	$	9,636			$	351			$	1,512			$	1,226			$	1,271			$	1,003		$	4,273
PECO	387				57				120				94				35				15			66
PECO	387				57				120				94				35				15			66
BGE	624				40				115				81				64				53			271
BGE	624				40				115				81				64				53			271

Other Purchase Obligations

The Registrants’ other purchase obligations as of September 30, 2014, which primarily represent commitments for services, materials and information technology, are as follows:



					Expiration within
	Total				2014				2015				2016				2017				2018			2019
	Total				2014				2015				2016				2017				2018			and beyond
Exelon	$	917			$	103			$	324			$	180			$	151			$	36		$	123
Exelon	$	917			$	103			$	324			$	180			$	151			$	36		$	123
Generation(a)(b)	493				80				182				57				43				30			101
Generation(a)(b)	493				80				182				57				43				30			101
ComEd(c)	92				13				38				16				5				5			15
ComEd(c)	92				13				38				16				5				5			15
PECO(c)	29				7				11				2				1				1			7
PECO(c)	29				7				11				2				1				1			7
BGE(c)	302				2				93				105				102				—			—
BGE(c)	302				2				93				105				102				—			—

________________
(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 5 — Regulatory Matters for additional information.


Construction Commitments

Generation’s ongoing investments in renewables development, new natural gas and biomass generation 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 estimated remaining commitment under the contract is $6 million and achievement of commercial operations is expected in the fourth quarter of 2014.

On July 26, 2013, Generation executed an engineering procurement and construction contract to expand its Perryman, Maryland generation site with 120 MW of new natural gas-fired generation. The estimated remaining commitment under the contract is $75 million and achievement of commercial operations is expected in 2015. This project will satisfy a portion of Exelon's commitment to Maryland. See Constellation Merger Commitment below for further information.

On December 27, 2013, Generation executed a Turbine Supply Agreement for construction of the 40 MW Fourmile Wind project in western Maryland. The estimated remaining commitment under the contract is $7 million and achievement of commercial operations is expected in the fourth quarter 2014. This project will satisfy a portion of Exelon’s 125 MW Tier I land-based renewables commitment made to Maryland. See Constellation Merger Commitment below for further information.

During the third quarter of 2014, Generation executed equipment procurement contracts associated with the construction of new combined-cycle gas turbine units in Texas. The estimated commitment under these contracts is $334 million and achievement of commercial operations is expected in 2017.

Refer to Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K for information on investment programs associated with regulatory mandates, such as ComEd’s Infrastructure Investment Plan under EIMA, PECO’s Smart Meter Procurement and Installation Plan and BGE’s comprehensive smart grid initiative.


Constellation Merger Commitments

In February 2012, the MDPSC issued an Order approving the Exelon and Constellation merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland, resulting in an estimated direct investment in the State of Maryland of approximately $1 billion.

The direct investment estimate includes $95 million to $120 million relating to the construction of a headquarters building in Baltimore for Generation’s competitive energy businesses. On March 20, 2013, Generation signed a 20 year lease agreement that was contingent upon the developer obtaining all required approvals, permits and financing for the construction of a building in Baltimore, Maryland. The operating lease became effective during the second quarter of 2014 when these outstanding contingencies were met by the developer. Generation's total commitments under the lease agreement are $0 related to 2014 and 2015, and $10 million, $12 million, $13 million, and $290 million related to 2016, 2017, 2018, and 2019 and thereafter.

The direct investment commitment also includes $600 million to $650 million relating to Exelon and Generation’s development or assistance in the development of 285 — 300 MWs of new generation in Maryland, which is expected to be completed over a period of 10 years. The MDPSC Order contemplates various options for complying with the new generation development commitments, including building or acquiring generating assets, making subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated damages payments. Exelon and Generation expect that the majority of these commitments will be satisfied by building or acquiring generating assets and, therefore, will be primarily capital in nature and recognized as incurred. However, during the third quarter of 2014 the conditions associated with one of the generation development commitments have 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 have recorded a pre-tax $44 million loss contingency related to this generation development commitment which is included in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. While this $44 million loss contingency represents Generation's best estimate of the future obligation, it is reasonably possible that Exelon and Generation could ultimately be required to make cumulative subsidy payments of up to a maximum of approximately $105 million over a 20-year period dependent on actual generating output from a successfully constructed generating plant. See Note 4 - Mergers and Acquisitions of the Exelon 2013 Form 10-K for additional information regarding the Constellation merger commitments.

Equity Investment Commitments


As part of Generation's recent investments in technology development, Generation has entered into equity purchase agreements 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 September 30, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



		Total
	2014	$	27
	2014	$	27
	2015	86
	2015	86
	2016	34
	2016	34
	2017	20
	2017	20
	2018	15
	2018	15
	Total	$	182
	Total	$	182

Contingencies

Commercial Commitments

The Registrants’ commercial commitments as of September 30, 2014, representing commitments potentially triggered by future events were as follows:



	Exelon				Generation				ComEd				PECO				BGE
Letters of credit (non-debt)(a)	$	1,021			$	973			$	20			$	22			$	1
Letters of credit (non-debt)(a)	$	1,021			$	973			$	20			$	22			$	1
Guarantees	4,902			(b)	1,604			(c)	206			(d)	181			(e)	259			(f)
Guarantees	4,902			(b)	1,604			(c)	206			(d)	181			(e)	259			(f)
Nuclear insurance premiums(g)	3,559				3,559				—				—				—
Nuclear insurance premiums(g)	3,559				3,559				—				—				—
Underwriters discount(h)	60				—				—				—				—
Underwriters discount(h)	60				—				—				—				—
Total commercial commitments	$	9,542			$	6,136			$	226			$	203			$	260
Total commercial commitments	$	9,542			$	6,136			$	226			$	203			$	260
___________________

(a)	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

(b)	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $467 million at September 30, 2014, which represents the total amount Exelon could be required to fund based on September 30, 2014 market prices.

(c)	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $205 million at September 30, 2014, which represents the total amount Generation could be required to fund based on September 30, 2014 market prices.

(d)	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.

(e)	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

(f)	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

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

(h)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 16 — Common Stock of the Combined Notes to Consolidated Financial Statements for further details of the equity securities offering.

Nuclear Insurance (Exelon and Generation)

Generation is subject to liability, property damage and other risks associated with major incidents at any of its nuclear stations, including the CENG nuclear stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and also to limit the liability of nuclear reactor owners for such claims from any single incident. As of September 30, 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 September 30, 2014, 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.

Generation is also 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. Premiums paid to NEIL by its members are subject to assessment for adverse loss experience (the retrospective premium obligation). The maximum combined retrospective premium amount that Generation could be required to pay due to participation in the Price-Anderson Act retrospective rating plan for power reactors and the NEIL retrospective premium obligation is $3.6 billion, including CENG's obligation, which is included above in the Commercial Commitments table. See the Nuclear Insurance section within Note 22 — Commitments and Contingencies of the Exelon 2013 Form 10-K for additional details on Generation’s nuclear insurance premiums.

As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information on Generation’s operations relating to CENG.

Spent Nuclear Fuel Obligation (Exelon and Generation)

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 pays the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. 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 will be delayed significantly. 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 January 3, 2014, the DOE filed a petition for rehearing which was denied by the D.C. Circuit Court on March 18, 2014. Also, on January 3, 2014, the DOE submitted a proposal to Congress to reduce the current SNF disposal fee to zero. On May 9, 2014, the DOE notified Generation that the SNF disposal fee will remain in effect through May 15, 2014, after which time the fee will be set to zero. For the nine months ended September 30, 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.

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.

Repurchase of Land Related to Master Agreement Closing (Exelon and Generation)

As a result of the closing of the transactions contemplated by the Master Agreement, EDF has the option to sell back to CENG the land adjacent to the Calvert Cliffs site, together with the rights associated with the land, at its fair market value. The option is exercisable for a period of five years, from April 1, 2014.

Environmental Issues

General. The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future.

ComEd, PECO and BGE have identified sites where former MGP activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.


•	ComEd has identified 42 sites, 17 of which the remediation has been completed and approved by the Illinois EPA or the U.S. EPA and 25 that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2019.


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


•	BGE has identified 13 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The required costs at these two sites are not considered material. 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 5 — Regulatory Matters for additional information regarding the associated regulatory assets.





As of September 30, 2014 and December 31, 2013, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:



30-Sep-14	Total Environmental				Portion of Total Related to
	Investigation and				MGP Investigation and
	Remediation Reserve				Remediation
Exelon	$	342			$	280
Exelon	$	342			$	280
Generation	55				—
Generation	55				—
ComEd	241				237
ComEd	241				237
PECO	45				43
PECO	45				43
BGE	1				—
BGE	1				—



December 31, 2013	Total Environmental				Portion of Total Related to
	Investigation and				MGP Investigation and
	Remediation Reserve				Remediation
Exelon	$	338			$	273
Exelon	$	338			$	273
Generation	56				—
Generation	56				—
ComEd	234				229
ComEd	234				229
PECO	47				44
PECO	47				44
BGE	1				—
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

Section 316(b) of the Clean Water Act. Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts, and is implemented through state-level NPDES permit programs. All of Generation’s and CENG’s power generation facilities with cooling water systems are subject to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by changes to the existing regulations. For Generation, those facilities are Clinton, Dresden, Eddystone, Fairless Hills, Gould Street, Handley, Mountain Creek, Mystic 7, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill. For CENG, those facilities are Calvert Cliffs, Nine Mile Point Unit 1 and R.E. Ginna.

On October 14, 2014, the U.S. EPA's final Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the best technology available, followed by an implementation period. The timing of the various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance schedule, as this is left to the discretion of the state permitting director.

The rule does not require closed-cycle cooling (e.g., cooling towers) as the best technology available to address impingement and entrainment of aquatic life at a facility’s cooling water intake structure. The rule provides the state permitting director with significant discretion to determine the best technology available to limit entrainment (drawing aquatic life into the plants cooling system) mortality, including application of a cost-benefit test and the consideration of a number of site-specific factors. After consideration of these factors, the state permitting agency may require closed cycle cooling, an alternate technology, or determine that the current technology is the best available. The rule also provides a number of flexible compliance options to reduce impingement (trapping aquatic life on screens) mortality, which likely will be accomplished by the installation of screens or other technology at the intake. A number of concerns raised by the electric generation industry about the proposed rule were resolved favorably in the final rule.

New York Facilities. In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific determination where the entrainment performance goal cannot be achieved. Each of CENG’s New York facilities has filed for its SPDES permit renewal in 2014 and the renewal applications are not yet effective.

Salem and Other Power Generation Facilities. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, allowing for the continued operation of Salem with its existing cooling water system. NJDEP advised PSEG, in July 2004, that it strongly recommended reducing cooling water intake flow commensurate with closed-cycle cooling as a compliance option for Salem. PSEG submitted an application for a renewal of the permit on February 1, 2006. In the permit renewal application, PSEG analyzed closed-cycle cooling and other options and demonstrated that the continuation of the Estuary Enhancement Program, an extensive environmental restoration program at Salem, is the best technology to meet the Section 316(b) requirements. PSEG continues to operate Salem under the approved June 2001 NPDES permit while the NPDES permit renewal application is being reviewed. If the final permit or Section 316(b) regulations ultimately requires the retrofitting of Salem’s cooling water intake structure to reduce cooling water intake flow commensurate with closed-cycle cooling, Exelon’s and Generation’s share of the total cost of the retrofit and any resulting interim replacement power would likely be in excess of $430 million, based on a 2006 estimate, and would result in increased depreciation expense related to the retrofit investment. However, it is unknown at this time whether implementation of the final EPA rule will result in a requirement to install closed cycle cooling at Salem.

Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate the effect that compliance with the rule will have on the operation of its and CENG’s generating facilities and its future results of operations, cash flows and financial position. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability would be called into question. However, the likely impact of the rule has been significantly decreased since the final rule does not mandate cooling towers as a national standard, and the state permitting director is required to apply a cost-benefit test and can take into consideration site-specific factors.

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 September 30, 2014, and December 31, 2013, Generation's remaining groundwater contamination reserve was $14 million and $14 million respectively. In addition, a private party asserted claims relating to groundwater contamination. In February 2014, Generation settled these private party claims for an amount that was not material to the financial condition of Generation.

Air Quality

Cross State Air Pollution Rule (CSAPR). On July 11, 2008, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit Court) vacated the CAIR, which had been promulgated by the U.S. EPA to reduce power plant emissions of SO2 and NOx. The D.C. Circuit Court later remanded the CAIR to the U.S. EPA, without invalidating the entire rulemaking, so that the U.S. EPA could correct CAIR in accordance with the D.C. Circuit Court’s July 11, 2008 opinion. On July 7, 2011, the U.S. EPA published the final rule, known as the CSAPR. The CSAPR requires 28 states in the eastern half of the United States to significantly improve air quality by reducing power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states.

Numerous entities challenged the CSAPR in the D.C. Circuit Court, and some requested a stay of the rule pending the Court’s consideration of the matter on the merits. On December 30, 2011, the Court granted a stay of the CSAPR, and directed the U.S. EPA to continue the administration of CAIR in the interim. On August 21, 2012, a three-judge panel of the D.C. Circuit Court held that the U.S. EPA has exceeded its authority in certain material aspects of the CSAPR and vacated the rule and remanded it to the U.S. EPA for further rulemaking consistent with its decision. The Court also ordered that CAIR remain in effect pending finalization of CSAPR on remand. The Court’s order was appealed to the U.S. Supreme Court, and on April 29, 2014, the U.S. Supreme Court reversed the D.C. Circuit Court decision and upheld CSAPR, and remanded the case to the D.C. Circuit Court to resolve the remaining implementation issues. On June 26, 2014, the U.S. EPA filed a motion with the D.C. Circuit Court seeking to have the stay of the CSAPR lifted, and proposed a three-year tolling of the effective dates under the rule so that the first phase of emission budgets would be implemented on January 1, 2015. The U.S. EPA believes that this would allow sufficient time to complete the remaining aspects of the rulemaking before the implementation of the more stringent second phase of emission budgets that, under the tolling proposal, would begin on January 1, 2017.

The CSAPR restricts entirely the use of pre-2012 allowances. Existing SO2 allowances under the ARP would remain available for use. As of September 30, 2014, Generation had $66 million of emission allowances carried at the lower of weighted average cost or market.

EPA Mercury and Air Toxics Standards (MATS). The MATS rule became final on April 16, 2012. The MATS rule reduces emissions of toxic air pollutants, and finalized the new source performance standards for fossil fuel-fired electric utility steam generating units (EGUs). The MATS rule requires coal-fired EGUs to achieve high removal rates of mercury, acid gases and other metals from air emissions. To achieve these standards, coal units with no pollution control equipment installed (uncontrolled coal units) will have to make capital investments and incur higher operating expenses. It is expected that smaller, older, uncontrolled coal units will retire rather than make these investments. Coal units with existing controls that do not meet the required standards may need to upgrade existing controls or add new controls to comply. In addition, the new standards will require oil units to achieve high removal rates of metals. Owners of oil units not currently meeting the proposed emission standards may choose to convert the units to light oils or natural gas, install control technologies or retire the units. The MATS rule requires generating stations to meet the new standards three years after the rule takes effect, April 16, 2015, with specific guidelines for an additional one or two years in limited cases. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. On April 15, 2014, the D.C Circuit Court issued an opinion upholding MATS in its entirety. On July 14, 2014, three petitions for certiorari were filed with the U.S. Supreme Court seeking review of the D.C. Circuit Court decision upholding MATS.

Exelon, along with the other co-owners of Conemaugh Generating Station, have improved the existing scrubbers and installed Selective Catalytic Reduction (SCR) controls at that station to meet the requirements of MATS.

In addition, as of September 30, 2014, Exelon had a $357 million net investment in coal-fired plants in Georgia subject to long-term leases extending through 2028 and 2030. While Exelon currently estimates the value of these plants at the end of the lease term will be in excess of the recorded residual lease values, after the impairments recorded in the second quarter of 2013 and 2014, final applications of the CSAPR and MATS regulations could negatively impact the end-of-lease term values of these assets, which could result in a future impairment loss that could be material. See Note 7 — Impairment of Long-Lived Assets for additional information.

National Ambient Air Quality Standards (NAAQS). The U.S. EPA previously announced that it would complete a review of all NAAQS by 2014. Oral argument in the litigation (State of Miss. v. EPA) of the final 2008 ozone standard occurred in the D.C. Circuit Court in November 2012 and a final Court decision was issued on July 23, 2013 with the 2008 primary ozone standard upheld, but the secondary standard remanded to EPA for reconsideration. On October 6, 2014, the Supreme Court declined to hear an industry petition for certiorari related to the EPA’s 2008 primary ozone standard. Concurrent with litigation of the 2008 ozone standard, the U.S. EPA continued its regular, periodic review of the ozone NAAQS and is expected to propose revisions by December 1, 2014, with preliminary indications that the U.S. EPA will likely propose a tightened standard based on the June 2014 recommendations of the EPA’s Clean Air Act Scientific Advisory Committee (CASAC) to the Administrator and the August 2014 Agency staff Policy Assessment for the Review of the Ozone National Ambient Air Quality Standards. In December 2012, the U.S. EPA issued its final revisions to the Agency’s particulate matter (PM) NAAQS. In its final rule, the U.S. EPA lowered the annual PM2.5 standard, but declined to issue a new secondary NAAQS to improve urban visibility. The U.S. EPA indicated in its final rule that by 2020 it expects most areas of the country will be in attainment of the new PM2.5 NAAQS based on currently expected regulations, such as the MATS regulation. On March 15, 2013, a number of industry coalitions filed a joint lawsuit challenging the new PM2.5 standard; on May 9, 2014 the D.C. Circuit Court denied these petitions for review.

In addition to these NAAQS, the U.S. EPA also finalized nonattainment designations for certain areas in the United States for the 2010 one-hour SO2 standard on August 5, 2013, and indicated that additional nonattainment areas will be designated in a future rulemaking. U.S. EPA will require states to submit state implementation plans (SIPs) for nonattainment areas by March 25, 2015. With regard to Texas and Maryland, no nonattainment areas were identified in EPA’s final designation rule. With regard to Illinois and Pennsylvania, several counties, or portions of counties, in each state were identified as nonattainment. Since the 2010 one-hour SO2 standard was finalized, EPA has issued a series of guidance documents, and proposed a Data Requirement Rule that will be finalized in the summer of 2015 related to requirements for states related to the application of air quality monitoring and modeling in state implementation plans. Nonattainment county compliance with the one-hour SO2 standard is required by March 25, 2018. While significant SO2 reductions will occur as a result of MATS compliance in 2015, Exelon is unable to predict the requirements of pending states’ SIPs to further reduce SO2 emissions in support of attainment of the one hour SO2 standard.

Notices and Finding of Violations and Midwest Generation Bankruptcy. In December 1999, ComEd sold several generating stations to Midwest Generation, LLC (Midwest Generation), a subsidiary of Edison Mission Energy (EME). Under the terms of the sale agreement, Midwest Generation and EME assumed responsibility for environmental liabilities associated with the ownership, occupancy, use and operation of the stations, including responsibility for compliance by the stations with environmental laws before their purchase by Midwest Generation. Midwest Generation and EME additionally agreed to indemnify and hold ComEd and its affiliates harmless from claims, fines, penalties, liabilities and expenses arising from third party claims against ComEd resulting from or arising out of the environmental liabilities assumed by Midwest Generation and EME under the terms of the agreement governing the sale. In connection with Exelon’s 2001 corporate restructuring, Generation assumed ComEd’s rights and obligations with respect to its former generation business, including its rights and obligations under the sale agreement with Midwest Generation and EME.

Under a supplemental agreement reached in 2003, Midwest Generation agreed to reimburse ComEd and Generation for 50% of the specific asbestos claims pending as of February 2003 and related expenses less recovery of insurance costs and agreed to a sharing arrangement for liabilities and expenses associated with future asbestos-related claims as specified in the agreement.

On December 17, 2012 (Petition Date), EME and certain of its subsidiaries, including Midwest Generation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code.

In 2012, the Bankruptcy Court approved the rejection of an agency agreement related to a coal rail car lease under which Midwest Generation had agreed to reimburse ComEd for all obligations incurred under the coal rail car lease. The rejection left Generation as the party responsible for making all remaining payments under the lease and performing all other obligations thereunder. 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 for the coal rail car lease, ComEd utility payments and certain legal costs. 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. As of September 30, 2014, Exelon has not recorded a receivable for the filed proofs of claim because recovery of any amount cannot be assured at this point in the bankruptcy. Exelon will not record claim recoveries unless and until they are realized.

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 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 allow a reasonable assessment of 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 September 30, 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 a January 2014 bankruptcy reorganization 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. The current estimated cost of the anticipated landfill cover remediation for the site is approximately $42 million, which will be allocated among all PRPs. Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability. By letter dated January 11, 2010, the 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 2014 and into 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 2015 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.

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.

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.

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 PRP’s 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 $6 million, which has been fully reserved as of September 30, 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.

Climate Change Regulation. Exelon is subject to climate change regulation or legislation at the Federal, regional and state levels. In 2007, the U.S. Supreme Court ruled that GHG emissions are pollutants subject to regulation under the new motor vehicle provisions of the Clean Air Act. Consequently, on December 7, 2009, the U.S. EPA issued an endangerment finding under Section 202 of the Clean Air Act regarding GHGs from new motor vehicles and on April 1, 2010 issued final regulations limiting GHG emissions from cars and light trucks effective on January 2, 2011. While such regulations do not specifically address stationary sources, such as a generating plant, it is the U.S. EPA’s position that the regulation of GHGs under the mobile source provisions of the Clean Air Act has triggered the permitting requirements under the Prevention of Significant Deterioration (PSD) and Title V operating permit sections of the Clean Air Act for new and modified stationary sources effective January 2, 2011. Therefore, on May 13, 2010, the U.S. EPA issued final regulations (the Tailoring Rule) relating to these provisions of the Clean Air Act for major stationary sources of GHG emissions that apply to new sources that emit greater than 100,000 tons per year, on a CO2 equivalent basis, and to modifications to existing sources that result in emissions increases greater than 75,000 tons per year on a CO2 equivalent basis. These thresholds became effective January 2, 2011, apply for six years and will be reviewed by the U.S. EPA for future applicability thereafter. On July 2, 2012 the U.S. EPA declined to lower GHG permit thresholds in its final “Step 3” Tailoring Rule update. The U.S. EPA will review permit thresholds again in a 2015 rulemaking process. On June 26, 2012, the United States Court of Appeals for the District of Columbia, in a per curium decision, dismissed industry and state petitions challenging the U.S. EPA’s “Tailpipe Rule” for cars and light duty trucks, the endangerment finding for GHG’s from stationary sources, and the Tailoring Rule. On October 15, 2013, the U.S. Supreme Court granted industry petitions to review one aspect of the PSD permitting regulations. Under the PSD regulations, new and modified major stationary sources could be required to install best available control technology, to be determined on a case by case basis. On June 23, 2014, the U.S. Supreme Court issued an opinion that rejected the U.S. EPA’s expansive interpretation of sources that must be subject to GHG regulation. However, the opinion did uphold the U.S. EPA’s determination that it could regulate GHG emissions from those sources that are already subject to the PSD rules. As such, large fossil fuel power plants will be subject to regulation of GHGs under the PSD permitting program, with the specific emission limits applied on a case-by-case basis. Therefore, Generation could be significantly affected by the regulations if it were to build new plants or modify existing plants.

On June 25, 2013, President Obama announced “The President’s Climate Action Plan,” a summary of executive branch actions intended to: reduce carbon emissions; prepare the United States for the impacts of climate change; and lead international efforts to combat global climate change and prepare for its impacts. Concurrent with the announcement of the Administration’s plan, the President also issued a Memorandum for the Administrator of the Environmental Protection Agency that focused on power generation sector carbon reductions under the Section 111 New Source Performance Standards (NSPS) section of the federal Clean Air Act. The memorandum directs the U.S. EPA Administrator to issue two sets of proposed rulemakings with regard to power plant carbon emissions under Section 111 of the Clean Air Act.

The first rulemaking, under Section 111(b) of the Clean Air Act, focuses on establishing carbon regulations for new fossil-fuel power plants. This rulemaking was proposed on September 20, 2013 and is to be finalized “in a timely fashion.” In the proposed rule, U.S. EPA sets separate standards for fossil-fuel fired utility boilers and natural gas fired stationary combustion turbines.

The second rulemaking, under Section 111(d) of the Clean Air Act, focuses on modified, reconstructed and existing fossil power plants. The proposed rule was published in the Federal Register on June 18, 2014 and is open for public comment until December 1, 2014. The Climate Action Plan calls for the rule to be finalized no later than June 1, 2015, and requires that states submit to U.S. EPA their implementation plans no later than June 30, 2016. The proposed rule establishes emission reduction targets for each state and provides flexibility for each state to determine how to achieve its required reductions, including heat rate improvements at coal-fired power plants, fuel switching from coal to gas, renewable generation and new nuclear facilities, demand side energy efficiency, and the use of market-based instruments.

To the extent that the final Section 111(d) rule results in emission reductions from fossil fuel fired plants, and thereby imposes some form of direct or indirect price of carbon in competitive electricity markets, Exelon’s overall low carbon generation portfolio results could benefit.

Litigation and Regulatory Matters

Except to the extent noted below, the circumstances set forth in Note 22 of the Exelon 2013 Form 10-K describe, in all material respects, the current status of litigation matters. The following is an update to that discussion.

Asbestos Personal Injury Claims (Exelon, Generation, PECO and BGE)

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

At September 30, 2014 and December 31, 2013, Generation had reserved approximately $103 million and $90 million, respectively, in total for asbestos-related bodily injury claims. As of September 30, 2014, approximately $22 million of this amount related to 265 open claims presented to Generation, while the remaining $81 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 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 September 30, 2014. Increased claims activity resulting from this ruling could have a material adverse effect on Exelon’s, Generation’s and PECO’s future results of operations and cash flows.

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

Approximately 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.

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 September 30, 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.

Baltimore City Franchise Taxes (BGE)

The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the proper franchise rights from the City. BGE has reviewed the City's claim and believes that it lacks merit. BGE has not recorded an accrual for payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future periods may be material to BGE’s results of operations and cash flows.

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

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

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

See Note 11 — Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999 sale of fossil generating assets.

Supplemental_Financial_Informa

Supplemental Financial Information (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 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 three and nine months ended September 30, 2014 and 2013:


	Three Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust funds(a)
	Regulatory agreement units	$	55			$	55			$	—			$	—			$	—

	Non-regulatory agreement units	39				39				—				—				—

	Net unrealized losses on decommissioning trust funds
	Regulatory agreement units	(107		)		(107		)		—				—				—

	Non-regulatory agreement units	(41		)		(41		)		—				—				—

	Net unrealized gains on pledged assets
	Zion Station decommissioning	7				7				—				—				—

	Regulatory offset to decommissioning trust fund-related	29				29				—				—				—
	activities(b)
	Total decommissioning-related activities	(18		)		(18		)		—				—				—

	Investment income	—				—				—				—				1			(c)

	Long-term lease income	4				—				—				—				—

	Interest income related to uncertain income tax positions	25				27				—				—				—

	AFUDC — Equity	5				—				—				2				3

	Gain on sale of assets	338				338				—				—				—

	Other	—				(5		)		4				—				—

	Other, net	$	354			$	342			$	4			$	2			$	4




	Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust funds(a)
	Regulatory agreement units	$	167			$	167			$	—			$	—			$	—

	Non-regulatory agreement units	102				102				—				—				—

	Net unrealized gains on decommissioning trust funds
	Regulatory agreement units	126				126				—				—				—

	Non-regulatory agreement units	100				100				—				—				—

	Net unrealized gains on pledged assets
	Zion Station decommissioning	27				27				—				—				—

	Regulatory offset to decommissioning trust fund-related	(270		)		(270		)		—				—				—
	activities(b)
	Total decommissioning-related activities	252				252				—				—				—

	Investment income (expense)	1				1				—				(1		)		5			(c)

Long-term lease income	20				—				—				—				—

Interest income related to uncertain income tax positions	41				53				—				—				—

AFUDC — Equity	17				—				3				5				9

Gain on sale of assets	356				355				1				—				—

Other	15				—				10				1				—

Other, net	$	702			$	661			$	14			$	5			$	14




Three Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds(a)
Regulatory agreement units	$	138			$	138			$	—			$	—			$	—

Non-regulatory agreement units	35				35				—				—				—

Net unrealized gains on decommissioning trust funds
Regulatory agreement units	103				103				—				—				—

Non-regulatory agreement units	46				46				—				—				—

Net unrealized losses on pledged assets
Zion Station decommissioning	(9		)		(9		)		—				—				—

Regulatory offset to decommissioning trust fund-related	(189		)		(189		)		—				—				—
activities(b)
Total decommissioning-related activities	124				124				—				—				—

Investment income	1				—				—				—				2			(c)

Long-term lease income	7				—				—				—				—

AFUDC — Equity	4				—				2				1				1

Gain on sale of assets	10				8				2				—				—

Other	9				2				3				—				1

Other, net	$	155			$	134			$	7			$	1			$	4




Nine Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds(a)
Regulatory agreement units	$	221			$	221			$	—			$	—			$	—

Non-regulatory agreement units	65				65				—				—				—

Net unrealized gains on decommissioning trust funds
Regulatory agreement units	196				196				—				—				—

Non-regulatory agreement units	70				70				—				—				—

Net unrealized losses on pledged assets
Zion Station decommissioning	(5		)		(5		)		—				—				—

Regulatory offset to decommissioning trust fund-related	(338		)		(338		)		—				—				—
activities(b)
Total decommissioning-related activities	209				209				—				—				—

Investment income (expense)	6				(1		)		—				(1		)		7			(c)

Long-term lease income	20				—				—				—				—

Interest income related to uncertain income tax positions	24				3				—				1				—

AFUDC — Equity	16				—				8				3				5

Gain on sale of assets	17				13				2				—				—

Other	19				5				8				1				1

Other, net	$	311			$	229			$	18			$	4			$	13

________

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

(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 5 — 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 nine months ended September 30, 2014 and 2013:



Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,549			$	686			$	438			$	169			$	215

Regulatory assets	150				—				83				7				60

Amortization of intangible assets, net	33				33				—				—				—

Amortization of energy contract assets and liabilities(a)	83				93				—				—				—

Nuclear fuel(b)	790				790				—				—				—

ARO accretion(c)	251				251				—				—				—

Total depreciation, amortization, accretion and depletion	$	2,856			$	1,853			$	521			$	176			$	275




Nine Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
Depreciation, amortization, accretion and depletion
Property, plant and equipment	$	1,420			$	610			$	413			$	164			$	194

Regulatory assets	153				—				88				7				58

Amortization of intangible assets, net	33				33				—				—				—

Amortization of energy contract assets and liabilities(a)	342				398				—				—				—

Nuclear fuel(b)	689				689				—				—				—

ARO accretion(c)	207				207				—				—				—

Total depreciation, amortization, accretion and depletion	$	2,844			$	1,937			$	501			$	171			$	252

_________

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

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

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


Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	437			$	193			$	129			$	28			$	50

Loss from equity method investments	20				20				—				—				—

Provision for uncollectible accounts	96				10				9				39				38

Stock-based compensation costs	111				—				—				—				—

Other decommissioning-related activity(a)	(102		)		(102		)		—				—				—

Energy-related options(b)	92				92				—				—				—

Amortization of regulatory asset related to debt costs	8				—				6				2				—

Amortization of rate stabilization deferral	50				—				—				—				50

Amortization of debt fair value adjustment	(45		)		(17		)		—				—				—

Discrete impacts of EIMA(c)	(32		)		—				(32		)		—				—

Amortization of debt costs	36				9				4				2				2

Merger commitments(d)	44				44				—				—				—

Other	(17		)		2				—				(1		)		(11		)

Total other non-cash operating activities	$	698			$	251			$	116			$	70			$	129

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	53			$	—			$	63			$	(14	)		$	6

Other regulatory assets and liabilities	(63		)		—				(14		)		(14		)		(89		)

Cash deposits(f)	(280		)		(280		)		—				—				—

Other current assets	(78		)		24				(9		)		(48		)	(h)	25

Other noncurrent assets and liabilities	(168		)		(111		)		22				1				(9		)

Total changes in other assets and liabilities	$	(536	)		$	(367	)		$	62			$	(75	)		$	(67	)

Non-cash investing and financing activities:
Fair value of net assets recorded upon CENG consolidation(j)	$	(3,400	)		$	(3,400	)		$	—			$	—			$	—

Issuance of equity units(k)	131				—				—				—				—

Uranium procurement(l)	70				70				—				—				—

Indemnification of like-kind exchange position(m)	—				—				4				—				—

Total non-cash investing and financing activities:	$	(3,199	)		$	(3,330	)		$	4			$	—			$	—




Nine Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs	$	621			$	259			$	231			$	32			$	41

Gain from equity method investments	(7		)		(7		)		—				—				—

Provision for uncollectible accounts	83				16				(6		)		48				25

Stock-based compensation costs	99				—				—				—				—

Other decommissioning-related activity(a)	(110		)		(110		)		—				—				—

Energy-related options(b)	87				87				—				—				—

Amortization of regulatory asset related to debt costs	9				—				7				2				—

Amortization of rate stabilization deferral	49				—				—				—				49

Amortization of debt fair value adjustment	(28		)		(28		)		—				—				—

Discrete impacts from EIMA(c)	(206		)		—				(206		)		—				—

Amortization of debt costs	13				7				3				2				1

Merger integration costs(e)	(6		)		—				—				—				(6		)

Increase in inventory reserve	7				7				—				—				—

Other	(27		)		—				(3		)		—				(5		)

Total other non-cash operating activities	$	584			$	231			$	26			$	84			$	105

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(47	)		$	—			$	(63	)		$	(10	)		$	26

Other regulatory assets and liabilities	(50		)		—				(35		)		—				(85		)

Settlement of interest rate swaps (g)	26				—				—				—				—

Other current assets	(169		)		(123		)		47				(31		)	(h)	(35		)

Other noncurrent assets and liabilities	205				(40		)		261			(i)	(6		)		(25		)

Total changes in other assets and liabilities	$	(35	)		$	(163	)		$	210			$	(47	)		$	(119	)

Non-cash investing and financing activities:
Consolidated VIE dividend to noncontrolling interest	$	63			$	63			$	—			$	—			$	—

Indemnification of like-kind exchange position(m)	—				—				175				—				—

Total non-cash investing and financing activities	$	63			$	63			$	175			$	—			$	—

____________

(a)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

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

(d)	Reflects the establishment of a reserve related to a MDPSC merger commitment for generation development. See Note 18 - Commitments and Contingencies for additional information.

(e)	Relates to integration costs to achieve distribution synergies related to the Constellation merger transaction that were reclassified to a regulatory asset. See Note 5 — Regulatory Matters for more information.

(f)	Relates primarily to cash deposits made to ISO's/RTO's.

(g)	Relates to settlement of forward starting interest rate swaps that Exelon entered into in anticipation of Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013. See Note 9 — Derivative Financial Instruments for more information on interest rate swaps.

(h)	Relates primarily to prepaid utility taxes.

(i)	Relates primarily to interest payable related to like-kind exchange tax position. See Note 11 — Income Taxes for discussion of the like-kind exchange tax position.

(j)	See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

(k)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 16 — Common Stock for additional information.

(l)	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.

(m)	See Note 11 — Income Taxes for discussion of the like-kind exchange tax position.
DOE Smart Grid Investment Grant (Exelon, BGE and PECO). For the nine months ended September 30, 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 nine months ended September 30, 2013, Exelon, PECO and BGE have included in the capital expenditures line item under investing activities of the cash flow statement capital expenditures of $68 million, $22 million and $46 million, respectively, and reimbursements of $64 million, $30 million and $34 million, respectively, related to PECO’s and BGE’s DOE SGIG programs. See Note 5 — 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 as of September 30, 2014 and December 31, 2013.



30-Sep-14	Exelon				Generation				ComEd				PECO				BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	14,932		(a)	$	7,868		(a)	$	3,370			$	2,972			$	2,825

Accounts receivable:
Allowance for uncollectible accounts	$	291			$	55			$	80			$	115			$	41



31-Dec-13	Exelon				Generation				ComEd				PECO				BGE
Property, plant and equipment:
Accumulated depreciation and amortization	$	13,713		(b)	$	7,034		(b)	$	3,184			$	2,935			$	2,702

Accounts receivable:
Allowance for uncollectible accounts	$	272			$	57			$	62			$	107			$	46

_______

(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,729 million.

(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.
PECO Installment Plan Receivables (Exelon and PECO)
PECO enters into payment agreements with certain delinquent customers, primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria are provided the option to enter into an installment payment plan, some of which have terms greater than one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent portion. The net receivable balance for installment plans with terms greater than one year was $19 million as of September 30, 2014 and December 31, 2013. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan receivables are consistent with the customer accounts receivable methodology discussed in Note 1 — Significant Accounting Policies of the Exelon 2013 Form 10-K. The allowance for uncollectible accounts balance associated with these receivables at September 30, 2014 of $19 million consists of $1 million, $4 million and $14 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 September 30, 2014 and December 31, 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 of the Exelon 2013 Form 10-K.

Segment_Information_Exelon_Gen

Segment Information (Exelon, Generation, ComEd, PECO and BGE)	9 Months Ended
	Sep. 30, 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 and 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, upstream natural gas, proprietary trading, distributed energy, 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 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 as a result of the merger with Constellation and the consolidation of CENG are also not allocated to a region.
	An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended September 30, 2014 and 2013 is as follows:
	Three Months Ended September 30, 2014 and 2013



		Generation(a)			ComEd			PECO			BGE			Other(b)				Intersegment Eliminations				Exelon
	Total revenues(c):
	2014	$	4,412		$	1,222		$	693		$	697		$	305			$	(417	)		$	6,912

	2013	4,255			1,156			728			737			294				(668		)		6,502

	Intersegment revenues(d):
	2014	$	112		$	1		$	—		$	3		$	302			$	(418	)		$	—

	2013	373			1			1			2			294				(669		)		2

	Net income (loss):
	2014	$	849		$	126		$	81		$	49		$	(31	)		$	—			$	1,074

	2013	485			126			92			53			(20		)		—				736

	Total assets:
	September 30, 2014	$	45,019		$	24,845		$	10,051		$	7,915		$	8,713			$	(11,279	)		$	85,264

	December 31, 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. Intersegment revenues for Generation for the three months ended September 30, 2014 include revenue from sales to PECO of $28 million and sales to BGE of $83 million in the Mid-Atlantic region, and sales to ComEd of $1 million in the Midwest region. For the three months ended September 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $82 million and sales to BGE of $144 million in the Mid-Atlantic region, and sales to ComEd of $143 million in the Midwest region.

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

(c)	For the three months ended September 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.

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

Generation total revenues (three months ended September 30,):



	2014									2013
	Revenues			Intersegment			Total			Revenues			Intersegment				Total
	from external			revenues			Revenues			from external			revenues				Revenues
	customers(a)									customers(a)
Mid-Atlantic	$	1,285		$	4		$	1,289		$	1,381		$	10			$	1,391

Midwest	1,062			(1		)	1,061			1,018			(5		)		1,013

New England	272			—			272			341			(1		)		340

New York	230			2			232			198			(14		)		184

ERCOT	303			(1		)	302			430			(3		)		427

Other Regions(b)	381			(6		)	375			278			(7		)		271

Total Revenues for Reportable Segments	3,533			(2		)	3,531			3,646			(20		)		3,626

Other(c)	879			2			881			609			20				629

Total Generation Consolidated Operating Revenues	$	4,412		$	—		$	4,412		$	4,255		$	—			$	4,255

__________

(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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $22 million decrease to revenues and $125 million decrease to revenues for the three months ended September 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.

Generation total revenues net of purchased power and fuel expense (three months ended September 30,):



	2014									2013
	RNF			Intersegment RNF			Total RNF			RNF			Intersegment RNF				Total RNF
	from external									from external
	customers(a)									customers(a)
Mid-Atlantic	$	921		$	14		$	935		$	857		$	7			$	864

Midwest	722			(6		)	716			606			(5		)		601

New England	120			(30		)	90			52			10				62

New York	176			10			186			29			(38		)		(9		)

ERCOT	186			(77		)	109			222			(78		)		144

Other Regions(b)	157			(89		)	68			116			(75		)		41

Total Revenues net of purchased power and fuel for Reportable Segments	2,282			(178		)	2,104			1,882			(179		)		1,703

Other(c)	250			178			428			194			179				373

Total Generation Revenues net of purchased power and fuel expense	$	2,532		$	—		$	2,532		$	2,076		$	—			$	2,076


__________

(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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $15 million increase to RNF and $44 million decrease to RNF for the three months ended September 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.
Nine Months Ended September 30, 2014 and 2013



	Generation(a)(b)			ComEd			PECO			BGE			Other(c)				Intersegment				Exelon
																	Eliminations
Total revenues(d):
2014	$	12,591		$	3,484		$	2,343		$	2,404		$	924			$	(1,573	)		$	20,173

2013	11,858			3,395			2,295			2,271			909				(2,003		)		18,725

Intersegment revenues(e):
2014	$	630		$	2		$	1		$	21		$	920			$	(1,574	)		$	—

2013	1,083			2			1			10			909				(2,003		)		2

Net income (loss):
2014	$	1,037		$	335		$	255		$	156		$	(58	)		$	—			$	1,725

2013	795			140			292			160			(152		)		—				1,235

__________

(a)	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2014 include revenue from sales to PECO of $165 million and sales to BGE of $290 million in the Mid-Atlantic region, and sales to ComEd of $175 million in the Midwest. For the nine months ended September 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $321 million and sales to BGE of $356 million in the Mid-Atlantic region, and sales to ComEd of $409 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 include activity recorded at CENG from April 1, 2014, the date of integration, through September 30, 2014.

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

(d)	For the nine months ended September 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.

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

Generation total revenues (nine months ended September 30,)


	2014									2013
	Revenues			Intersegment			Total			Revenues			Intersegment				Total
	from external			revenues			Revenues			from external			revenues				Revenues
	customers(a)									customers(a)
Mid-Atlantic(b)	$	3,998		$	(14	)	$	3,984		$	3,932		$	11			$	3,943

Midwest	3,302			11			3,313			3,274			(3		)		3,271

New England	1,028			5			1,033			942			(9		)		933

New York(b)	614			(1		)	613			547			(20		)		527

ERCOT	743			(2		)	741			1,042			(8		)		1,034

Other Regions(c)	1,027			(4		)	1,023			708			29				737

Total Revenues for Reportable Segements	10,712			(5		)	10,707			10,445			—				10,445

Other(d)	1,879			5			1,884			1,413			—				1,413

Total Generation Consolidated Operating Revenues	$	12,591		$	—		$	12,591		$	11,858		$	—			$	11,858

__________

(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

(b)	Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through September 30, 2014.

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

(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $203 million decrease to revenues and $603 million decrease to revenues, for the nine months ended September 30, 2014 and 2013, respectively, and elimination of intersegment revenues.


Generation total revenues net of purchased power and fuel expense (nine months ended September 30,):



	2014									2013
	RNF			Intersegment			Total			RNF			Intersegment				Total
	from external			RNF			RNF			from external			RNF				RNF
	customers(a)									customers(a)
Mid-Atlantic(b)	$	2,610		$	(60	)	$	2,550		$	2,477		$	(2	)		$	2,475

Midwest	1,856			21			1,877			2,002			(1		)		2,001

New England	362			(72		)	290			156			(14		)		142

New York(b)	289			24			313			14			(31		)		(17		)

ERCOT	457			(207		)	250			477			(120		)		357

Other Regions(c)	465			(216		)	249			238			(91		)		147

Total Revenues net of purchased power and fuel expense for Reportable Segments	6,039			(510		)	5,529			5,364			(259		)		5,105

Other(d)	(519		)	510			(9		)	200			259				459

Total Generation Revenues net of purchased power and fuel expense	$	5,520		$	—		$	5,520		$	5,564		$	—			$	5,564

__________

(a)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b)	Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through September 30, 2014.

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

(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $78 million decrease to RNF and $386 million decrease to RNF for the nine months ended September 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.

Subsequent_Events_Exelon_and_G

Subsequent Events (Exelon and Generation)	9 Months Ended
Subsequent Events (Exelon and Generation)	Sep. 30, 2014
Subsequent Events [Abstract]	'
Subsequent Events (Exelon and Generation)	'
	Subsequent Event (Exelon and Generation)

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

Basis_of_Presentation_Basis_of

Basis of Presentation Basis of Presentation (Policies)	9 Months Ended
Basis of Presentation Basis of Presentation (Policies)	Sep. 30, 2014
Organization, Consolidation and Presentation of Financial Statements [Abstract]	'
Fair Value Assets Measured On Recurring Basis Investments Valuation Techniques	'
	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.
Fair Value Assets Measured On Recurring Basis Cash And Cash Equivalents Valuation Techniques	'
	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.
Fair Value Assets Measured On Recurring Basis Nuclear Decommissioning Trust Fund Investments Valuation Techniques	'
	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. 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, 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 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. See Note 12 — Nuclear Decommissioning for further discussion on the NDT fund investments.
	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.
	As of September 30, 2014, Generation has outstanding commitments to invest in middle market lending, corporate debt securities, private equity investments, and real estate investments of approximately $344 million. These commitments will be funded by Generation’s existing nuclear decommissioning trust funds.
Fair Value Assets And Liabilities Measured On Recurring Basis Derivative Financial Instruments Assets And Liabilities Valuation Techniques	'
	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 9 - Derivative Financial Instruments for further discussion on mark-to-market derivatives.
Fair Value Liabilities Measured On Recurring Basis Obligations Valuation Techniques	'
	Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO and BGE). The Registrants’ deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The 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.

New_Accounting_Pronouncements_1

New Accounting Pronouncements (Policies)	9 Months Ended
New Accounting Pronouncements (Policies)	Sep. 30, 2014
New Accounting Pronouncements and Changes in Accounting Principles [Abstract]	'
New Accounting Pronouncements	'
	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.

	The following recently issued accounting standards are 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_Tab

Variable Interest Entities (Tables)	9 Months Ended
	Sep. 30, 2014
Variable Interest Entity [Abstract]	'
Schedule of Variable Interest Entities	'
	The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:


	30-Sep-14	Commercial				Equity				Total
		Agreement				Investment
		VIEs				VIEs
	Total assets(a)	$	115			$	307			$	422

	Total liabilities(a)	2				115				117

	Exelon's ownership interest in VIE(a)	—				62				62

	Other ownership interests in VIE(a)	113				130				243

	Registrants’ maximum exposure to loss:

	Carrying amount of equity method investments	—				66				66

	Contract intangible asset	9				—				9

	Debt and payment guarantees	—				3				3

	Net assets pledged for Zion Station decommissioning(b)	31				—				31



	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 $365 million and $458 million as of September 30, 2014 and December 31, 2013, respectively; offset by payables to ZionSolutions LLC of $334 million and $414 million as of September 30, 2014 and December 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.


			September 30, 2014												December 31, 2013
			Exelon				Generation				BGE				Exelon				Generation					BGE
	Cash and cash equivalents		$	372			$	372			$	—			$	62			$	62			$	—

	Restricted cash			142				95				47				80				52				28

	Accounts receivable, net
		Customer		213				213				—				260				260				—

	Other		53				53				—				—				—				—

Mark-to-market derivatives assets			40				40				—				21				21				—

Inventory

	Materials and supplies		171				171				—				—				—				—

Other current assets			53				47				—				34				23				—

	Total current assets		1,044				991				47				457				418				28


	Property, plant and equipment, net		4,517				4,517				—				1,171				1,171				—

	Nuclear decommissioning trust funds		2,034				2,034				—				—				—				—

	Goodwill		46				46				—				—				—				—

	Other noncurrent assets		132				115				3				127				106				3

	Total noncurrent assets		6,729				6,712				3				1,298				1,277				3

	Total assets	$	7,773			$	7,703			$	50			$	1,755			$	1,695			$	31


Short-term borrowings		$	1			$	1			$	—			$	—			$	—			$	—

Long-term debt due within one year			83				5				72				85				5				70

Accounts payable			264				264				—				170				170				—

Accrued expenses			78				72				7				26				22				4

Mark-to-market derivative liabilities			18				18				—				29				29				—

Other current liabilities			53				53				—				10				10				—

	Total current liabilities		497				413				79				320				236				74


	Long-term debt		256				84				158				298				86				195

	Asset retirement obligations		1,654				1,654				—				—				—				—

	Pension obligation(a)		8				8				—				—				—				—

	Other noncurrent liabilities		179				179				—				40				40				—

	Noncurrent liabilities		2,097				1,925				158				338				126				195

	Total liabilities	$	2,594			$	2,338			$	237			$	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 — 13 - Retirement Benefits for additional details.
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in Exelon’s, Generation’s, and BGE’s consolidated financial statements at September 30, 2014 and December 31, 2013 are as follows:


	30-Sep-14												31-Dec-13
	Exelon(a)(b)				Generation(b)				BGE				Exelon(a)				Generation				BGE
Current assets	$	1,071			$	1,018			$	47			$	484			$	446			$	28

Noncurrent assets	7,384				7,367				3				1,905				1,884				3

Total assets	$	8,455			$	8,385			$	50			$	2,389			$	2,330			$	31


Current liabilities	$	545			$	460			$	79			$	566			$	481			$	74

Noncurrent liabilities	2,671				2,499				158				774				562				195

Total liabilities	$	3,216			$	2,959			$	237			$	1,340			$	1,043			$	269

_______________________

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

(b)	Includes total assets of $6.0 billion and total liabilities of $2.0 billion due to the consolidation of CENG beginning April 1, 2014. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

Mergers_Acquisitions_and_Dispo1

Mergers, Acquisitions and Dispositions (Tables)	9 Months Ended
	Sep. 30, 2014
Business Combinations [Abstract]	'
Major classes of assets and liabilities held for sale	'
	During the third quarter of 2014, Generation also entered into purchase and sale agreements with separate counterparties to divest the following long-lived assets:


	Station	Net Generation Capacity		Location	Operating Segment
	Fore River	726 MW		North Weymouth, MA	New England
	West Valley	185 MW		Salt Lake City, UT	Other
	Quail Run	488 MW		Odessa, TX	ERCOT


	The assets and liabilities of the three power plants are 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 September 30, 2014.


		30-Sep-14
	Assets:
	Property, plant and equipment, net (a)	$	617

	Inventory	31

	Current assets	1

	Total assets held for sale	$	649

	Liabilities:
	Accounts payable	$	1

	Accrued expenses	4

	Other current liabilities	13

	Total liabilities held for sale (b)	$	18


	(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 7 - Impairment of Long-Lived Assets for further information.
	(b) Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Regulatory_Matters_Tables

Regulatory Matters (Tables)	9 Months Ended
	Sep. 30, 2014
Regulated Operations [Abstract]	'
Schedule of Regulatory Assets	'


	30-Sep-14	Exelon								ComEd								PECO							BGE
		Current				Noncurrent				Current				Noncurrent				Current				Noncurrent			Current				Noncurrent
	Regulatory assets
	Pension and other postretirement	$	208			$	2,455			$	—			$	—			$	—			$	—		$	—			$	—
	benefits
	Deferred income taxes	7				1,517				1				67				—				1,377			6				73

	AMI programs	9				254				9				69				—				74			—				111

	Under-recovered distribution service	243				223				243				223				—				—			—				—
	costs
	Debt costs	9				50				7				48				2				2			1				8

	Fair value of BGE long-term debt(a)	6				192				—				—				—				—			—				—

	Fair value of BGE supply contract(b)	3				—				—				—				—				—			—				—

	Severance	4				9				—				—				—				—			4				9

	Asset retirement obligations	1				111				1				73				—				26			—				12

	MGP remediation costs	39				220				32				186				6				33			1				1

	RTO start-up costs	1				—				1				—				—				—			—				—

	Under-recovered uncollectible accounts	—				70				—				70				—				—			—				—

	Renewable energy	14				164				14				164				—				—			—				—

	Energy and transmission programs	22				5				19				—				—				—			3			(f)	5

	Deferred storm costs	3				—				—				—				—				—			3				—

	Electric generation-related	12				21				—				—				—				—			12				21
	regulatory asset
	Rate stabilization deferral	75				101				—				—				—				—			75				101

	Energy efficiency and demand	84				151				—				—				—				—			84				151
	response programs
	Merger integration costs	2				7				—				—				—				—			2				7

	Conservation voltage reduction	1				1				—				—				—				—			1				1

	Under-recovered revenue decoupling(e)	14				—				—				—				—				—			14				—

	Other	17				38				3				28				13				8			—				—

	Total regulatory assets	$	774			$	5,589			$	330			$	928			$	21			$	1,520		$	206			$	500



	30-Sep-14	Exelon								ComEd								PECO							BGE
		Current				Noncurrent				Current				Noncurrent				Current				Noncurrent			Current				Noncurrent
	Regulatory liabilities
	Other postretirement benefits	$	53			$	96			$	—			$	—			$	—			$	—		$	—			$	—

	Nuclear decommissioning	—				2,850				—				2,371				—				479			—				—

	Removal costs	110				1,455				86				1,257				—				—			24				198

	Energy efficiency and demand	28				2				28				—				—				2			—				—
response programs
DLC Program Costs	—				10				—				—				—				10			—				—

Energy efficiency Phase 2	—				32				—				—				—				32			—				—

Electric distribution tax repairs	20				100				—				—				20				100			—				—

Gas distribution tax repairs	8				32				—				—				8				32			—				—

Energy and transmission programs	73				13				26				13				44			(c)	—			3			(f)	—

Over-recovered gas and electric	4				—				—				—				4				—			—				—
universal service fund costs
Revenue subject to refund(d)	47				—				47				—				—				—			—				—

Over-recovered revenue decoupling(e)	16				—				—				—				—				—			16				—

Other	5				3				—				2				3				—			2				1

Total regulatory liabilities	$	364			$	4,593			$	187			$	3,643			$	79			$	655		$	45			$	199



31-Dec-13	Exelon								ComEd								PECO							BGE
	Current				Noncurrent				Current				Noncurrent				Current				Noncurrent			Current				Noncurrent
Regulatory assets
Pension and other postretirement	$	221			$	2,794			$	—			$	—			$	—			$	—		$	—			$	—
benefits
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	178				285				178				285				—				—			—				—
costs
Debt costs	12				56				9				53				3				3			1				8

Fair value of BGE long-term debt(a)	—				219				—				—				—				—			—				—

Fair value of BGE supply contract(b)	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				—				52				—				—				—			1			(f)	—

Deferred storm costs	3				3				—				—				—				—			3				3

Electric generation-related regulatory	13				30				—				—				—				—			13				30
asset
Rate stabilization deferral	71				154				—				—				—				—			71				154

Energy efficiency and demand	73				148				—				—				—				—			73				148
response programs
Merger integration costs	2				9				—				—				—				—			2				9

Other	31				39				18				26				8				7			4				6

Total regulatory assets	$	760			$	5,910			$	329			$	933			$	17			$	1,448		$	181			$	524



31-Dec-13	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	53				—				45				—				8				—			—				—
response programs
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			(c)	—			11			(f)	—

Over-recovered gas and electric	8				—				—				—				8				—			—				—
universal service fund costs
Revenue subject to refund(d)	38				—				38				—				—				—			—				—

Over-recovered revenue decoupling(e)	16				—				—				—				—				—			16				—

Other	4				—				—				—				3				—			—				—

Total regulatory liabilities	$	327			$	4,388			$	170			$	3,512			$	106			$	629		$	48			$	204

________________

(a)	Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt.

(b)	Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.

(c)	Includes $28 million related to the DSP program, $11 million related to the over-recovered natural gas costs under the PGC and $5 million related to over-recovered electric transmission costs as of September 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.

(d)	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC’s order in the 2007 Rate Case. See Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K. for further information.

(e)	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2014, BGE had a regulatory asset of $14 million related to under-recovered electric revenue decoupling and a regulatory liability of $16 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.

(f)	Relates to $3 million associated with the transmission formula rate and $3 million of over-recovered natural gas supply costs as of September 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs.
Schedule of Regulatory Liabilities	'


	30-Sep-14	Exelon								ComEd								PECO							BGE
		Current				Noncurrent				Current				Noncurrent				Current				Noncurrent			Current				Noncurrent
	Regulatory assets
	Pension and other postretirement	$	208			$	2,455			$	—			$	—			$	—			$	—		$	—			$	—
	benefits
	Deferred income taxes	7				1,517				1				67				—				1,377			6				73

	AMI programs	9				254				9				69				—				74			—				111

	Under-recovered distribution service	243				223				243				223				—				—			—				—
	costs
	Debt costs	9				50				7				48				2				2			1				8

	Fair value of BGE long-term debt(a)	6				192				—				—				—				—			—				—

	Fair value of BGE supply contract(b)	3				—				—				—				—				—			—				—

	Severance	4				9				—				—				—				—			4				9

	Asset retirement obligations	1				111				1				73				—				26			—				12

	MGP remediation costs	39				220				32				186				6				33			1				1

	RTO start-up costs	1				—				1				—				—				—			—				—

	Under-recovered uncollectible accounts	—				70				—				70				—				—			—				—

	Renewable energy	14				164				14				164				—				—			—				—

	Energy and transmission programs	22				5				19				—				—				—			3			(f)	5

	Deferred storm costs	3				—				—				—				—				—			3				—

	Electric generation-related	12				21				—				—				—				—			12				21
	regulatory asset
	Rate stabilization deferral	75				101				—				—				—				—			75				101

	Energy efficiency and demand	84				151				—				—				—				—			84				151
	response programs
	Merger integration costs	2				7				—				—				—				—			2				7

	Conservation voltage reduction	1				1				—				—				—				—			1				1

	Under-recovered revenue decoupling(e)	14				—				—				—				—				—			14				—

	Other	17				38				3				28				13				8			—				—

	Total regulatory assets	$	774			$	5,589			$	330			$	928			$	21			$	1,520		$	206			$	500



	30-Sep-14	Exelon								ComEd								PECO							BGE
		Current				Noncurrent				Current				Noncurrent				Current				Noncurrent			Current				Noncurrent
	Regulatory liabilities
	Other postretirement benefits	$	53			$	96			$	—			$	—			$	—			$	—		$	—			$	—

	Nuclear decommissioning	—				2,850				—				2,371				—				479			—				—

	Removal costs	110				1,455				86				1,257				—				—			24				198

	Energy efficiency and demand	28				2				28				—				—				2			—				—
response programs
DLC Program Costs	—				10				—				—				—				10			—				—

Energy efficiency Phase 2	—				32				—				—				—				32			—				—

Electric distribution tax repairs	20				100				—				—				20				100			—				—

Gas distribution tax repairs	8				32				—				—				8				32			—				—

Energy and transmission programs	73				13				26				13				44			(c)	—			3			(f)	—

Over-recovered gas and electric	4				—				—				—				4				—			—				—
universal service fund costs
Revenue subject to refund(d)	47				—				47				—				—				—			—				—

Over-recovered revenue decoupling(e)	16				—				—				—				—				—			16				—

Other	5				3				—				2				3				—			2				1

Total regulatory liabilities	$	364			$	4,593			$	187			$	3,643			$	79			$	655		$	45			$	199



31-Dec-13	Exelon								ComEd								PECO							BGE
	Current				Noncurrent				Current				Noncurrent				Current				Noncurrent			Current				Noncurrent
Regulatory assets
Pension and other postretirement	$	221			$	2,794			$	—			$	—			$	—			$	—		$	—			$	—
benefits
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	178				285				178				285				—				—			—				—
costs
Debt costs	12				56				9				53				3				3			1				8

Fair value of BGE long-term debt(a)	—				219				—				—				—				—			—				—

Fair value of BGE supply contract(b)	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				—				52				—				—				—			1			(f)	—

Deferred storm costs	3				3				—				—				—				—			3				3

Electric generation-related regulatory	13				30				—				—				—				—			13				30
asset
Rate stabilization deferral	71				154				—				—				—				—			71				154

Energy efficiency and demand	73				148				—				—				—				—			73				148
response programs
Merger integration costs	2				9				—				—				—				—			2				9

Other	31				39				18				26				8				7			4				6

Total regulatory assets	$	760			$	5,910			$	329			$	933			$	17			$	1,448		$	181			$	524



31-Dec-13	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	53				—				45				—				8				—			—				—
response programs
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			(c)	—			11			(f)	—

Over-recovered gas and electric	8				—				—				—				8				—			—				—
universal service fund costs
Revenue subject to refund(d)	38				—				38				—				—				—			—				—

Over-recovered revenue decoupling(e)	16				—				—				—				—				—			16				—

Other	4				—				—				—				3				—			—				—

Total regulatory liabilities	$	327			$	4,388			$	170			$	3,512			$	106			$	629		$	48			$	204

________________

(a)	Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt.

(b)	Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGE’s supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.

(c)	Includes $28 million related to the DSP program, $11 million related to the over-recovered natural gas costs under the PGC and $5 million related to over-recovered electric transmission costs as of September 30, 2014. As of December 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.

(d)	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICC’s order in the 2007 Rate Case. See Note 3 — Regulatory Matters of the Exelon 2013 Form 10-K. for further information.

(e)	Represents the electric and gas distribution costs recoverable from customers under BGE’s decoupling mechanism. As of September 30, 2014, BGE had a regulatory asset of $14 million related to under-recovered electric revenue decoupling and a regulatory liability of $16 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.

(f)	Relates to $3 million associated with the transmission formula rate and $3 million of over-recovered natural gas supply costs as of September 30, 2014. As of December 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs.
Purchase Of Receivables	'


	As of September 30, 2014	Exelon				ComEd				PECO				BGE
	Purchased receivables(a)	$	306			$	152			$	78			$	76

	Allowance for uncollectible accounts(b)	(36		)		(21		)		(8		)		(7		)
	Purchased receivables, net	$	270			$	131			$	70			$	69



	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.

Investment_in_Constellation_En1

Investment in Constellation Energy Nuclear Group, LLC (Tables) (Exelon Generation Co L L C [Member])	9 Months Ended
	Sep. 30, 2014
Exelon Generation Co L L C [Member]	'
Schedule of Equity Method Investments [Line Items]	'
Schedule of total equity in earnings of investment in CENG	'
	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:



	Preliminary Fair Values	Exelon and Generation
	Current assets	$	499

	Nuclear decommissioning trust fund	1,955

	Property, plant and equipment	2,941

	Nuclear fuel	482

	Other assets	10

	Total assets	5,887


	Current liabilities	237

	Asset retirement obligation	1,684

	Pension and other employee benefit obligations	281

	Unamortized energy contract liabilities	171

	Other liabilities	114

	Total liabilities	2,487

	Total net assets	$	3,400

Impairment_of_Longlived_Assets1

Impairment of Long-lived Assets (Tables)	9 Months Ended
	Sep. 30, 2014
Property, Plant and Equipment [Abstract]	'
Schedule of Capital Leased Assets	'
	At September 30, 2014 and December 31, 2013, the components of the net investment in long-term leases were as follows:



		September 30, 2014		December 31, 2013
	Estimated residual value of leased assets	$	685	$	1,465

	Less: unearned income		328		767

	Net investment in long-term leases	$	357	$	698

Fair_Value_of_Financial_Assets1

Fair Value of Financial Assets and Liabilities (Tables)	9 Months Ended
Fair Value of Financial Assets and Liabilities (Tables)	Sep. 30, 2014
Fair Value Tables [Line Items]	'
Fair value of financial liabilities recorded at the carrying amount	'
	The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of September 30, 2014 and December 31, 2013:
	Exelon


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	565			$	3			$	562			$	—			$	565
	Short-term liabilities	$	565			$	3			$	562			$	—			$	565
	Long-term debt (including amounts due within one year)	21,264				1,168				20,278				1,297				22,743
	Long-term debt (including amounts due within one year)	21,264				1,168				20,278				1,297				22,743
	Long-term debt to financing trusts	648				—				—				677				677
	Long-term debt to financing trusts	648				—				—				677				677
	SNF obligation	1,021				—				849				—				849
	SNF obligation	1,021				—				849				—				849



		31-Dec-13
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	344			$	3			$	341			$	—			$	344
	Short-term liabilities	$	344			$	3			$	341			$	—			$	344
	Long-term debt (including amounts due within one year)	19,132				—				18,672				1,079				19,751
	Long-term debt (including amounts due within one year)	19,132				—				18,672				1,079				19,751
	Long-term debt to financing trusts	648				—				—				631				631
	Long-term debt to financing trusts	648				—				—				631				631
	SNF obligation	1,021				—				790				—				790
	SNF obligation	1,021				—				790				—				790
Assets and liabilities measured and recorded at fair value on recurring basis	'
	The following tables present assets and liabilities measured and recorded at fair value on Exelon's and Generation’s Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2014 and December 31, 2013:



			Generation																Exelon
	As of September 30, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
	Assets
	Cash equivalents(a)		$	944			$	—			$	—			$	944			$	1,876				$	—				$	—				$	1,876
	Cash equivalents(a)		$	944			$	—			$	—			$	944			$	1,876				$	—				$	—				$	1,876
	Nuclear decommissioning trust fund investments
	Cash equivalents		261				62				—				323				261					62					—					323
	Cash equivalents		261				62				—				323				261					62					—					323
	Equity
	Individually held		2,569				—				—				2,569				2,569					—					—					2,569
	Individually held		2,569				—				—				2,569				2,569					—					—					2,569
	Exchange traded funds		170				—				—				170				170					—					—					170
	Exchange traded funds		170				—				—				170				170					—					—					170
	Commingled funds		—				2,365				—				2,365				—					2,365					—					2,365
	Commingled funds		—				2,365				—				2,365				—					2,365					—					2,365
	Equity funds subtotal		2,739				2,365				—				5,104				2,739					2,365					—					5,104
	Equity funds subtotal		2,739				2,365				—				5,104				2,739					2,365					—					5,104
	Balanced funds - commingled funds		—				273				—				273				—					273					—					273
	Balanced funds - commingled funds		—				273				—				273				—					273					—					273
	Fixed income
	Debt securities issued by the U.S.		967				—				—				967				967					—					—					967
	Treasury and other U.S. government
	corporations and agencies
	Debt securities issued by states of the		—				429				—				429				—					429					—					429
	United States and political
	subdivisions of the states
	Debt securities issued by foreign		—				105				—				105				—					105					—					105
	governments		—				105				—				105				—					105					—					105
	Corporate debt securities		—				2,001				235				2,236				—					2,001					235					2,236
	Corporate debt securities		—				2,001				235				2,236				—					2,001					235					2,236
	Federal agency mortgage-backed		—				79				—				79				—					79					—					79
	securities		—				79				—				79				—					79					—					79
	Commercial mortgage-backed		—				39				—				39				—					39					—					39
	securities (non-agency)		—				39				—				39				—					39					—					39
	Residential mortgage-backed securities		—				3				—				3				—					3					—					3
	(non-agency)		—				3				—				3				—					3					—					3
	Mutual funds		—				21				—				21				—					21					—					21
	Mutual funds		—				21				—				21				—					21					—					21
	Commingled funds		—				328				—				328				—					328			—		—					328
	Commingled funds		—				328				—				328				—					328			—		—					328
	Fixed income subtotal		967				3,005				235				4,207				967					3,005					235					4,207
	Fixed income subtotal		967				3,005				235				4,207				967					3,005					235					4,207
	Middle market lending		—				—				354				354				—					—					354					354
	Middle market lending		—				—				354				354				—					—					354					354
	Private Equity		—				—				54				54				—					—					54					54
	Private Equity		—				—				54				54				—					—					54					54
	Other debt obligations		—				19				—				19				—					19					—					19
	Other debt obligations		—				19				—				19				—					19					—					19
	Real Estate		—				—				1				1				—			—		—			—		1					1
	Real Estate		—				—				1				1				—			—		—			—		1					1
	Nuclear decommissioning trust fund investments subtotal(b)		3,967				5,724				644				10,335				3,967					5,724					644					10,335
	Nuclear decommissioning trust fund investments subtotal(b)		3,967				5,724				644				10,335				3,967					5,724					644					10,335


			Generation																Exelon
	As of September 30, 2014		Level 1				Level 2				Level 3				Total				Level 1					Level 2					Level 3					Total
	Pledged assets for Zion Station decommissioning
	Pledged assets for Zion Station decommissioning
	Cash equivalents		—				12				—				12				—					12					—					12
	Cash equivalents		—				12				—				12				—					12					—					12
Equity
Equity
Individually held		5				2				—				7				5					2					—					7
Individually held		5				2				—				7				5					2					—					7
Equity funds subtotal		5				2				—				7				5					2					—					7
Equity funds subtotal		5				2				—				7				5					2					—					7
Fixed income
Fixed income
Debt securities issued by the U.S.		13				2				—				15				13					2					—					15
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				19				—				19				—					19					—					19
United States and political
subdivisions of the states
Corporate debt securities		—				138				—				138				—					138					—					138
Corporate debt securities		—				138				—				138				—					138					—					138
Commingled funds		—				4				—				4				—			—		4			—		—			—		4
Commingled funds		—				4				—				4				—			—		4			—		—			—		4
Fixed income subtotal		13				163				—				176				13					163					—					176
Fixed income subtotal		13				163				—				176				13					163					—					176
Middle market lending		—				—				166				166				—					—					166					166
Middle market lending		—				—				166				166				—					—					166					166
Pledged assets for Zion Station		18				177				166				361				18					177					166					361
decommissioning subtotal(c)		18				177				166				361				18					177					166					361
Rabbi trust investments(e)
Mutual funds(d)		15				—				—				15				46					—					—					46
Mutual funds(d)		15				—				—				15				46					—					—					46
Rabbi trust investments subtotal		15				—				—				15				46					—					—					46
Rabbi trust investments subtotal		15				—				—				15				46					—					—					46
Commodity derivative assets
Economic hedges		396				2,523				1,683				4,602				396					2,523					1,683					4,602
Economic hedges		396				2,523				1,683				4,602				396					2,523					1,683					4,602
Proprietary trading		129				537				214				880				129					537					214					880
Proprietary trading		129				537				214				880				129					537					214					880
Effect of netting and allocation of collateral(f)		(563		)		(2,472		)		(1,213		)		(4,248		)		(563		)			(2,472		)			(1,213		)			(4,248		)
Commodity derivative assets subtotal		(38		)		588				684				1,234				(38		)			588					684					1,234
Commodity derivative assets subtotal		(38		)		588				684				1,234				(38		)			588					684					1,234
Interest rate and foreign currency derivative
assets
Derivatives designated as hedging instruments		—				13				—				13				—					25					—					25
Derivatives designated as hedging instruments		—				13				—				13				—					25					—					25
Economic hedges		—				7				—				7				—					12					—					12
Economic hedges		—				7				—				7				—					12					—					12
Proprietary trading		18				3				—				21				18					3					—					21
Proprietary trading		18				3				—				21				18					3					—					21
Effect of netting and allocation of collateral		(19		)		(5		)		—				(24		)		(19		)			(5		)			—					(24		)
Effect of netting and allocation of collateral		(19		)		(5		)		—				(24		)		(19		)			(5		)			—					(24		)
Interest rate and foreign currency derivative		(1		)		18				—				17				(1		)			35					—					34
assets subtotal		(1		)		18				—				17				(1		)			35					—					34
Other investments		13				—				3				16				13					—					3					16
Other investments		13				—				3				16				13					—					3					16
Total assets		4,918				6,507				1,497				12,922				5,881					6,524					1,497					13,902
Total assets		4,918				6,507				1,497				12,922				5,881					6,524					1,497					13,902
Liabilities
Commodity derivative liabilities
Economic hedges		(458		)		(2,194		)		(1,494		)		(4,146		)		(458		)			(2,194		)			(1,672		)			(4,324		)
Proprietary trading		(133		)		(555		)		(203		)		(891		)		(133		)			(555		)			(203		)			(891		)
Effect of netting and allocation of collateral(f)		591				2,672				1,444				4,707				591					2,672					1,444					4,707
Effect of netting and allocation of collateral(f)		591				2,672				1,444				4,707				591					2,672					1,444					4,707
Commodity derivative liabilities subtotal		—				(77		)		(253		)		(330		)		—					(77		)			(431		)			(508		)
Commodity derivative liabilities subtotal		—				(77		)		(253		)		(330		)		—					(77		)			(431		)			(508		)
Interest rate and foreign currency derivative
liabilities
Derivatives designated as hedging instruments		—				(2		)		—				(2		)		—					(12		)			—					(12		)
Derivatives designated as hedging instruments		—				(2		)		—				(2		)		—					(12		)			—					(12		)
Economic hedges		—				(9		)		—				(9		)		—					(22		)			—					(22		)
Economic hedges		—				(9		)		—				(9		)		—					(22		)			—					(22		)
Proprietary trading		(17		)		(3		)		—				(20		)		(17		)			(3		)			—					(20		)
Proprietary trading		(17		)		(3		)		—				(20		)		(17		)			(3		)			—					(20		)
Effect of netting and allocation of collateral		17				5				—				22				17					5					—					22
Effect of netting and allocation of collateral		17				5				—				22				17					5					—					22
Interest rate and foreign currency derivative		—				(9		)		—				(9		)		—					(32		)			—					(32		)
liabilities subtotal		—				(9		)		—				(9		)		—					(32		)			—					(32		)
Deferred compensation obligation		—				(29		)		—				(29		)		—					(105		)			—					(105		)
Deferred compensation obligation		—				(29		)		—				(29		)		—					(105		)			—					(105		)
Total liabilities		—				(115		)		(253		)		(368		)		—					(214		)			(431		)			(645		)
Total liabilities		—				(115		)		(253		)		(368		)		—					(214		)			(431		)			(645		)
Total net assets		$	4,918			$	6,392			$	1,244			$	12,554			$	5,881				$	6,310				$	1,066				$	13,257
Total net assets		$	4,918			$	6,392			$	1,244			$	12,554			$	5,881				$	6,310				$	1,066				$	13,257


		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
Cash equivalents(a)		$	1,006			$	—			$	—			$	1,006			$	1,230			$	—			$	—			$	1,230
Nuclear decommissioning trust fund investments
Cash equivalents		459				—				—				459				459				—				—				459
Cash equivalents		459				—				—				459				459				—				—				459
Equity
Individually held		1,776				—				—				1,776				1,776				—				—				1,776
Individually held		1,776				—				—				1,776				1,776				—				—				1,776
Exchange traded funds		115				—				—				115				115				—				—				115
Exchange traded funds		115				—				—				115				115				—				—				115
Commingled funds		—				2,271				—				2,271				—				2,271				—				2,271
Commingled funds		—				2,271				—				2,271				—				2,271				—				2,271
Equity funds subtotal		1,891				2,271				—				4,162				1,891				2,271				—				4,162
Equity funds subtotal		1,891				2,271				—				4,162				1,891				2,271				—				4,162
Fixed income
Debt securities issued by the U.S.		882				—				—				882				882				—				—				882
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				294				—				294				—				294				—				294
United States and political
subdivisions of the states
Debt securities issued by foreign		—				87				—				87				—				87				—				87
governments		—				87				—				87				—				87				—				87
Corporate debt securities		—				1,753				31				1,784				—				1,753				31				1,784
Corporate debt securities		—				1,753				31				1,784				—				1,753				31				1,784
Federal agency mortgage-backed		—				10				—				10				—				10				—				10
securities		—				10				—				10				—				10				—				10
Commercial mortgage-backed		—				40				—				40				—				40				—				40
securities (non-agency)		—				40				—				40				—				40				—				40
Residential mortgage-backed securities		—				7				—				7				—				7				—				7
(non-agency)		—				7				—				7				—				7				—				7
Mutual funds		—				18				—				18				—				18				—				18
Mutual funds		—				18				—				18				—				18				—				18
Fixed income subtotal		882				2,209				31				3,122				882				2,209				31				3,122
Fixed income subtotal		882				2,209				31				3,122				882				2,209				31				3,122
Middle market lending		—				—				314				314				—				—				314				314
Middle market lending		—				—				314				314				—				—				314				314
Private Equity		—				—				5				5				—				—				5				5
Private Equity		—				—				5				5				—				—				5				5
Other debt obligations		—				14				—				14				—				14				—				14
Other debt obligations		—				14				—				14				—				14				—				14
Nuclear decommissioning trust fund investments		3,232				4,494				350				8,076				3,232				4,494				350				8,076
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
Cash equivalents		—				26				—				26				—				26				—				26
Equity
Individually held		16				—				—				16				16				—				—				16
Individually held		16				—				—				16				16				—				—				16
Equity funds subtotal		16				—				—				16				16				—				—				16
Equity funds subtotal		16				—				—				16				16				—				—				16
Fixed income
Debt securities issued by the U.S.		45				4				—				49				45				4				—				49
Treasury and other U.S. government
corporations and agencies
Debt securities issued by states of the		—				20				—				20				—				20				—				20
United States and political
subdivisions of the states
Corporate debt securities		—				227				—				227				—				227				—				227
Corporate debt securities		—				227				—				227				—				227				—				227
Fixed income subtotal		45				251				—				296				45				251				—				296
Fixed income subtotal		45				251				—				296				45				251				—				296
Middle market lending		—				—				112				112				—				—				112				112
Middle market lending		—				—				112				112				—				—				112				112
Other debt obligations		—				1				—				1				—				1				—				1
Other debt obligations		—				1				—				1				—				1				—				1
Pledged assets for Zion Station		61				278				112				451				61				278				112				451
decommissioning subtotal(c)		61				278				112				451				61				278				112				451
Rabbi trust investments(e)
Cash equivalents		—				—				—				—				2				—				—				2
Cash equivalents		—				—				—				—				2				—				—				2
Mutual funds(d)		13				—				—				13				54				—				—				54
Mutual funds(d)		13				—				—				13				54				—				—				54
Rabbi trust investments subtotal		13				—				—				13				56				—				—				56
Rabbi trust investments subtotal		13				—				—				13				56				—				—				56




		Generation																Exelon
As of December 31, 2013		Level 1				Level 2				Level 3				Total				Level 1				Level 2				Level 3				Total
Commodity derivative assets
Economic hedges		493				2,582				885				3,960				493				2,582				885				3,960
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
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
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		30				32				—				62				30				39				—				69
Effect of netting and allocation of collateral		(30		)		(2		)		—				(32		)		(30		)		(2		)		—				(32		)
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		—				30				—				30				—				37				—				37
Other investments		—				—				15				15				—				—				15				15
Other investments		—				—				15				15				—				—				15				15
Total assets		4,266				5,568				1,054				10,888				4,533				5,575				1,054				11,162
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
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		)
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		(31		)		(13		)		—				(44		)		(31		)		(17		)		—				(48		)
Effect of netting and allocation of collateral		31				1				—				32				31				1				—				32
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		—				(12		)		—				(12		)		—				(16		)		—				(16		)
Deferred compensation obligation		—				(29		)		—				(29		)		—				(114		)		—				(114		)
Deferred compensation obligation		—				(29		)		—				(29		)		—				(114		)		—				(114		)
Total liabilities		1				(180		)		(112		)		(291		)		1				(269		)		(305		)		(573		)
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
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 assets (liabilities) of $14 million and $(5) million at September 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(c)	Excludes net assets of $4 million and $7 million at September 30, 2014 and December 31, 2013, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, and payables related to pending securities purchases.

(d)	The mutual funds held by the Rabbi trusts at Exelon include $45 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at September 30, 2014, and $53 million related to deferred compensation and $1 million related to Supplemental Executive Retirement Plan at December 31, 2013.

(e)	Excludes $11 million and $35 million of cash surrender value of life insurance investment at September 30, 2014 and $10 million and $32 million of cash surrender value of life insurance investment at December 31, 2013 at Generation and Exelon, respectively.

(f)	Includes collateral postings (received) from counterparties. Collateral posted (received) from counterparties for commodity positions, net of collateral paid to counterparties, totaled $28 million, $200 million and $231 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of September 30, 2014. Collateral posted (received) 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 ComEd, PECO and BGE Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of September 30, 2014 and December 31, 2013:


		ComEd																PECO																BGE
As of September 30, 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		$	—			$	—			$	—			$	—			$	304			$	—			$	—			$	304			$	5	$	—		$	—	$	5
Cash equivalents		$	—			$	—			$	—			$	—			$	304			$	—			$	—			$	304			$	5	$	—		$	—	$	5
Rabbi trust investments
Mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		5
Mutual funds (a)		—				—				—				—				9				—				—				9				5		—			—		5
Rabbi trust investments		—				—				—				—				9				—				—				9				5		—			—		5
subtotal		—				—				—				—				9				—				—				9				5		—			—		5
Total assets		—				—				—				—				313				—				—				313				10		—			—		10
Total assets		—				—				—				—				313				—				—				313				10		—			—		10
Liabilities
Deferred compensation		—				(8		)		—				(8		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
obligation		—				(8		)		—				(8		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Mark-to-market derivative		—				—				(178		)		(178		)		—				—				—				—				—		—			—		—
liabilities (b)		—				—				(178		)		(178		)		—				—				—				—				—		—			—		—
Total liabilities		—				(8		)		(178		)		(186		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Total liabilities		—				(8		)		(178		)		(186		)		—				(15		)		—				(15		)		—		(5		)	—		(5		)
Total net assets (liabilities)		$	—			$	(8	)		$	(178	)		$	(186	)		$	313			$	(15	)		$	—			$	298			$	10	$	(5	)	$	—	$	5
Total net assets (liabilities)		$	—			$	(8	)		$	(178	)		$	(186	)		$	313			$	(15	)		$	—			$	298			$	10	$	(5	)	$	—	$	5



		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
Cash equivalents		$	—			$	—			$	—			$	—			$	175			$	—			$	—			$	175			$	31	$	—		$	—	$	31
Rabbi trust investments
Mutual funds (a)		5				—				—				5				9				—				—				9				6		—			—		6
Mutual funds (a)		5				—				—				5				9				—				—				9				6		—			—		6
Rabbi trust investments subtotal		5				—				—				5				9				—				—				9				6		—			—		6
Rabbi trust investments subtotal		5				—				—				5				9				—				—				9				6		—			—		6
Total assets		5				—				—				5				184				—				—				184				37		—			—		37
Total assets		5				—				—				5				184				—				—				184				37		—			—		37
Liabilities
Deferred compensation obligation		—				(8		)		—				(8		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Deferred compensation obligation		—				(8		)		—				(8		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Mark-to-market derivative liabilities (b)		—				—				(193		)		(193		)		—				—				—				—				—		—			—		—
Mark-to-market derivative liabilities (b)		—				—				(193		)		(193		)		—				—				—				—				—		—			—		—
Total liabilities		—				(8		)		(193		)		(201		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Total liabilities		—				(8		)		(193		)		(201		)		—				(17		)		—				(17		)		—		(6		)	—		(6		)
Total net assets (liabilities)		$	5			$	(8	)		$	(193	)		$	(196	)		$	184			$	(17	)		$	—			$	167			$	37	$	(6	)	$	—	$	31
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 September 30, 2014 and December 31, 2013.

(b)	The Level 3 balance includes the current and noncurrent liability of $14 million and $164 million at September 30, 2014, respectively, and $17 million and $176 million at December 31, 2013, respectively, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis	'
	The following table presents the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 2014 and 2013:



			Generation																				ComEd				Exelon
	Three Months Ended September 30, 2014		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Total
			Decommissioning				for Zion Station				Derivatives				Investments
			Trust Fund				Decommissioning
			Investments
	Balance as of June 30, 2014		$	592			$	133			$	242			$	10			$	977			$	(134	)		$	843
	Balance as of June 30, 2014		$	592			$	133			$	242			$	10			$	977			$	(134	)		$	843
	Total realized / unrealized gains
	(losses)
	Included in net income		1				—				76			(a)	—				77				—				77
	Included in net income		1				—				76			(a)	—				77				—				77
	Included in noncurrent		3				—				—				—				3				—				3
	payables to affiliates		3				—				—				—				3				—				3
	Included in payable for Zion		—				(2		)		—				—				(2		)		—				(2		)
	Station decommissioning		—				(2		)		—				—				(2		)		—				(2		)
	Included in regulatory assets		—				—				—				—				—				(44		)		(44		)
	Included in regulatory assets		—				—				—				—				—				(44		)		(44		)
	Change in collateral		—				—				79				—				79				—				79
	Change in collateral		—				—				79				—				79				—				79
	Purchases, sales, issuances and
	settlements
	Purchases		83				53				12				—				148				—				148
	Purchases		83				53				12				—				148				—				148
	Sales		(8		)		(18		)		—				(7		)		(33		)		—				(33		)
	Sales		(8		)		(18		)		—				(7		)		(33		)		—				(33		)
	Settlements		(27		)		—				—				—				(27		)		—				(27		)
	Settlements		(27		)		—				—				—				(27		)		—				(27		)
	Transfers into Level 3		—				—				21				—				21				—				21
	Transfers into Level 3		—				—				21				—				21				—				21
	Transfers out of Level 3		—				—				1				—				1				—				1
	Transfers out of Level 3		—				—				1				—				1				—				1
	Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
	Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
	The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2014		$	1			$	—			$	163			$	—			$	164			$	—			$	164
			$	1			$	—			$	163			$	—			$	164			$	—			$	164



			Generation																				ComEd				Exelon
	Nine Months Ended September 30, 2014		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives (b)				Total
			Decommissioning				for Zion Station				Derivatives				Investments
			Trust Fund				Decommissioning
			Investments
	Balance as of December 31, 2013		$	350			$	112			$	465			$	15			$	942			$	(193	)		$	749
	Balance as of December 31, 2013		$	350			$	112			$	465			$	15			$	942			$	(193	)		$	749
	Total realized / unrealized gains
	(losses)
	Included in net income		5				—				(284		)	(a)	—				(279		)		—				(279		)
	Included in net income		5				—				(284		)	(a)	—				(279		)		—				(279		)
	Included in noncurrent		14				—				—				—				14				—				14
	payables to affiliates		14				—				—				—				14				—				14
	Included in payable for Zion		—				2				—				—				2				—				2
	Station decommissioning		—				2				—				—				2				—				2
	Included in regulatory assets		—				—				—				—				—				15				15
	Included in regulatory assets		—				—				—				—				—				15				15
	Change in collateral		—				—				257				—				257				—				257
	Change in collateral		—				—				257				—				257				—				257
	Purchases, sales, issuances and
	settlements
Purchases		331				95				27				2				455				—				455
Purchases		331				95				27				2				455				—				455
Sales		(10		)		(43		)		(6		)		(7		)		(66		)		—				(66		)
Sales		(10		)		(43		)		(6		)		(7		)		(66		)		—				(66		)
Settlements		(46		)		—				—				—				(46		)		—				(46		)
Settlements		(46		)		—				—				—				(46		)		—				(46		)
Transfers into Level 3		—				—				(9		)		—				(9		)		—				(9		)
Transfers into Level 3		—				—				(9		)		—				(9		)		—				(9		)
Transfers out of Level 3		—				—				(19		)		(7		)		(26		)		—				(26		)
Transfers out of Level 3		—				—				(19		)		(7		)		(26		)		—				(26		)
Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
Balance as of September 30, 2014		$	644			$	166			$	431			$	3			$	1,244			$	(178	)		$	1,066
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held for the nine months ended September 30, 2014		$	3			$	—			$	(264	)		$	—			$	(261	)		$	—			$	(261	)
		$	3			$	—			$	(264	)		$	—			$	(261	)		$	—			$	(261	)


(a)	Includes an increase for the reclassification of $87 million and $20 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2014, respectively.

(b)	Includes $45 million of increases and $19 million of decreases in fair value and realized losses due to settlements of $1 million and realized gains due to settlements of $4 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2014, respectively.





		Generation																				ComEd				Exelon
Three Months Ended September 30, 2013		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to-Market Derivatives(c)				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of June 30, 2013		$	240			$	111			$	516			$	11			$	878			$	(85	)		$	793
Balance as of June 30, 2013		$	240			$	111			$	516			$	11			$	878			$	(85	)		$	793
Total realized / unrealized gains
(losses)
Included in net income		—				—				(32		)	(a)	—				(32		)		—				(32		)
Included in net income		—				—				(32		)	(a)	—				(32		)		—				(32		)
Included in noncurrent payables		(1		)		—				—				—				(1		)		—				(1		)
to affiliates		(1		)		—				—				—				(1		)		—				(1		)
Included in payable for Zion		—				—				—				—				—				—				—
Station decommissioning		—				—				—				—				—				—				—
Included in regulatory assets		—				—				—				—				—				(37		)		(37		)
Included in regulatory assets		—				—				—				—				—				(37		)		(37		)
Change in collateral		—				—				(30		)		—				(30		)		—				(30		)
Change in collateral		—				—				(30		)		—				(30		)		—				(30		)
Purchases, sales, issuances and
settlements
Purchases		23				10				8				—				41				—				41
Purchases		23				10				8				—				41				—				41
Sales		(14		)		(15		)		—				—				(29		)		—				(29		)
Sales		(14		)		(15		)		—				—				(29		)		—				(29		)
Settlements		(3		)		—				—				—				(3		)		—				(3		)
Settlements		(3		)		—				—				—				(3		)		—				(3		)
Transfers into Level 3		—				—				4				—				4				—				4
Transfers into Level 3		—				—				4				—				4				—				4
Transfers out of Level 3		—				—				(5		)		—				(5		)		—				(5		)
Transfers out of Level 3		—				—				(5		)		—				(5		)		—				(5		)
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the three months ended September 30, 2013		$	—			$	—			$	51			$	—			$	51			$	—			$	51
		$	—			$	—			$	51			$	—			$	51			$	—			$	51




		Generation																				ComEd				Exelon
Nine Months Ended September 30, 2013		Nuclear				Pledged Assets				Mark-to-Market				Other				Total Generation				Mark-to- Market Derivatives(c)(d)				Total
		Decommissioning				for Zion Station				Derivatives				Investments
		Trust Fund				Decommissioning
		Investments
Balance as of December 31, 2012		$	183			$	89			$	660			$	17			$	949			$	(293	)		$	656
Balance as of December 31, 2012		$	183			$	89			$	660			$	17			$	949			$	(293	)		$	656
Total realized / unrealized gains
(losses)
Included in net income		2				—				(8		)	(a)(b)	—				(6		)		—				(6		)
Included in net income		2				—				(8		)	(a)(b)	—				(6		)		—				(6		)
Included in other		—				—				(219		)	(b)	—				(219		)		—				(219		)
comprehensive income		—				—				(219		)	(b)	—				(219		)		—				(219		)
Included in noncurrent		8				—				—				—				8				226				234
payables to affiliates		8				—				—				—				8				226				234
Included in payable for Zion		—				1				—				—				1				—				1
Station decommissioning		—				1				—				—				1				—				1
Included in regulatory assets		—				—				—				—				—				(55		)		(55		)
Included in regulatory assets		—				—				—				—				—				(55		)		(55		)
Change in collateral		—				—				13				—				13				—				13
Change in collateral		—				—				13				—				13				—				13
Purchases, sales, issuances and
settlements
Purchases		90				43				16				2				151				—				151
Purchases		90				43				16				2				151				—				151
Sales		(27		)		(27		)		(8		)		(8		)		(70		)		—				(70		)
Sales		(27		)		(27		)		(8		)		(8		)		(70		)		—				(70		)
Settlements		(11		)		—				—				—				(11		)		—				(11		)
Settlements		(11		)		—				—				—				(11		)		—				(11		)
Transfers into Level 3		—				—				11				—				11				—				11
Transfers into Level 3		—				—				11				—				11				—				11
Transfers out of Level 3		—				—				(4		)		—				(4		)		—				(4		)
Transfers out of Level 3		—				—				(4		)		—				(4		)		—				(4		)
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
Balance as of September 30, 2013		$	245			$	106			$	461			$	11			$	823			$	(122	)		$	701
The amount of total gains included in income attributed to the change in unrealized gains related to assets and liabilities held for the nine months ended September 30, 2013		$	1			$	—			$	148			$	—			$	149			$	11			$	160
		$	1			$	—			$	148			$	—			$	149			$	11			$	160


(a)	Includes the reclassification of $83 million and $156 million of realized losses due to the settlement of derivative contracts recorded in results of operations for the three and nine months ended September 30, 2013, respectively.

(b)	Includes $11 million of increases in fair value and realized gains due to settlements of $215 million associated with Generation's financial swap contract with ComEd for the nine months ended September 30, 2013. This position eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(c)	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 nine months ended September 30, 2013. This position eliminates upon consolidation in Exelon’s Consolidated Financial Statements.

(d)	Includes $37 million and $57 million of increases in fair value and realized losses due to settlements of $1 million and $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three and nine months ended September 30, 2013, respectively.
Total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis	'
	The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and nine months ended September 30, 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 three months ended September 30, 2014		$	70			$	6			$	1			$	70			$	6			$	1
			$	70			$	6			$	1			$	70			$	6			$	1
	Total gains (losses) included in net income for the nine months ended September 30, 2014		(260		)		(24		)		5				(260		)		(24		)		5
			(260		)		(24		)		5				(260		)		(24		)		5
	Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2014		142				21				1				142				21				1
			142				21				1				142				21				1
	Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2014		(293		)		29				3				(293		)		29				3
			(293		)		29				3				(293		)		29				3



		Generation												Exelon
		Operating				Purchased				Other, net(a)				Operating				Purchased				Other, net(a)
		Revenues				Power and								Revenues				Power and
						Fuel												Fuel
	Total gains (losses) included in net income for the three months ended September 30, 2013	$	(39	)		$	7			$	—			$	(39	)		$	7			$	—
		$	(39	)		$	7			$	—			$	(39	)		$	7			$	—
	Total gains (losses) included in net income for the nine months ended September 30, 2013	(67		)		59				2				(61		)		60				2
		(67		)		59				2				(61		)		60				2
	Change in the unrealized gains (losses) relating to assets and liabilities held for the three months ended September 30, 2013	42				9				—				42				9				—
		42				9				—				42				9				—
	Change in the unrealized gains (losses) relating to assets and liabilities held for the nine months ended September 30, 2013	71				77				1				81				78				1
		71				77				1				81				78				1


	(a)	Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation.
Fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis, valuation technique	'
	The table below discloses the significant inputs to the forward curve used to value these positions.



	Type of trade		Fair Value at September 30, 2014				Valuation		Unobservable		Range
	Type of trade		Fair Value at September 30, 2014				Technique		Input		Range
	Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	189			Discounted		Forward power		$13	-	$194	(d)
			$	189			Cash Flow		price		$13	-	$194	(d)
									Forward gas		$2.54	-	$22.15	(d)
									price		$2.54	-	$22.15	(d)
							Option Model		Volatility		8%	-	154%
							Option Model		percentage		8%	-	154%
	Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	11			Discounted		Forward power		$14	-	$191	(d)
			$	11			Cash Flow		price		$14	-	$191	(d)
							Option Model		Volatility		8%	-	154%
							Option Model		percentage		8%	-	154%
	Mark-to-market derivatives (ComEd)		$	(178	)		Discounted		Forward heat		8x	-	9x
	Mark-to-market derivatives (ComEd)		$	(178	)		Cash Flow		rate(b)		8x	-	9x
									Marketability		3.50%	-	8%
									reserve		3.50%	-	8%
									Renewable		86%	-	126%
									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 $231 million as of September 30, 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 economic hedges would be approximately $146 and $10.62, respectively, and would be approximately $104 for power proprietary trading.



	Type of trade		Fair Value at December 31, 2013				Valuation		Unobservable		Range
	Type of trade		Fair Value at December 31, 2013				Technique		Input		Range
	Mark-to-market derivatives — Economic Hedges (Generation)(a)(c)		$	488			Discounted		Forward power		$8	-	$176	(d)
			$	488			Cash Flow		price		$8	-	$176	(d)
									Forward gas		$2.98	-	$16.63	(d)
									price		$2.98	-	$16.63	(d)
							Option Model		Volatility		15%	-	142%
							Option Model		percentage		15%	-	142%
	Mark-to-market derivatives — Proprietary trading (Generation)(a)(c)		$	3			Discounted		Forward power		$10	-	$176	(d)
			$	3			Cash Flow		price		$10	-	$176	(d)
							Option Model		Volatility		14%	-	19%
							Option Model		percentage		14%	-	19%
	Mark-to-market derivatives (ComEd)		$	(193	)		Discounted		Forward heat		8x	-	9x
	Mark-to-market derivatives (ComEd)		$	(193	)		Cash Flow		rate(b)		8x	-	9x
									Marketability		3.50%	-	8%
									reserve		3.50%	-	8%
									Renewable		84%	-	128%
									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.
Exelon Generation Co L L C [Member]	'
Fair Value Tables [Line Items]	'
Fair value of financial liabilities recorded at the carrying amount	'
	Generation


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	14			$	—			$	14			$	—			$	14
	Short-term liabilities	$	14			$	—			$	14			$	—			$	14
	Long-term debt (including amounts due within one year)	8,320				—				7,543				1,297				8,840
	Long-term debt (including amounts due within one year)	8,320				—				7,543				1,297				8,840
	SNF obligation	1,021				—				849				—				849
	SNF obligation	1,021				—				849				—				849



		December 31, 2013
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	22			$	—			$	22			$	—			$	22
	Short-term liabilities	$	22			$	—			$	22			$	—			$	22
	Long-term debt (including amounts due within one year)	7,729				—				6,586				1,062				7,648
	Long-term debt (including amounts due within one year)	7,729				—				6,586				1,062				7,648
	SNF obligation	1,021				—				790				—				790
	SNF obligation	1,021				—				790				—				790
Commonwealth Edison Co [Member]	'
Fair Value Tables [Line Items]	'
Fair value of financial liabilities recorded at the carrying amount	'
	ComEd


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	528			$	—			$	528			$	—			$	528
	Short-term liabilities	$	528			$	—			$	528			$	—			$	528
	Long-term debt (including amounts due within one year)	5,708				—				6,422				—				6,422
	Long-term debt (including amounts due within one year)	5,708				—				6,422				—				6,422
	Long-term debt to financing trust	206				—				—				214				214
	Long-term debt to financing trust	206				—				—				214				214


		December 31, 2013
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	184			$	—			$	184			$	—			$	184
	Short-term liabilities	$	184			$	—			$	184			$	—			$	184
	Long-term debt (including amounts due within one year)	5,675				—				6,238				17				6,255
	Long-term debt (including amounts due within one year)	5,675				—				6,238				17				6,255
	Long-term debt to financing trust	206				—				—				202				202
	Long-term debt to financing trust	206				—				—				202				202
PECO Energy Co [Member]	'
Fair Value Tables [Line Items]	'
Fair value of financial liabilities recorded at the carrying amount	'
	PECO


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Long-term debt (including amounts due within one year)	$	2,496			$	—			$	2,720			$	—			$	2,720
	Long-term debt (including amounts due within one year)	$	2,496			$	—			$	2,720			$	—			$	2,720
	Long-term debt to financing trusts	184				—				—				204				204
	Long-term debt to financing trusts	184				—				—				204				204



		December 31, 2013
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Long-term debt (including amounts due within one year)	$	2,197			$	—			$	2,358			$	—			$	2,358
	Long-term debt (including amounts due within one year)	$	2,197			$	—			$	2,358			$	—			$	2,358
	Long-term debt to financing trusts	184				—				—				180				180
	Long-term debt to financing trusts	184				—				—				180				180
Baltimore Gas and Electric Company [Member]	'
Fair Value Tables [Line Items]	'
Fair value of financial liabilities recorded at the carrying amount	'
	BGE


		30-Sep-14
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	23			$	3			$	20			$	—			$	23
	Short-term liabilities	$	23			$	3			$	20			$	—			$	23
	Long-term debt (including amounts due within one year)	1,976				—				2,196				—				2,196
	Long-term debt (including amounts due within one year)	1,976				—				2,196				—				2,196
	Long-term debt to financing trusts	258				—				—				259				259
	Long-term debt to financing trusts	258				—				—				259				259



		December 31, 2013
		Carrying				Fair Value
		Amount				Level 1				Level 2				Level 3				Total
	Short-term liabilities	$	138			$	3			$	135			$	—			$	138
	Short-term liabilities	$	138			$	3			$	135			$	—			$	138
	Long-term debt (including amounts due within one year)	2,011				—				2,148				—				2,148
	Long-term debt (including amounts due within one year)	2,011				—				2,148				—				2,148
	Long-term debt to financing trusts	258				—				—				249				249
	Long-term debt to financing trusts	258				—				—				249				249

Derivative_Financial_Instrumen1

Derivative Financial Instruments (Tables)	9 Months Ended
Derivative Financial Instruments (Tables)	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Summary of the derivative fair value	'
	Below is a summary of the interest rate and foreign currency hedges as of September 30, 2014.



			Generation																				Other							Exelon
	Description		Derivatives				Economic				Proprietary				Collateral				Subtotal				Derivatives				Economic			Total
			Designated				Hedges				Trading(a)				and								Designated				Hedges
			as Hedging												Netting(b)								as Hedging
			Instruments																				Instruments
	Mark-to-market derivative		$	—			$	4			$	14			$	(14	)		$	4			$	—			$	—		$	4
	assets (current assets)		$	—			$	4			$	14			$	(14	)		$	4			$	—			$	—		$	4
	Mark-to-market derivative		13				3				7				(10		)		13				12				5			30
	assets (noncurrent
	assets)
	Total mark-to-market		13				7				21				(24		)		17				12				5			34
	derivative assets		13				7				21				(24		)		17				12				5			34
	Mark-to-market derivative		(1		)		(7		)		(11		)		13				(6		)		—				—			(6		)
	liabilities (current
	liabilities)
	Mark-to-market derivative		(1		)		(2		)		(9		)		9				(3		)		(10		)		(13		)	(26		)
	liabilities (noncurrent
	liabilities)
	Total mark-to-market		(2		)		(9		)		(20		)		22				(9		)		(10		)		(13		)	(32		)
	derivative liabilities		(2		)		(9		)		(20		)		22				(9		)		(10		)		(13		)	(32		)
	Total mark-to-market		$	11			$	(2	)		$	1			$	(2	)		$	8			$	2			$	(8	)	$	2
	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				Hedges				Trading(a)				and								Designated
			as Hedging												Netting(b)								as Hedging
			Instruments																				Instruments
	Mark-to-market derivative assets		$	—			$	3			$	15			$	(19	)		$	(1	)		$	—			$	(1	)
	(current assets)		$	—			$	3			$	15			$	(19	)		$	(1	)		$	—			$	(1	)
	Mark-to-market derivative assets		26				3				15				(13		)		31				7				38
	(noncurrent assets)		26				3				15				(13		)		31				7				38
	Total mark-to-market derivative		26				6				30				(32		)		30				7				37
	assets		26				6				30				(32		)		30				7				37
	Mark-to-market derivative liabilities		(1		)		(1		)		(18		)		19				(1		)		—				(1		)
	(current liabilities)		(1		)		(1		)		(18		)		19				(1		)		—				(1		)
	Mark-to-market derivative liabilities		(10		)		(1		)		(13		)		13				(11		)		(4		)		(15		)
	(noncurrent liabilities)		(10		)		(1		)		(13		)		13				(11		)		(4		)		(15		)
	Total mark-to-market derivative		(11		)		(2		)		(31		)		32				(12		)		(4		)		(16		)
	liabilities		(11		)		(2		)		(31		)		32				(12		)		(4		)		(16		)
	Total mark-to-market derivative		$	15			$	4			$	(1	)		$	—			$	18			$	3			$	21
	net assets (liabilities)		$	15			$	4			$	(1	)		$	—			$	18			$	3			$	21
	_______________

	(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.
	Exelon includes the gain or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:



			Three Months Ended September 30,
	Income Statement		2014				2013				2014				2013
	Location		Gain (Loss) on Swaps								Gain (Loss) on Borrowings
Generation	Interest expense(a)		$	(4	)		$	(4	)		$	1			$	(1	)
Generation	Interest expense(a)		$	(4	)		$	(4	)		$	1			$	(1	)
Exelon	Interest expense		(8		)		—				(6		)		(6		)
Exelon	Interest expense		(8		)		—				(6		)		(6		)

			Nine Months Ended September 30,
	Income Statement		2014				2013				2014				2013
	Location		Gain (Loss) on Swaps								Gain (Loss) on Borrowings
Generation	Interest expense(a)		$	(12	)		$	(13	)		$	1			$	—
Generation	Interest expense(a)		$	(12	)		$	(13	)		$	1			$	—
Exelon	Interest expense		(3		)		(12		)		6				(2		)
Exelon	Interest expense		(3		)		(12		)		6				(2		)
__________

(a)	For the three and nine months ended September 30, 2014, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with $2 million amount excluded from hedge effectiveness testing. For the three and nine months ended September 30, 2013, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with an immaterial excluded from hedge effectiveness testing.
The following table provides a summary of the derivative fair value balances recorded by the Registrants as of September 30, 2014:



		Generation																ComEd				Exelon
Derivatives		Economic				Proprietary				Collateral				Subtotal(b)				Economic				Total
		Hedges				Trading				and								Hedges(c)				Derivatives
										Netting(a)
Mark-to-market derivative assets		$	3,230			$	752			$	(3,242	)		$	740			$	—			$	740
(current assets)		$	3,230			$	752			$	(3,242	)		$	740			$	—			$	740
Mark-to-market derivative assets		1,372				128				(1,006		)		494				—				494
(noncurrent assets)		1,372				128				(1,006		)		494				—				494
Total mark-to-market derivative		4,602				880				(4,248		)		1,234				—				1,234
assets		4,602				880				(4,248		)		1,234				—				1,234
Mark-to-market derivative liabilities		(3,017		)		(755		)		3,543				(229		)		(14		)		(243		)
(current liabilities)		(3,017		)		(755		)		3,543				(229		)		(14		)		(243		)
Mark-to-market derivative liabilities		(1,129		)		(136		)		1,164				(101		)		(164		)		(265		)
(noncurrent liabilities)		(1,129		)		(136		)		1,164				(101		)		(164		)		(265		)
Total mark-to-market derivative		(4,146		)		(891		)		4,707				(330		)		(178		)		(508		)
liabilities		(4,146		)		(891		)		4,707				(330		)		(178		)		(508		)
Total mark-to-market derivative		$	456			$	(11	)		$	459			$	904			$	(178	)		$	726
net assets (liabilities)		$	456			$	(11	)		$	459			$	904			$	(178	)		$	726
_________

(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 $(96) million and $(50) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(205) million and $(108) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $459 million at September 30, 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
Description		Economic				Proprietary				Collateral				Subtotal(b)				Economic				Total
		Hedges				Trading				and								Hedges(c)				Derivatives
										Netting(a)
Mark-to-market derivative assets		$	2,616			$	1,476			$	(3,364	)		$	728			$	—			$	728
(current assets)		$	2,616			$	1,476			$	(3,364	)		$	728			$	—			$	728
Mark-to-market derivative assets		1,344				285				(1,060		)		569				—				569
(noncurrent assets)		1,344				285				(1,060		)		569				—				569
Total mark-to-market derivative		3,960				1,761				(4,424		)		1,297				—				1,297
assets		3,960				1,761				(4,424		)		1,297				—				1,297
Mark-to-market derivative liabilities		(2,023		)		(1,410		)		3,292				(141		)		(17		)		(158		)
(current liabilities)		(2,023		)		(1,410		)		3,292				(141		)		(17		)		(158		)
Mark-to-market derivative liabilities		(804		)		(293		)		988				(109		)		(176		)		(285		)
(noncurrent liabilities)		(804		)		(293		)		988				(109		)		(176		)		(285		)
Total mark-to-market derivative		(2,827		)		(1,703		)		4,280				(250		)		(193		)		(443		)
liabilities		(2,827		)		(1,703		)		4,280				(250		)		(193		)		(443		)
Total mark-to-market derivative		$	1,133			$	58			$	(144	)		$	1,047			$	(193	)		$	854
net assets (liabilities)		$	1,133			$	58			$	(144	)		$	1,047			$	(193	)		$	854
________

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

(b)	Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. 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.
The activity of accumulated OCI related to cash flow hedges	'
	The amounts reclassified from accumulated OCI, when combined with the impacts of the actual physical power sales, result in the ultimate recognition of net revenues at the contracted price.



					Total Cash Flow Hedge OCI Activity, Net of Income Tax
					Generation				Exelon
	Three Months Ended September 30, 2014		Income Statement		Energy-Related				Total Cash Flow
	Three Months Ended September 30, 2014		Location		Hedges				Hedges
	Accumulated OCI derivative gain at June 30, 2014				$	57		(a)	$	47
	Accumulated OCI derivative gain at June 30, 2014				$	57		(a)	$	47
	Effective portion of changes in fair value				—				(3		)
	Effective portion of changes in fair value				—				(3		)
	Reclassifications from accumulated OCI to net income		Operating Revenues		(16		)	(b)	(16		)
	Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
	Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
	__________

	(a)	Excludes $13 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2014 and June 30, 2014.

	(b)	Amount is net of related income tax expense of $12 million for the three months ended September 30, 2014.


					Total Cash Flow Hedge OCI Activity, Net of Income Tax
					Generation				Exelon
	Nine Months Ended September 30, 2014		Income Statement		Energy-Related				Total Cash Flow
	Nine Months Ended September 30, 2014		Location		Hedges				Hedges
	Accumulated OCI derivative gain at December 31, 2013				$	119		(a)	$	120
	Accumulated OCI derivative gain at December 31, 2013				$	119		(a)	$	120
	Effective portion of changes in fair value				—				(14		)
	Effective portion of changes in fair value				—				(14		)
	Reclassifications from accumulated OCI to net income		Operating Revenues		(78		)	(b)	(78		)
	Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
	Accumulated OCI derivative gain at September 30, 2014				$	41		(a)	$	28
	______

	(a)	Excludes $13 million and $5 million of losses, net of taxes, related to interest rate swaps and treasury locks as of September 30, 2014 and December 31, 2013, respectively.

	(b)	Amount is net of related income tax expense of $52 million for the nine months ended September 30, 2014.


					Total Cash
					Flow Hedge OCI Activity,
					Net of Income Tax
					Generation				Exelon
	Three Months Ended September 30, 2013		Income Statement		Energy-Related				Total Cash Flow
	Three Months Ended September 30, 2013		Location		Hedges				Hedges
	Accumulated OCI derivative gain at June 30, 2013				$	255		(a)	$	245
	Accumulated OCI derivative gain at June 30, 2013				$	255		(a)	$	245
	Effective portion of changes in fair value				—				2			(b)
	Effective portion of changes in fair value				—				2			(b)
	Reclassifications from accumulated OCI to net income		Operating Revenues		(51		)	(c)	(48		)
	Accumulated OCI derivative gain at September 30, 2013				$	204		(a)	$	199
	Accumulated OCI derivative gain at September 30, 2013				$	204		(a)	$	199
	_____________

	(a)	Excludes $11 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and June 30, 2013.

	(b)	Includes $2 million of gains, 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 three months ended September 30, 2013.

	(c)	Amount is net of related income tax expense of $33 million for the three months ended September 30, 2013.


					Total Cash
Flow Hedge OCI Activity,
Net of Income Tax
								Generation				Exelon
Nine Months Ended September 30, 2013						Income Statement		Energy-Related				Total Cash Flow
Nine Months Ended September 30, 2013	Location	Hedges				Hedges
Accumulated OCI derivative gain at December 31, 2012				$	532			(a) (c)	$	368
Accumulated OCI derivative gain at December 31, 2012				$	532			(a) (c)	$	368
Effective portion of changes in fair value				—				25			(d)
Effective portion of changes in fair value				—				25			(d)
Reclassifications from accumulated OCI to net income		Operating Revenues		(328		)	(b) (e)	(194		)
Accumulated OCI derivative gain at September 30, 2013				$	204		(c)	$	199
Accumulated OCI derivative gain at September 30, 2013				$	204		(c)	$	199
__________

(a)	Includes $133 million of gains, net of taxes, related to the fair value of the five-year financial swap contract with ComEd, as of December 31, 2012.

(b)	Includes $133 million of losses, net of taxes, reclassified from accumulated OCI to recognize gains in net income related to the settlements of the five-year financial swap contract with ComEd.

(c)	Excludes $11 million of losses and $20 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of September 30, 2013 and December 31, 2012, respectively.

(d)	Includes $25 million of losses, net of taxes, related to the effective portion of changes in fair value of interest rate swaps and treasury rate locks.

(e)	Amount is net of related income tax expense of $215 million for the nine months ended September 30, 2013.
Other Derivatives - Gain (loss) and reclassification	'
	In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the derivative during the period.



			Generation																Intercompany				HoldCo				Exelon
			Generation																Eliminations				HoldCo				Exelon
	Three Months Ended September 30, 2014		Operating				Purchased				Interest Expense				Total				Operating				Interest				Total
			Revenues				Power												Revenues (a)				Expense
							and Fuel
	Change in fair value of commodity		$	181			$	19			$	—			$	200			$	—			$	—			$	200
	positions		$	181			$	19			$	—			$	200			$	—			$	—			$	200
	Reclassification to realized at		86				(23		)		—				63				—				—				63
	settlement of commodity positions		86				(23		)		—				63				—				—				63
	Net commodity mark-to-market gains		267				(4		)		—				263				—				—				263
	(losses)		267				(4		)		—				263				—				—				263
	Change in fair value of treasury		5				—				(3		)		2				—				(8		)		(6		)
	positions		5				—				(3		)		2				—				(8		)		(6		)
	Reclassification to realized at		(1		)		—				—				(1		)		—				—				(1		)
	settlement of treasury positions		(1		)		—				—				(1		)		—				—				(1		)
	Net treasury mark-to-market gains		4				—				(3		)		1				—				(8		)		(7		)
	(losses)		4				—				(3		)		1				—				(8		)		(7		)

	Net mark-to-market gains (losses)		$	271			$	(4	)		$	(3	)		$	264			$	—			$	(8	)		$	256
	Net mark-to-market gains (losses)		$	271			$	(4	)		$	(3	)		$	264			$	—			$	(8	)		$	256



			Generation																Intercompany				HoldCo				Exelon
			Generation																Eliminations				HoldCo				Exelon
	Nine Months Ended September 30, 2014		Operating				Purchased				Interest				Total				Operating				Interest				Total
			Revenues				Power				Expense								Revenues(a)				Expense
							and Fuel
	Change in fair value of commodity		$	(795	)		$	302			$	—			$	(493	)		$	—			$	—			$	(493	)
	positions		$	(795	)		$	302			$	—			$	(493	)		$	—			$	—			$	(493	)
	Reclassification to realized at		224				(207		)		—				17				—				—				17
	settlement of commodity positions		224				(207		)		—				17				—				—				17
	Net commodity mark-to-market gains		(571		)		95				—				(476		)		—				—				(476		)
	(losses)		(571		)		95				—				(476		)		—				—				(476		)
	Change in fair value of treasury		1				—				(5		)		(4		)		—				(8		)		(12		)
	positions		1				—				(5		)		(4		)		—				(8		)		(12		)
	Reclassification to realized at		(2		)		—				—				(2		)		—				—				(2		)
	settlement of treasury positions		(2		)		—				—				(2		)		—				—				(2		)
	Net treasury mark-to-market gains		(1		)		—				(5		)		(6		)		—				(8		)		(14		)
	(losses)		(1		)		—				(5		)		(6		)		—				(8		)		(14		)

	Net mark-to-market gains (losses)		$	(572	)		$	95			$	(5	)		$	(482	)		$	—			$	(8	)		$	(490	)
	Net mark-to-market gains (losses)		$	(572	)		$	95			$	(5	)		$	(482	)		$	—			$	(8	)		$	(490	)




			Generation																Intercompany				HoldCo				Exelon
			Generation																Eliminations				HoldCo				Exelon
	Three Months Ended September 30, 2013		Operating				Purchased				Interest Expense				Total				Operating				Interest				Total
			Revenues				Power												Revenues(a)				Expense
							and Fuel
	Change in fair value of commodity		$	175			$	5			$	—			$	180			$	—			$	—			$	180
	positions		$	175			$	5			$	—			$	180			$	—			$	—			$	180
	Reclassification to realized at settlement		41				25				—				66				—				—				66
	of commodity positions		41				25				—				66				—				—				66
	Net commodity mark-to-market gains		216				30				—				246				—				—				246
	(losses)		216				30				—				246				—				—				246
	Change in fair value of treasury positions		—				—				—				—				—				—				—
	Change in fair value of treasury positions		—				—				—				—				—				—				—
Reclassification to realized at settlement		—				—				—				—				—				—				—
of treasury positions		—				—				—				—				—				—				—
Net treasury mark-to-market gains		—				—				—				—				—				—				—
(losses)		—				—				—				—				—				—				—

Net mark-to-market gains (losses)		$	216			$	30			$	—			$	246			$	—			$	—			$	246
Net mark-to-market gains (losses)		$	216			$	30			$	—			$	246			$	—			$	—			$	246




		Generation																Intercompany				HoldCo				Exelon
		Generation																Eliminations				HoldCo				Exelon
Nine Months Ended September 30, 2013		Operating				Purchased				Interest Expense				Total				Operating				Interest				Total
		Revenues				Power												Revenues(a)				Expense
						and Fuel
Change in fair value of commodity		$	149			$	74			$	—			$	223			$	(6	)		$	—			$	217
positions		$	149			$	74			$	—			$	223			$	(6	)		$	—			$	217
Reclassification to realized at		(15		)		63				—				48				13				—				61
settlement of commodity positions		(15		)		63				—				48				13				—				61
Net commodity mark-to-market gains		134				137				—				271				7				—				278
(losses)		134				137				—				271				7				—				278
Change in fair value of treasury		—				—				(3		)		(3		)		—				—				(3		)
positions		—				—				(3		)		(3		)		—				—				(3		)
Reclassification to realized at		—				—				—				—				—				—				—
settlement of treasury positions		—				—				—				—				—				—				—
Net treasury mark-to-market gains		—				—				(3		)		(3		)		—				—				(3		)
(losses)		—				—				(3		)		(3		)		—				—				(3		)

Net mark-to-market gains (losses)		$	134			$	137			$	(3	)		$	268			$	7			$	—			$	275
Net mark-to-market gains (losses)		$	134			$	137			$	(3	)		$	268			$	7			$	—			$	275
______________

(a)	Prior to the 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		Three Months Ended September 30,								Nine Months Ended September 30,
	Statement		2014				2013				2014				2013
Change in fair value of commodity positions	Operating Revenues		$	(2	)		$	—			$	(2	)		$	1
Change in fair value of commodity positions	Operating Revenues		$	(2	)		$	—			$	(2	)		$	1
Reclassification to realized at settlement	Operating Revenues		(10		)		(39		)		(17		)		(34		)
of commodity positions	Operating Revenues		(10		)		(39		)		(17		)		(34		)
Net commodity mark-to-market gains (losses)	Operating Revenues		(12		)		(39		)		(19		)		(33		)

Change in fair value of treasury positions	Operating Revenues		1				—				—				—
Change in fair value of treasury positions	Operating Revenues		1				—				—				—
Reclassification to realized at settlement	Operating Revenues		—				(1		)		1				(2		)
of treasury positions	Operating Revenues		—				(1		)		1				(2		)
Net treasury mark-to-market gains (losses)	Operating Revenues		1				(1		)		1				(2		)
Net treasury mark-to-market gains (losses)	Operating Revenues		1				(1		)		1				(2		)

Net mark-to-market gains (losses)	Operating Revenues		$	(11	)		$	(40	)		$	(18	)		$	(35	)
Information on Generation's credit exposure for all derivative instruments, normal purchase normal sales, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements	'
	The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:



	Credit-Risk Related Contingent Feature		30-Sep-14				31-Dec-13
	Gross Fair Value of Derivative Contracts Containing this Feature(a)		$	(997	)		$	(1,056	)
	Offsetting Fair Value of In-the-Money Contracts Under Master		694				846
	Netting Arrangements(b)		694				846
	Net Fair Value of Derivative Contracts Containing This Feature(c)		$	(303	)		$	(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.
	The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of September 30, 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 excludes credit risk exposure from individual retail counterparties, uranium procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE and Nodal commodity exchanges, further discussed in ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO and BGE of $11 million, $21 million and $34 million, respectively.



	Rating as of September 30, 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		$	1,240			$	88			$	1,152			1			$	423
	Investment grade		$	1,240			$	88			$	1,152			1			$	423
	Non-investment grade		23				7				16				—			—
	Non-investment grade		23				7				16				—			—
	No external ratings
	Internally rated — investment grade		302				—				302				1			180
	Internally rated — investment grade		302				—				302				1			180
	Internally rated — non-investment		26				3				23				—			—
	grade		26				3				23				—			—
	Total		$	1,591			$	98			$	1,493			2			$	603
	Total		$	1,591			$	98			$	1,493			2			$	603



	Net Credit Exposure by Type of Counterparty		As of September 30, 2014
	Financial institutions		$	264
	Financial institutions		$	264
	Investor-owned utilities, marketers, power producers		470
	Investor-owned utilities, marketers, power producers		470
	Energy cooperatives and municipalities		749
	Energy cooperatives and municipalities		749
	Other		10
	Other		10
	Total		$	1,493
	Total		$	1,493
	_____

	(a)	As of September 30, 2014, credit collateral held from counterparties where Generation had credit exposure included $94 million of cash and $4 million of letters of credit.

Debt_and_Credit_Agreements_Tab

Debt and Credit Agreements (Tables)	9 Months Ended
	Sep. 30, 2014
Debt Disclosure [Abstract]	'
Schedule of Short-term Debt	'
	Exelon had bank lines of credit under committed credit facilities at September 30, 2014 for short-term financial needs, as follows:




	Type of Credit Facility		Amount(a)				Expiration Dates		Capacity Type
			(In billions)
	Exelon Corporate
	Syndicated Revolver(b)		$	0.5			May-19		Letters of credit and cash

	Generation
	Syndicated Revolver		5.1				May-19		Letters of credit and cash

	Syndicated Revolver		0.2				Aug-18		Letters of credit and cash

	Bilateral		0.3				December 2015 and March 2016		Letters of credit and cash

	Bilateral		0.1				Jan-15		Letters of credit

	Bilateral		0.1				Oct-14		Letters of credit and cash

	ComEd
	Syndicated Revolver		1				Mar-19		Letters of credit and cash

	PECO
	Syndicated Revolver(b)		0.6				May-19		Letters of credit and cash

	BGE
	Syndicated Revolver(b)		0.6				May-19		Letters of credit and cash

	Total		$	8.5



	(a)	Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEd’s, PECO’s and BGE’s service territories. These facilities 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 September 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $9 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.9 billion to support the PHI transaction discussed below, as well as, applicable asset divestitures.

	(b)	Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.
	The Registrants had the following amounts of commercial paper borrowings outstanding as of September 30, 2014 and December 31, 2013:



	Commercial Paper Borrowings		30-Sep-14				31-Dec-13
	Exelon Corporate		$	—			$	—

	Generation		—				—

	ComEd		528				184

	PECO		—				—

	BGE		20				135

Schedule Of Issuance Of Long Term Debt	'
	During the nine months ended September 30, 2014, the following long-term debt was issued:



	Company		Type		Interest Rate			Maturity		Amount		Use of Proceeds
	Exelon		Junior Subordinated Notes		2.5	%		1-Jun-24		$	1,150	Used to finance a portion of the acquisition of PHI and for general corporate purposes

	Generation		Nuclear Fuel Purchase Contract		3.35	%		30-Jun-18		$	38	Used for procurement of uranium

	Generation		ExGen Renewables		LIBOR + 4.250%			February 6, 2021		$	300	Used for general corporate purposes
			I Project Financing(a)
	Generation		ExGen Texas Power Project Financing (a)		LIBOR + 4.750%			September 18, 2021		$	675	Used for general corporate purposes

	Generation		Energy Efficiency Project Financing		4.12	%		December 31, 2015		$	12	Funding to install energy conservation measures in Washington, DC

	Generation		AVSR DOE Project Financing		3.056% - 3.143%			January 5, 2037		$	125	Used for Antelope Valley solar development

	Generation		Nuclear Fuel Purchase Contract		3.25	%		June 30, 2018		$	32	Used for procurement of uranium

	ComEd		First Mortgage Bonds		2.15	%		January 15, 2019		$	300	Used to refinance existing mortgage bonds
			Series 115
	ComEd		First Mortgage Bonds		4.7	%		January 15, 2044		$	350	Used to refinance existing mortgage bonds
			Series 116
	PECO		First and Refunding Mortgage Bonds		4.15	%		October 1, 2044		$	300	Used to refinance existing mortgage bonds and general corporate purposes


	(a) See ExGen Renewables I Project Financing and ExGen Texas Power Project Financing discussed below
Schedule of Long-term Debt Instruments	'
	During the nine months ended September 30, 2013, the following long-term debt was issued:



	Company		Type		Interest Rate			Maturity		Amount		Use of Proceeds
	Generation		Upstream Gas Lending		2.210 - 2.440%			July 22, 2016		$	5	Used to fund Upstream gas activities
			Agreement
	Generation		AVSR DOE Project Financing		2.535 - 3.353 %			January 5, 2037		$	204	Funding for Antelope Valley Solar Development

	Generation		Energy Efficiency Project Financing		4.4	%		August 31, 2014		$	9	Funding to install energy conservation measures in Beckley, West Virginia

	Generation		Continental Wind Senior Secured Notes		6	%		February 28, 2033		$	613	Used for general corporate purposes

	ComEd		First Mortgage Bonds Series 114		4.6	%		August 15, 2043		$	350	Used to repay outstanding commercial paper obligations and for general corporate purposes

	PECO		First and Refunding Mortgage Bonds		1.2	%		October 15, 2016		$	300	Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes

	PECO		First and Refunding Mortgage Bonds		4.8	%		October 15, 2043		$	250	Used to pay at maturity first and refunding mortgage bonds due October 15, 2013 and other general corporate purposes

	BGE		Senior Notes		3.35	%		July 1, 2023		$	300	Used to partially refinance Notes due July 1, 2013 and for general corporate purposes

Retirement and Redemptions of Current and Long-Term Debt	'
	On October 6, 2014, Generation paid down $11 million of principal and interest of its 3.056% - 3.143% AVSR Solar loan.
	During the nine months ended September 30, 2013, the following long-term debt was retired and/or redeemed:



	Company		Type		Interest Rate			Maturity		Amount
	Generation		Kennett Square Capital Lease		7.83	%		September 20, 2020		$	2

	Generation		Solar Revolver		1.930 - 1.950%			7-Jul-14		$	18

	Generation		Clean Horizons Solar Project Financing		2.563	%		7-Sep-30		$	1

	Generation(a)		Series A Junior Subordinated		8.625	%		15-Jun-63		$	450
			Debentures
	ComEd		First Mortgage Bonds Series 92		7.625	%		15-Apr-13		$	125

	ComEd		First Mortgage Bonds Series 94		7.5	%		1-Jul-13		$	127

	BGE		Senior Notes		6.125	%		1-Jul-13		$	400

	BGE		Rate Stabilization Bonds		5.72	%		1-Apr-17		$	33

	During the nine months ended September 30, 2014, the following long-term debt was retired and/or redeemed:



	Company		Type		Interest Rate			Maturity		Amount
	Generation		2003 Senior Notes		5.35	%		January 15, 2014		$	500

	Generation		Pollution Control Loan		4.1	%		July 1, 2014		$	20

	Generation		Continental Wind Project Financing		6	%		February 28, 2033		$	20

	Generation		Kennett Square Capital Lease		7.83	%		September 20, 2020		$	2

	Generation		ExGen Renewables I Project Financing		3mL + 4.25%			6-Feb-21		$	3

	Generation		AVSR DOE Project Financing		2.33% - 3.55%			5-Jan-37		$	4

	Generation		Clean Horizons Solar		2.56	%		7-Sep-30		$	1

	Generation		Sacramento Solar Project Financing		2.56	%		31-Dec-30		$	1

	Generation		Energy Efficiency Project Financing		4.4	%		31-Aug-14		$	9

	ComEd		Mortgage Bonds Series 110		1.63	%		January 15, 2014		$	600

	ComEd		Pollution Control Series 1994C		5.85	%		January 15, 2014		$	17

	BGE		Rate Stabilization Bonds		5.72	%		April 1, 2017		$	35

Income_Taxes_Tables

Income Taxes (Tables)	9 Months Ended
	Sep. 30, 2014
Income Tax Disclosure [Abstract]	'
Effective Income Tax Rate Reconciliation	'


	For the Three Months Ended September 30, 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	1.1			0.7			5			0.1			4.6

	Qualified nuclear decommissioning trust fund income	(0.3	)		(0.4	)		—			—			—

	Domestic production activities deduction	(2.4	)		(3.2	)		—			—			—

	Health care reform legislation	—			—			0.2			—			0.2

	Amortization of investment tax credit, net deferred taxes	(1.0	)		(1.2	)		(0.3	)		(0.1	)		(0.3	)

	Plant basis differences	(0.8	)		—			—			(11.3	)		0.5

	Production tax credits and other credits	(1.9	)		(2.4	)		—			—			—

	Noncontrolling interest	(1.2	)		(1.6	)		—			—			—

	Other	(0.3	)		(1.4	)		0.1			(0.1	)		(1.2	)

	Effective income tax rate	28.2	%		25.5	%		40	%		23.6	%		38.8	%




	For the Nine Months Ended September 30, 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	0.5			(1.4	)		5			0.3			4.9

	Qualified nuclear decommissioning trust fund income	2			3.6			—			—			—

	Domestic production activities deduction	(2.7	)		(4.8	)		—			—			—

	Health care reform legislation	0.1			—			0.2			—			0.2

	Amortization of investment tax credit, net deferred taxes	(1.1	)		(1.7	)		(0.3	)		(0.1	)		(0.3	)
	Plant basis differences	(1.6	)		—			(0.3	)		(11.0	)		0.5

	Production tax credits and other credits	(2.1	)		(3.7	)		—			—			—

	Noncontrolling interest	(1.4	)		(2.6	)		—			—			—

	Other	(1.5	)		(2.5	)		0.1			0.1			(0.5	)

	Effective income tax rate	27.2	%		21.9	%		39.7	%		24.3	%		39.8	%



	For the Three Months Ended September 30, 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	3			2.6			5.4			(0.3	)		5.6

	Qualified nuclear decommissioning trust fund income	3.5			5.3			—			—			—

	Tax exempt income	(0.2	)		(0.3	)		—			—			—

Health care reform legislation	0.1			—			0.4			—			0.2

Amortization of investment tax credit, net deferred taxes	(1.5	)		(2.1	)		(0.4	)		(0.1	)		(0.3	)
Plant basis differences	(0.8	)		—			(0.4	)		(6.9	)		0.1

Production tax credits and other credits	(2.2	)		(3.3	)		—			—			—

Other	0.5			0.1			0.3			(0.1	)		(0.2	)

Effective income tax rate	37.4	%		37.3	%		40.3	%		27.6	%		40.4	%



For the Nine Months Ended September 30, 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	5.3			1.8			5.2			1.9			5.6

Qualified nuclear decommissioning trust fund income	3.2			5.1			—			—			—

Tax exempt income	(0.2	)		(0.3	)		—			—			—

Health care reform legislation	0.1			—			0.9			—			0.2

Amortization of investment tax credit, net deferred taxes	(2.3	)		(3.4	)		(0.8	)		(0.1	)		(0.3	)
Plant basis differences	(1.7	)		—			(1.2	)		(7.3	)		(0.4	)

Production tax credits and other credits	(2.4	)		(3.9	)		—			—			—

Other	0.2			1.1			0.8			—			—

Effective income tax rate	37.2	%		35.4	%		39.9	%		29.5	%		40.1	%

Nuclear_Decommissioning_Tables

Nuclear Decommissioning (Tables) (Exelon Generation Co L L C [Member])	9 Months Ended
	Sep. 30, 2014
Exelon Generation Co L L C [Member]	'
Schedule Of Nuclear Decommissioning [Line Items]	'
Nuclear decommissioning asset retirement obligation rollforward	'
	The following table provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 2013 to September 30, 2014:



	Nuclear decommissioning ARO at December 31, 2013(a)	$	4,855
	Nuclear decommissioning ARO at December 31, 2013(a)	$	4,855
	Consolidation of CENG(b)	1,684
	Consolidation of CENG(b)	1,684
	Accretion expense	243
	Accretion expense	243
	Net decrease due to changes in, and timing of, estimated cash flows	(125		)
		(125		)
	Costs incurred to decommission retired plants	(5		)
	Nuclear decommissioning ARO at September 30, 2014(a)	$	6,652
	Nuclear decommissioning ARO at September 30, 2014(a)	$	6,652


	(a)	Includes $9 million as the current portion of the ARO at September 30, 2014 and December 31, 2013 which is included in Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets.

	(b)	Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
Unrealized Gains (Losses) on nuclear decommissioning trust funds	'
	The following table provides unrealized gains (losses) on NDT funds for the three and nine months ended September 30, 2014 and 2013:



		Exelon and Generation
		Three Months Ended September 30,					Nine Months Ended September 30,
		2014			2013		2014		2013
	Net unrealized gains (losses) on decommissioning trust	$	(107	)	$	103	$	126	$	196
	funds — Regulatory Agreement Units(a)	$	(107	)	$	103	$	126	$	196
	Net unrealized gains (losses) on decommissioning trust	(41		)	46		100		70
	funds — Non-Regulatory Agreement Units(b)(c)	(41		)	46		100		70



	(a)	Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.

	(b)	Excludes $7 million of net unrealized gains and $9 million of net unrealized losses related to the Zion Station pledged assets for the three months ended September 30, 2014 and 2013, respectively, and $27 million of net unrealized gains and $5 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended September 30, 2014 and 2013, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance Sheets.

	(c)	Net unrealized gains (losses) related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Zion Station pledged assets	'
	The following table provides the pledged assets and payable to ZionSolutions, and withdrawals by ZionSolutions at September 30, 2014 and December 31, 2013:



		Exelon and Generation
		30-Sep-14			31-Dec-13
	Carrying value of Zion Station pledged assets	$	365		$	458
	Carrying value of Zion Station pledged assets	$	365		$	458
	Payable to Zion Solutions(a)	334			414
	Payable to Zion Solutions(a)	334			414
	Current portion of payable to Zion Solutions(b)	74			109
	Current portion of payable to Zion Solutions(b)	74			109
	Withdrawals by Zion Solutions to pay decommissioning costs(c)	618			498
		618			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.

	(c)	Cumulative withdrawals since September 1, 2010.

Retirement_Benefits_Tables

Retirement Benefits (Tables)	9 Months Ended
	Sep. 30, 2014
Compensation and Retirement Disclosure [Abstract]	'
Schedule of Defined Benefit Plans Disclosures	'


		Pension Benefits						Other
		Three Months Ended						Postretirement Benefits
		September 30,						Three Months Ended
								September 30,
		2014(a)			2013(a)			2014(a)			2013(a)
	Service cost	$	74		$	79		$	27		$	41

	Interest cost	189			163			42			48

	Expected return on assets	(251		)	(253		)	(39		)	(33		)
	Amortization of:
	Prior service cost (benefit)	3			3			(44		)	(4		)

	Actuarial loss	106			140			15			20

	Settlement charges	—			9			—			—

	Net periodic benefit cost	$	121		$	141		$	1		$	72



		Pension Benefits						Other
		Nine Months Ended						Postretirement Benefits
		September 30,						Nine Months Ended
								September 30,
		2014(b)			2013(b)			2014(b)			2013(b)
	Service cost	$	218		$	238		$	90		$	122

	Interest cost	561			488			144			145

	Expected return on assets	(743		)	(761		)	(115		)	(99		)
	Amortization of:
	Prior service cost (benefit)	10			10			(79		)	(14		)

	Actuarial loss	316			421			35			62

	Settlement charges	—			9			—			—

	Net periodic benefit cost	$	362		$	405		$	75		$	216

	___________

	(a)	For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. CENG is not included in the 2013 amounts.

	(b)	For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.
Schedule Of Pension And Other Postretirement Benefit Costs	'
	The amounts below represent Generation’s, ComEd’s, PECO’s, BGE’s and BSC's allocated portion of the pension and postretirement benefit plan costs, which were included in Capital expenditures and Operating and maintenance expense during the three and nine months ended September 30, 2014 and 2013.



			Three Months Ended September 30,						Nine Months Ended September 30,
	Pension and Other Postretirement Benefit Costs		2014			2013			2014			2013
	Generation(a)		$	54		$	87		$	193		$	259

	ComEd		33			77			129			231

	PECO		7			11			28			32

	BGE		17			14			50			41

	BSC(b)		11			24			37			58

	______________

	(a)	For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.

	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.
Schedule Of Defined Contributions	'
	The following table presents the matching contributions to the savings plans during the three and nine months ended September 30, 2014 and 2013:



			Three Months Ended September 30,						Nine Months Ended September 30,
	Savings Plan Matching Contributions		2014			2013			2014			2013
	Exelon(a)		$	34		$	18		$	82		$	61

	Generation(a)		17			8			41			29

	ComEd		8			6			20			16

	PECO		2			2			6			6

	BGE		3			1			7			5

	BSC(b)		4			1			8			5

	_______________

	(a)	Includes $1 million related to CENG for the three months ended September 30, 2014 and for the period from April 1, 2014 to September, 30 2014. CENG is not included in the 2013 amounts.

	(b)	These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd, PECO or BGE amounts above.

Severance_Tables

Severance (Tables)	9 Months Ended
	Sep. 30, 2014
Restructuring and Related Activities [Abstract]	'
Activity of severance obligations for the corporate restructuring (excluding obligations recorded in equity)	'
	Amounts included in the table below represent the severance liability recorded by Exelon, Generation, ComEd, PECO and BGE for employees of those Registrants and exclude amounts billed through intercompany allocations:



	Nine Months Ended September 30, 2014
	Severance Liability		Exelon			Generation			ComEd		PECO		BGE
	Balance at December 31, 2013		$	53		$	10		$	—	$	—	$	6

	Payments		(36		)	(5		)	—		—		(4		)

	Balance at September 30, 2014		$	17		$	5		$	—	$	—	$	2

	Amounts included in the table below represent the severance liability recorded by Exelon and Generation related to the CENG integration:


	Nine Months Ended September 30, 2014
	Severance Liability		Exelon and Generation
	Balance at December 31, 2013		$	2

	Integration of CENG(a)		19

	Severance charges		2

	Payments		(7		)
	Balance at September 30, 2014		$	16

	_______________

	(a)	Includes the fair value of the CENG integration-related obligation as of April 1, 2014, the date of consolidation. Note this does not include $4 million of severance charges that were paid out prior to consolidation. See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.
Restructuring and Related Costs	'
	For the three and nine months ended September 30, 2014 and 2013, the Registrants recorded the following severance costs associated with these ongoing severance benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:



			Exelon			Generation			ComEd		PECO		BGE
	Three Months Ended
	30-Sep-14		$	(2	)	$	(2	)	$	—	$	—	$	—

	30-Sep-13		$	12		$	11		$	1	$	—	$	—



			Exelon			Generation			ComEd		PECO		BGE
	Nine Months Ended
	30-Sep-14		$	4		$	3		$	1	$	—	$	—

	30-Sep-13		$	14		$	12		$	2	$	—	$	—

Changes_in_Accumulated_Other_C1

Changes in Accumulated Other Comprehensive Income (Tables)	9 Months Ended
	Sep. 30, 2014
Changes in Accumulated Other Comprehensive Income [Abstract]	'
Schedule of Accumulated Other Comprehensive Income (Loss)	'
	The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the nine months ended September 30, 2014 and 2013:



	Nine Months Ended September 30, 2014		Gains				Unrealized				Pension and				Foreign				AOCI of				Total
			and				Gains and				Non-Pension				Currency				Equity
			(Losses)				(Losses) on				Postretirement				Items				Investments
			on Cash				Marketable				Benefit Plan
			Flow Hedges				Securities				Items
	Exelon(a)
	Beginning balance		$	120			$	2			$	(2,260	)		$	(10	)		$	108			$	(2,040	)

	OCI before reclassifications		(14		)		(2		)		240				(6		)		11				229

	Amounts reclassified from AOCI(b)		(78		)		—				91				—				(119		)		(106		)

	Net current-period OCI		(92		)		(2		)		331				(6		)		(108		)		123

	Ending balance		$	28			$	—			$	(1,929	)		$	(16	)		$	—			$	(1,917	)

	Generation(a)
	Beginning balance		$	114			$	2			$	—			$	(10	)		$	108			$	214

	OCI before reclassifications		(8		)		(3		)		—				(6		)		11				(6		)

	Amounts reclassified from AOCI(b)		(78		)		—				—				—				(119		)		(197		)

	Net current-period OCI		(86		)		(3		)		—				(6		)		(108		)		(203		)

	Ending balance		$	28			$	(1	)		$	—			$	(16	)		$	—			$	11

	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 tables following changes in accumulated other comprehensive income tables for details about these reclassifications.



	Nine Months Ended September 30, 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		25				(1		)		73				(5		)		46				138

	Amounts reclassified from AOCI(b)		(194		)		—				157				—				5				(32		)

	Net current-period OCI		(169		)		(1		)		230				(5		)		51				106

Ending balance		$	199			$	(1	)		$	(2,907	)		$	(5	)		$	53			$	(2,661	)

Generation(a)
Beginning balance		$	512			$	—			$	—			$	—			$	1			$	513

OCI before reclassifications		12				(1		)		—				(5		)		47				53

Amounts reclassified from AOCI(b)		(328		)		—				—				—				5				(323		)

Net current-period OCI		(316		)		(1		)		—				(5		)		52				(270		)

Ending balance		$	196			$	(1	)		$	—			$	(5	)		$	53			$	243

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 tables following changes in accumulated other comprehensive income tables for details about these reclassifications.
Reclassification out of Accumulated Other Comprehensive Income	'
	The following tables present amounts reclassified out of AOCI to Net Income for Exelon and Generation during the three and nine months ended September 30, 2014 and 2013.

	Three Months Ended September 30, 2014


	Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
											where Net Income is presented
			Exelon				Generation
	Gains on cash flow hedges
	Energy related hedges		$	28			$	28			Operating revenues

			28				28				Total before tax

			(12		)		(12		)		Tax (expense)
			$	16			$	16			Net of tax

	Amortization of pension and other postretirement benefit plan items
	Prior service costs		$	19			$	—			(b)

	Actuarial losses		(61		)		—				(b)

			(42		)		—				Total before tax

			16				—				Tax benefit

			$	(26	)		$	—			Net of tax

	Equity investments
	Sale of equity method investment		$	5			$	5			Other, net

			5				5				Total before tax

			(2		)		(2		)		Tax (expense)
			$	3			$	3			Net of tax

	Total Reclassifications for the period		$	(7	)		$	19			Net of Tax


	Nine Months Ended September 30, 2014


	Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
											where Net Income is presented
			Exelon				Generation
	Gains on cash flow hedges
	Energy related hedges		$	130			$	130			Operating revenues

			130				130				Total before tax

			(52		)		(52		)		Tax (expense)
			$	78			$	78			Net of tax

	Amortization of pension and other postretirement benefit plan items
	Prior service costs		$	29			$	—			(b)

	Actuarial losses		(178		)		—				(b)

			(149		)		—				Total before tax

			58				—				Tax benefit

			$	(91	)		$	—			Net of tax

Equity investments
Sale of equity method investment		$	5			$	5			Other, net

Reversal of CENG equity method AOCI		193				193				Gain on consolidation of CENG

		198				198				Total before tax

		(79		)		(79		)		Tax (expense)
		$	119			$	119			Net of tax

Total reclassifications for the period		$	106			$	197			Net of Tax

Three Months Ended September 30, 2013


Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
										where Net Income is presented
		Exelon				Generation
Gains on cash flow hedges
Energy related hedges		$	84			$	84			Operating revenues

Other cash flow hedges		(1		)		(1		)		Interest expense
		83				83				Total before tax

		(35		)		(33		)		Tax (expense)
		$	48			$	50			Net of tax

Amortization of pension and other postretirement benefit plan items
Actuarial losses		$	(92	)		$	—			(b)

Deferred compensation unit plan		(1		)		—				(c)

		(93		)		—				Total before tax

		37				—				Tax benefit

		$	(56	)		$	—			Net of tax

Equity investments
Capital Activity		$	—			$	—			Equity in losses of unconsolidated affiliates

		—				—				Total before tax

		—				—				Tax benefit

		$	—			$	—			Net of tax

Total Reclassifications for the period		$	(8	)		$	50			Net of Tax


Nine Months Ended September 30, 2013


Details about AOCI components		Items reclassified out of AOCI(a)								Affected line item in the statement
										where Net Income is presented
		Exelon				Generation
Gains on cash flow hedges
Energy related hedges		$	324			$	543			Operating revenues

Other cash flow hedges		(2		)		—				Interest (expense) or benefit

		322				543				Total before tax

		(128		)		(215		)		Tax (expense)
		$	194			$	328			Net of tax

Amortization of pension and other postretirement benefit plan items
Prior service costs		$	(1	)		$	—			(b)

Actuarial losses		(257		)		—				(b)

Deferred compensation unit plan		(1		)		—				(c)

		(259		)		—				Total before tax

		102				—				Tax benefit

		$	(157	)		$	—			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 for the period		$	32			$	323			Net of Tax

____________

(a)	All amounts are net of tax. 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 13— Retirement Benefits for additional details).

(c)	Amortization of deferred compensation unit is allocated to capital and operating and maintenance expense.
Schedule Of Other Comprehensive Income Loss Tax	'
	The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the three and nine months ended September 30, 2014 and 2013:



		Three Months Ended September 30,								Nine Months Ended September 30,
		2014				2013				2014				2013
	Exelon
	Pension and non-pension postretirement benefit plans:
	Prior service benefit reclassified to periodic benefit cost	$	8			$	—			11				$	—

	Actuarial gain (loss) reclassified to periodic cost	(24		)		33				(69		)		97

	Pension and non-pension postretirement benefit plans valuation adjustment	5				(6		)		(153		)		44

	Change in unrealized gain (loss) on cash flow hedges	15				(35		)		62				(109		)

	Change in unrealized income on equity investments	3				9				73				32

	Deferred compensation unit valuation adjustment	—				—				—				6

	Change in unrealized loss on marketable securities	1				—				(1		)		—

	Total	$	8			$	1			$	(77	)		$	70


	Generation
	Change in unrealized gain (loss) on cash flow hedges	$	13			$	(36	)		$	57			$	(209	)

	Change in unrealized income on equity investments	3				9				73				32

	Change in marketable securities	1				—				(1		)		—

	Total	$	17			$	(27	)		$	129			$	(177	)

Earnings_Per_Share_and_Equity_1

Earnings Per Share and Equity (Tables)	9 Months Ended
	Sep. 30, 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 these stock options, performance share awards and restricted stock on the weighted average number of shares outstanding (in millions) used in calculating diluted earnings per share:


		Three Months Ended September 30,				Nine Months Ended September 30,
		2014		2013		2014		2013
	Net income attributable to common shareholders	$	993	$	738	$	1,604	$	1,224

	Average common shares outstanding — basic	861		857		860		856

	Potentially dilutive effect of stock options, performance share awards and restricted stock	2		3		3		4

	Average common shares outstanding — diluted	863		860		863		860

Commitments_and_Contingencies_1

Commitments and Contingencies (Tables)	9 Months Ended
Commitments and Contingencies (Tables)	Sep. 30, 2014
Commitments And Contingencies Tables Disclosure [Line Items]	'
Energy Commitments	'
	As of September 30, 2014, Generation’s commitments relating to its purchases from unaffiliated utilities and others of energy, capacity, transmission rights and RECs, are as indicated in the following table:



		Net Capacity				REC			Transmission			Total
		Purchases(a)				Purchases(b)			Rights
									Purchases(c)
	2014	$	91			$	7		$	6		$	104
	2014	$	91			$	7		$	6		$	104
	2015	396				162			20			578
	2015	396				162			20			578
	2016	269				166			15			450
	2016	269				166			15			450
	2017	208				80			15			303
	2017	208				80			15			303
	2018	98				15			16			129
	2018	98				15			16			129
	Thereafter	389				4			51			444
	Thereafter	389				4			51			444
	Total	$	1,451			$	434		$	123		$	2,008
	Total	$	1,451			$	434		$	123		$	2,008

	____________________

	(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 September 30, 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 September 30, 2014, capacity offsets were $23 million, $132, million $133 million, $136, million, $137 million, and $729 million for years 2014, 2015, 2016, 2017, 2018, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.

	(b)	The table excludes renewable energy purchases that are contingent in nature.

	(c)	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
Utility Energy Purchase Commitments	'
	ComEd’s, PECO’s and BGE’s electric supply procurement, curtailment services, REC and AEC purchase commitments, as applicable, as of September 30, 2014 are as follows:



						Expiration within
		Total				2014			2015			2016			2017			2018		2019
		Total				2014			2015			2016			2017			2018		and beyond
	ComEd
	Electric supply procurement(a)	$	731			$	111		$	329		$	151		$	140		$	—	$	—
	Electric supply procurement(a)	$	731			$	111		$	329		$	151		$	140		$	—	$	—
	Renewable energy and RECs(b)	1,538				22			73			76			77			78		1,212
	Renewable energy and RECs(b)	1,538				22			73			76			77			78		1,212
	PECO
	Electric supply procurement(c)	498				193			305			—			—			—		—
	Electric supply procurement(c)	498				193			305			—			—			—		—
	AECs(d)	13				1			2			2			2			2		4
	AECs(d)	13				1			2			2			2			2		4
	BGE
	Electric supply procurement(e)	1,055				198			621			236			—			—		—
	Electric supply procurement(e)	1,055				198			621			236			—			—		—
	Curtailment services(f)	125				10			40			34			29			12		—
	Curtailment services(f)	125				10			40			34			29			12		—
	___________________

	(a)	ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of September 30, 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 2014 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 — Regulatory Matters for additional information.

	(d)	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See Note 5 — Regulatory Matters for additional information.

	(e)	BGE entered into various contracts for the procurement of electricity that expire between 2014 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 5 — 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 5 —Regulatory Matters for additional information.
Fuel Purchase Commitments	'
	As of September 30, 2014, these net commitments were as follows:



						Expiration within
		Total				2014			2015			2016			2017			2018		2019
		Total				2014			2015			2016			2017			2018		and beyond
	Generation	$	9,636			$	351		$	1,512		$	1,226		$	1,271		$	1,003	$	4,273
	Generation	$	9,636			$	351		$	1,512		$	1,226		$	1,271		$	1,003	$	4,273
	PECO	387				57			120			94			35			15		66
	PECO	387				57			120			94			35			15		66
	BGE	624				40			115			81			64			53		271
	BGE	624				40			115			81			64			53		271
Other Purchase Obligation	'
	The Registrants’ other purchase obligations as of September 30, 2014, which primarily represent commitments for services, materials and information technology, are as follows:



						Expiration within
		Total				2014			2015			2016			2017			2018		2019
		Total				2014			2015			2016			2017			2018		and beyond
	Exelon	$	917			$	103		$	324		$	180		$	151		$	36	$	123
	Exelon	$	917			$	103		$	324		$	180		$	151		$	36	$	123
	Generation(a)(b)	493				80			182			57			43			30		101
	Generation(a)(b)	493				80			182			57			43			30		101
	ComEd(c)	92				13			38			16			5			5		15
	ComEd(c)	92				13			38			16			5			5		15
	PECO(c)	29				7			11			2			1			1		7
	PECO(c)	29				7			11			2			1			1		7
	BGE(c)	302				2			93			105			102			—		—
	BGE(c)	302				2			93			105			102			—		—

	________________
	(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 5 — Regulatory Matters for additional information.
Commercial Commitments	'
	The Registrants’ commercial commitments as of September 30, 2014, representing commitments potentially triggered by future events were as follows:



		Exelon				Generation			ComEd			PECO			BGE
	Letters of credit (non-debt)(a)	$	1,021			$	973		$	20		$	22		$	1
	Letters of credit (non-debt)(a)	$	1,021			$	973		$	20		$	22		$	1
	Guarantees	4,902			(b)	1,604		(c)	206		(d)	181		(e)	259		(f)
	Guarantees	4,902			(b)	1,604		(c)	206		(d)	181		(e)	259		(f)
	Nuclear insurance premiums(g)	3,559				3,559			—			—			—
	Nuclear insurance premiums(g)	3,559				3,559			—			—			—
	Underwriters discount(h)	60				—			—			—			—
	Underwriters discount(h)	60				—			—			—			—
	Total commercial commitments	$	9,542			$	6,136		$	226		$	203		$	260
	Total commercial commitments	$	9,542			$	6,136		$	226		$	203		$	260
	___________________

	(a)	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.

	(b)	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $467 million at September 30, 2014, which represents the total amount Exelon could be required to fund based on September 30, 2014 market prices.

	(c)	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $205 million at September 30, 2014, which represents the total amount Generation could be required to fund based on September 30, 2014 market prices.

	(d)	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.

	(e)	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.

	(f)	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

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

	(h)	Represents the underwriters discount for Exelon’s forward equity transaction. See Note 16 — Common Stock of the Combined Notes to Consolidated Financial Statements for further details of the equity securities offering.
Accrued environmental liabilities	'
	As of September 30, 2014 and December 31, 2013, the Registrants had accrued the following undiscounted amounts for environmental liabilities in other current liabilities and other deferred credits and other liabilities within their respective Consolidated Balance Sheets:



	30-Sep-14	Total Environmental				Portion of Total Related to
		Investigation and				MGP Investigation and
		Remediation Reserve				Remediation
	Exelon	$	342			$	280
	Exelon	$	342			$	280
	Generation	55				—
	Generation	55				—
	ComEd	241				237
	ComEd	241				237
	PECO	45				43
	PECO	45				43
	BGE	1				—
	BGE	1				—



	December 31, 2013	Total Environmental				Portion of Total Related to
		Investigation and				MGP Investigation and
		Remediation Reserve				Remediation
	Exelon	$	338			$	273
	Exelon	$	338			$	273
	Generation	56				—
	Generation	56				—
	ComEd	234				229
	ComEd	234				229
	PECO	47				44
	PECO	47				44
	BGE	1				—
	BGE	1				—
Exelon Generation Co L L C [Member] \| Equity Method Investments [Member]	'
Commitments And Contingencies Tables Disclosure [Line Items]	'
Other Commitments	'
	As of September 30, 2014, Generation’s estimated commitment relating to its equity purchase agreements, including the in-kind services contributions, is anticipated to be as follows:



			Total
		2014	$	27
		2014	$	27
		2015	86
		2015	86
		2016	34
		2016	34
		2017	20
		2017	20
		2018	15
		2018	15
		Total	$	182
		Total	$	182

Supplemental_Financial_Informa1

Supplemental Financial Information (Tables)	9 Months Ended
	Sep. 30, 2014
Supplemental Financial Information [Abstract]	'
Components of non-operating income and expenses	'
	The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the three and nine months ended September 30, 2014 and 2013:


	Three Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust funds(a)
	Regulatory agreement units	$	55			$	55			$	—			$	—			$	—

	Non-regulatory agreement units	39				39				—				—				—

	Net unrealized losses on decommissioning trust funds
	Regulatory agreement units	(107		)		(107		)		—				—				—

	Non-regulatory agreement units	(41		)		(41		)		—				—				—

	Net unrealized gains on pledged assets
	Zion Station decommissioning	7				7				—				—				—

	Regulatory offset to decommissioning trust fund-related	29				29				—				—				—
	activities(b)
	Total decommissioning-related activities	(18		)		(18		)		—				—				—

	Investment income	—				—				—				—				1			(c)

	Long-term lease income	4				—				—				—				—

	Interest income related to uncertain income tax positions	25				27				—				—				—

	AFUDC — Equity	5				—				—				2				3

	Gain on sale of assets	338				338				—				—				—

	Other	—				(5		)		4				—				—

	Other, net	$	354			$	342			$	4			$	2			$	4




	Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Other, Net
	Decommissioning-related activities:
	Net realized income on decommissioning trust funds(a)
	Regulatory agreement units	$	167			$	167			$	—			$	—			$	—

	Non-regulatory agreement units	102				102				—				—				—

	Net unrealized gains on decommissioning trust funds
	Regulatory agreement units	126				126				—				—				—

	Non-regulatory agreement units	100				100				—				—				—

	Net unrealized gains on pledged assets
	Zion Station decommissioning	27				27				—				—				—

	Regulatory offset to decommissioning trust fund-related	(270		)		(270		)		—				—				—
	activities(b)
	Total decommissioning-related activities	252				252				—				—				—

	Investment income (expense)	1				1				—				(1		)		5			(c)

	Long-term lease income	20				—				—				—				—

Interest income related to uncertain income tax positions	41				53				—				—				—

AFUDC — Equity	17				—				3				5				9

Gain on sale of assets	356				355				1				—				—

Other	15				—				10				1				—

Other, net	$	702			$	661			$	14			$	5			$	14




Three Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds(a)
Regulatory agreement units	$	138			$	138			$	—			$	—			$	—

Non-regulatory agreement units	35				35				—				—				—

Net unrealized gains on decommissioning trust funds
Regulatory agreement units	103				103				—				—				—

Non-regulatory agreement units	46				46				—				—				—

Net unrealized losses on pledged assets
Zion Station decommissioning	(9		)		(9		)		—				—				—

Regulatory offset to decommissioning trust fund-related	(189		)		(189		)		—				—				—
activities(b)
Total decommissioning-related activities	124				124				—				—				—

Investment income	1				—				—				—				2			(c)

Long-term lease income	7				—				—				—				—

AFUDC — Equity	4				—				2				1				1

Gain on sale of assets	10				8				2				—				—

Other	9				2				3				—				1

Other, net	$	155			$	134			$	7			$	1			$	4




Nine Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds(a)
Regulatory agreement units	$	221			$	221			$	—			$	—			$	—

Non-regulatory agreement units	65				65				—				—				—

Net unrealized gains on decommissioning trust funds
Regulatory agreement units	196				196				—				—				—

Non-regulatory agreement units	70				70				—				—				—

Net unrealized losses on pledged assets
Zion Station decommissioning	(5		)		(5		)		—				—				—

Regulatory offset to decommissioning trust fund-related	(338		)		(338		)		—				—				—
activities(b)
Total decommissioning-related activities	209				209				—				—				—

Investment income (expense)	6				(1		)		—				(1		)		7			(c)

Long-term lease income	20				—				—				—				—

Interest income related to uncertain income tax positions	24				3				—				1				—

AFUDC — Equity	16				—				8				3				5

Gain on sale of assets	17				13				2				—				—

Other	19				5				8				1				1

Other, net	$	311			$	229			$	18			$	4			$	13

________

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

(b)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those units. See Note 15 — Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

(c)	Relates to the cash return on BGE’s rate stabilization deferral. See Note 5 — 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 nine months ended September 30, 2014 and 2013:



	Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Depreciation, amortization, accretion and depletion
	Property, plant and equipment	$	1,549			$	686			$	438			$	169			$	215

	Regulatory assets	150				—				83				7				60

	Amortization of intangible assets, net	33				33				—				—				—

	Amortization of energy contract assets and liabilities(a)	83				93				—				—				—

	Nuclear fuel(b)	790				790				—				—				—

	ARO accretion(c)	251				251				—				—				—

	Total depreciation, amortization, accretion and depletion	$	2,856			$	1,853			$	521			$	176			$	275




	Nine Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
	Depreciation, amortization, accretion and depletion
	Property, plant and equipment	$	1,420			$	610			$	413			$	164			$	194

	Regulatory assets	153				—				88				7				58

	Amortization of intangible assets, net	33				33				—				—				—

	Amortization of energy contract assets and liabilities(a)	342				398				—				—				—

	Nuclear fuel(b)	689				689				—				—				—

	ARO accretion(c)	207				207				—				—				—

	Total depreciation, amortization, accretion and depletion	$	2,844			$	1,937			$	501			$	171			$	252

	_________

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

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

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


	Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	437			$	193			$	129			$	28			$	50

	Loss from equity method investments	20				20				—				—				—

	Provision for uncollectible accounts	96				10				9				39				38

	Stock-based compensation costs	111				—				—				—				—

	Other decommissioning-related activity(a)	(102		)		(102		)		—				—				—

	Energy-related options(b)	92				92				—				—				—

	Amortization of regulatory asset related to debt costs	8				—				6				2				—

Amortization of rate stabilization deferral	50				—				—				—				50

Amortization of debt fair value adjustment	(45		)		(17		)		—				—				—

Discrete impacts of EIMA(c)	(32		)		—				(32		)		—				—

Amortization of debt costs	36				9				4				2				2

Merger commitments(d)	44				44				—				—				—

Other	(17		)		2				—				(1		)		(11		)

Total other non-cash operating activities	$	698			$	251			$	116			$	70			$	129

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	53			$	—			$	63			$	(14	)		$	6

Other regulatory assets and liabilities	(63		)		—				(14		)		(14		)		(89		)

Cash deposits(f)	(280		)		(280		)		—				—				—

Other current assets	(78		)		24				(9		)		(48		)	(h)	25

Other noncurrent assets and liabilities	(168		)		(111		)		22				1				(9		)

Total changes in other assets and liabilities	$	(536	)		$	(367	)		$	62			$	(75	)		$	(67	)

Non-cash investing and financing activities:
Fair value of net assets recorded upon CENG consolidation(j)	$	(3,400	)		$	(3,400	)		$	—			$	—			$	—

Issuance of equity units(k)	131				—				—				—				—

Uranium procurement(l)	70				70				—				—				—

Indemnification of like-kind exchange position(m)	—				—				4				—				—

Total non-cash investing and financing activities:	$	(3,199	)		$	(3,330	)		$	4			$	—			$	—

Cash Flow Supplemental Disclosures	'


	Nine Months Ended September 30, 2014	Exelon				Generation				ComEd				PECO				BGE
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	437			$	193			$	129			$	28			$	50

	Loss from equity method investments	20				20				—				—				—

	Provision for uncollectible accounts	96				10				9				39				38

	Stock-based compensation costs	111				—				—				—				—

	Other decommissioning-related activity(a)	(102		)		(102		)		—				—				—

	Energy-related options(b)	92				92				—				—				—

	Amortization of regulatory asset related to debt costs	8				—				6				2				—

	Amortization of rate stabilization deferral	50				—				—				—				50

	Amortization of debt fair value adjustment	(45		)		(17		)		—				—				—

	Discrete impacts of EIMA(c)	(32		)		—				(32		)		—				—

	Amortization of debt costs	36				9				4				2				2

	Merger commitments(d)	44				44				—				—				—

	Other	(17		)		2				—				(1		)		(11		)

	Total other non-cash operating activities	$	698			$	251			$	116			$	70			$	129

	Changes in other assets and liabilities:
	Under/over-recovered energy and transmission costs	$	53			$	—			$	63			$	(14	)		$	6

	Other regulatory assets and liabilities	(63		)		—				(14		)		(14		)		(89		)

	Cash deposits(f)	(280		)		(280		)		—				—				—

	Other current assets	(78		)		24				(9		)		(48		)	(h)	25

	Other noncurrent assets and liabilities	(168		)		(111		)		22				1				(9		)

	Total changes in other assets and liabilities	$	(536	)		$	(367	)		$	62			$	(75	)		$	(67	)

	Non-cash investing and financing activities:
	Fair value of net assets recorded upon CENG consolidation(j)	$	(3,400	)		$	(3,400	)		$	—			$	—			$	—

	Issuance of equity units(k)	131				—				—				—				—

	Uranium procurement(l)	70				70				—				—				—

	Indemnification of like-kind exchange position(m)	—				—				4				—				—

	Total non-cash investing and financing activities:	$	(3,199	)		$	(3,330	)		$	4			$	—			$	—




	Nine Months Ended September 30, 2013	Exelon				Generation				ComEd				PECO				BGE
	Other non-cash operating activities:
	Pension and non-pension postretirement benefit costs	$	621			$	259			$	231			$	32			$	41

Gain from equity method investments	(7		)		(7		)		—				—				—

Provision for uncollectible accounts	83				16				(6		)		48				25

Stock-based compensation costs	99				—				—				—				—

Other decommissioning-related activity(a)	(110		)		(110		)		—				—				—

Energy-related options(b)	87				87				—				—				—

Amortization of regulatory asset related to debt costs	9				—				7				2				—

Amortization of rate stabilization deferral	49				—				—				—				49

Amortization of debt fair value adjustment	(28		)		(28		)		—				—				—

Discrete impacts from EIMA(c)	(206		)		—				(206		)		—				—

Amortization of debt costs	13				7				3				2				1

Merger integration costs(e)	(6		)		—				—				—				(6		)

Increase in inventory reserve	7				7				—				—				—

Other	(27		)		—				(3		)		—				(5		)

Total other non-cash operating activities	$	584			$	231			$	26			$	84			$	105

Changes in other assets and liabilities:
Under/over-recovered energy and transmission costs	$	(47	)		$	—			$	(63	)		$	(10	)		$	26

Other regulatory assets and liabilities	(50		)		—				(35		)		—				(85		)

Settlement of interest rate swaps (g)	26				—				—				—				—

Other current assets	(169		)		(123		)		47				(31		)	(h)	(35		)

Other noncurrent assets and liabilities	205				(40		)		261			(i)	(6		)		(25		)

Total changes in other assets and liabilities	$	(35	)		$	(163	)		$	210			$	(47	)		$	(119	)

Non-cash investing and financing activities:
Consolidated VIE dividend to noncontrolling interest	$	63			$	63			$	—			$	—			$	—

Indemnification of like-kind exchange position(m)	—				—				175				—				—

Total non-cash investing and financing activities	$	63			$	63			$	175			$	—			$	—

____________

(a)	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

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

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

(d)	Reflects the establishment of a reserve related to a MDPSC merger commitment for generation development. See Note 18 - Commitments and Contingencies for additional information.

(e)	Relates to integration costs to achieve distribution synergies related to the Constellation merger transaction that were reclassified to a regulatory asset. See Note 5 — Regulatory Matters for more information.

(f)	Relates primarily to cash deposits made to ISO's/RTO's.

(g)	Relates to settlement of forward starting interest rate swaps that Exelon entered into in anticipation of Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013. See Note 9 — Derivative Financial Instruments for more information on interest rate swaps.

(h)	Relates primarily to prepaid utility taxes.

(i)	Relates primarily to interest payable related to like-kind exchange tax position. See Note 11 — Income Taxes for discussion of the like-kind exchange tax position.

(j)	See Note 6 — Investment in Constellation Energy Nuclear Group, LLC for additional information.

(k)	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 16 — Common Stock for additional information.

(l)	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.

(m)	See Note 11 — Income Taxes for discussion of the like-kind exchange tax position.
Supplemental Balance Sheet Disclosures	'
	The following tables provide additional information about assets and liabilities of the Registrants as of September 30, 2014 and December 31, 2013.



	30-Sep-14	Exelon				Generation				ComEd				PECO				BGE
	Property, plant and equipment:
	Accumulated depreciation and amortization	$	14,932		(a)	$	7,868		(a)	$	3,370			$	2,972			$	2,825

	Accounts receivable:
	Allowance for uncollectible accounts	$	291			$	55			$	80			$	115			$	41



	31-Dec-13	Exelon				Generation				ComEd				PECO				BGE
	Property, plant and equipment:
	Accumulated depreciation and amortization	$	13,713		(b)	$	7,034		(b)	$	3,184			$	2,935			$	2,702

	Accounts receivable:
	Allowance for uncollectible accounts	$	272			$	57			$	62			$	107			$	46

	_______

	(a)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,729 million.

	(b)	Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2014
Segment Reporting Information [Line Items]	'
Analysis and reconciliation of reportable segment information	'
	An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three months ended September 30, 2014 and 2013 is as follows:
	Three Months Ended September 30, 2014 and 2013



		Generation(a)			ComEd				PECO			BGE			Other(b)				Intersegment Eliminations			Exelon
	Total revenues(c):
	2014	$	4,412		$	1,222			$	693		$	697		$	305			$	(417	)	$	6,912

	2013	4,255			1,156				728			737			294				(668		)	6,502

	Intersegment revenues(d):
	2014	$	112		$	1			$	—		$	3		$	302			$	(418	)	$	—

	2013	373			1				1			2			294				(669		)	2

	Net income (loss):
	2014	$	849		$	126			$	81		$	49		$	(31	)		$	—		$	1,074

	2013	485			126				92			53			(20		)		—			736

	Total assets:
	September 30, 2014	$	45,019		$	24,845			$	10,051		$	7,915		$	8,713			$	(11,279	)	$	85,264

	December 31, 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. Intersegment revenues for Generation for the three months ended September 30, 2014 include revenue from sales to PECO of $28 million and sales to BGE of $83 million in the Mid-Atlantic region, and sales to ComEd of $1 million in the Midwest region. For the three months ended September 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $82 million and sales to BGE of $144 million in the Mid-Atlantic region, and sales to ComEd of $143 million in the Midwest region.

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

	(c)	For the three months ended September 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended September 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended September 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended September 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.

	(d)	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with 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	'


		2014										2013
		Revenues			Intersegment				Total			Revenues			Intersegment				Total
		from external			revenues				Revenues			from external			revenues				Revenues
		customers(a)										customers(a)
	Mid-Atlantic(b)	$	3,998		$	(14	)		$	3,984		$	3,932		$	11			$	3,943

	Midwest	3,302			11				3,313			3,274			(3		)		3,271

	New England	1,028			5				1,033			942			(9		)		933

	New York(b)	614			(1		)		613			547			(20		)		527

	ERCOT	743			(2		)		741			1,042			(8		)		1,034

	Other Regions(c)	1,027			(4		)		1,023			708			29				737

	Total Revenues for Reportable Segements	10,712			(5		)		10,707			10,445			—				10,445

	Other(d)	1,879			5				1,884			1,413			—				1,413

	Total Generation Consolidated Operating Revenues	$	12,591		$	—			$	12,591		$	11,858		$	—			$	11,858

	__________

	(a)	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.

	(b)	Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through September 30, 2014.

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

	(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $203 million decrease to revenues and $603 million decrease to revenues, for the nine months ended September 30, 2014 and 2013, respectively, and elimination of intersegment revenues.


		Generation(a)(b)			ComEd				PECO			BGE			Other(c)				Intersegment			Exelon
																			Eliminations
	Total revenues(d):
	2014	$	12,591		$	3,484			$	2,343		$	2,404		$	924			$	(1,573	)	$	20,173

	2013	11,858			3,395				2,295			2,271			909				(2,003		)	18,725

	Intersegment revenues(e):
	2014	$	630		$	2			$	1		$	21		$	920			$	(1,574	)	$	—

	2013	1,083			2				1			10			909				(2,003		)	2

	Net income (loss):
	2014	$	1,037		$	335			$	255		$	156		$	(58	)		$	—		$	1,725

	2013	795			140				292			160			(152		)		—			1,235

	__________

	(a)	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended September 30, 2014 include revenue from sales to PECO of $165 million and sales to BGE of $290 million in the Mid-Atlantic region, and sales to ComEd of $175 million in the Midwest. For the nine months ended September 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $321 million and sales to BGE of $356 million in the Mid-Atlantic region, and sales to ComEd of $409 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 include activity recorded at CENG from April 1, 2014, the date of integration, through September 30, 2014.

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

	(d)	For the nine months ended September 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended September 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended September 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended September 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.

	(e)	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
Exelon Generation Co L L C [Member]	'
Segment Reporting Information [Line Items]	'
Analysis and reconciliation of reportable segment revenues for Generation	'


		2014										2013
		Revenues			Intersegment				Total			Revenues			Intersegment				Total
		from external			revenues				Revenues			from external			revenues				Revenues
		customers(a)										customers(a)
	Mid-Atlantic	$	1,285		$	4			$	1,289		$	1,381		$	10			$	1,391

	Midwest	1,062			(1		)		1,061			1,018			(5		)		1,013

	New England	272			—				272			341			(1		)		340

	New York	230			2				232			198			(14		)		184

	ERCOT	303			(1		)		302			430			(3		)		427

	Other Regions(b)	381			(6		)		375			278			(7		)		271

	Total Revenues for Reportable Segments	3,533			(2		)		3,531			3,646			(20		)		3,626

	Other(c)	879			2				881			609			20				629

	Total Generation Consolidated Operating Revenues	$	4,412		$	—			$	4,412		$	4,255		$	—			$	4,255

	__________

	(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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $22 million decrease to revenues and $125 million decrease to revenues for the three months ended September 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.
	Generation total revenues net of purchased power and fuel expense (three months ended September 30,):



		2014										2013
		RNF			Intersegment RNF				Total RNF			RNF			Intersegment RNF				Total RNF
		from external										from external
		customers(a)										customers(a)
	Mid-Atlantic	$	921		$	14			$	935		$	857		$	7			$	864

	Midwest	722			(6		)		716			606			(5		)		601

	New England	120			(30		)		90			52			10				62

	New York	176			10				186			29			(38		)		(9		)

	ERCOT	186			(77		)		109			222			(78		)		144

	Other Regions(b)	157			(89		)		68			116			(75		)		41

	Total Revenues net of purchased power and fuel for Reportable Segments	2,282			(178		)		2,104			1,882			(179		)		1,703

	Other(c)	250			178				428			194			179				373

	Total Generation Revenues net of purchased power and fuel expense	$	2,532		$	—			$	2,532		$	2,076		$	—			$	2,076


	__________

	(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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $15 million increase to RNF and $44 million decrease to RNF for the three months ended September 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.


	2014										2013
	RNF			Intersegment				Total			RNF			Intersegment				Total
	from external			RNF				RNF			from external			RNF				RNF
	customers(a)										customers(a)
Mid-Atlantic(b)	$	2,610		$	(60	)		$	2,550		$	2,477		$	(2	)		$	2,475

Midwest	1,856			21				1,877			2,002			(1		)		2,001

New England	362			(72		)		290			156			(14		)		142

New York(b)	289			24				313			14			(31		)		(17		)

ERCOT	457			(207		)		250			477			(120		)		357

Other Regions(c)	465			(216		)		249			238			(91		)		147

Total Revenues net of purchased power and fuel expense for Reportable Segments	6,039			(510		)		5,529			5,364			(259		)		5,105

Other(d)	(519		)	510				(9		)	200			259				459

Total Generation Revenues net of purchased power and fuel expense	$	5,520		$	—			$	5,520		$	5,564		$	—			$	5,564

__________

(a)	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.

(b)	Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through September 30, 2014.

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

(d)	Other represents activities not allocated to a region. See text above for a description of included activities. Also includes amortization of intangible assets related to commodity contracts recorded at fair value at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $78 million decrease to RNF and $386 million decrease to RNF for the nine months ended September 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.

Basis_of_Presentation_Narrativ

Basis of Presentation - Narrative (Details) (USD $)	3 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Mar. 31, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Total interest expense to affiliates, net	$11	'	$6	$31	$19
Pretax decrease in operating and maintenance expense	-1,982	-1	-1,735	-6,005	-5,391
Pretax increase in taxes other than income	306	'	277	887	825
Scenario Adjustment [Member]	'	'	'	'	'
Purchased power and fuel from affiliates	'	'	339	'	944
Exelon Generation Co L L C [Member]	'	'	'	'	'
Purchased power and fuel from affiliates	59	'	342	476	953
Total interest expense to affiliates, net	12	'	13	37	47
Pretax decrease in operating and maintenance expense	-1,114	'	-936	-3,308	-2,943
Pretax increase in taxes other than income	127	'	98	350	292
Exelon Generation Co L L C [Member] \| Scenario Adjustment [Member]	'	'	'	'	'
Purchased power and fuel from affiliates	'	'	342	'	953
Total interest expense to affiliates, net	'	'	13	'	47
Baltimore Gas and Electric Company [Member]	'	'	'	'	'
Total interest expense to affiliates, net	4	'	4	12	12
Purchased power and fuel	216	'	202	808	703
Pretax decrease in operating and maintenance expense	-142	'	-125	-468	-391
Pretax increase in taxes other than income	55	'	53	168	162
Baltimore Gas and Electric Company [Member] \| Scenario Adjustment [Member]	'	'	'	'	'
Total interest expense to affiliates, net	'	'	$4	'	$12

Variable_Interest_Entities_Nar

Variable Interest Entities - Narrative (Details) (USD $)

9 Months Ended

0 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

Sep. 30, 2014

Aug. 18, 2014

Dec. 31, 2013

Sep. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Apr. 01, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Apr. 01, 2014

VIE

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Constellation Energy Nuclear Group [Member]

Financial Guarantee [Member]

Payment Guarantee [Member]

Variable Interest Entity, Primary Beneficiary [Member]

RSB Bond Co LLC [Member]

Exelon Generation Co L L C [Member]

Constellation Energy Nuclear Group [Member]

Equity Method Investment Variable Interest Entities [Member]

Exelon Generation Co L L C [Member]

Variable Interest Entity [Line Items]

Number of Variable Interest Entities not consolidated by equity holders

Number Of Variable Interest Entities Consolidated

Equity Method Investment, Ownership Percentage

67.00%

50.01%

Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain

$261,000,000

Remittance of payments received from customers for rate stabilization to BondCo.

21,000,000

24,000,000

63,000,000

Related Party Transaction Required Purchase Of Power Percentage

85.00%

Due from Affiliates

400,000,000

Severance Benefits Obligations Balance

6,000,000

Guarantor Obligations, Current Carrying Value

75,000,000

4,000,000

7,000,000

637,000,000

Related Party Purchase Of Nuclear Output By Third Party Percentage

49.99%

Payables to affiliates

124,000,000

181,000,000

245,000,000

205,000,000

Guarantor Obligations, Maximum Exposure, Undiscounted

9,542,000,000

6,136,000,000

260,000,000

165,000,000

Payments for Restructuring

$36,000,000

$5,000,000

$4,000,000

Variable_Interest_Entities_Car

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

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Apr. 01, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

In Millions, unless otherwise specified

Variable Interest Entity, Primary Beneficiary [Member]

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Variable Interest Entity, Primary Beneficiary [Member]

Variable Interest Entity [Line Items]

Current Assets

$1,071

[1],[2]

$484

[1]

$1,018

[2]

$446

$47

$28

Non Current Assets

7,384

[1],[2]

1,905

[1]

7,367

[2]

1,884

Total Assets

8,455

[1],[2]

2,389

[1]

8,385

[2]

2,330

Current Liabilities

545

[1],[2]

566

[1]

460

[2]

481

Non Current Liabilities

2,671

[1],[2]

774

[1]

2,499

[2]

562

158

195

Total Liabilities

3,216

[1],[2]

1,340

[1]

2,959

[2]

1,043

237

269

Assets

85,264

79,924

7,773

6,000

1,755

45,019

41,232

7,703

1,695

7,915

7,861

Total liabilities

$60,214

[3]

$56,984

[3]

$2,594

$2,000

$658

$30,693

[4]

$28,490

[4]

$2,338

$362

$5,214

[5]

$5,306

[5]

$237

$269

[1]

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

[2]

Includes total assets of $6.0 billion and total liabilities of $2.0 billion due to the consolidation of CENG beginning April 1, 2014. See Note 6 b Investment in Constellation Energy Nuclear Group, LLC for additional information.

[3]

Exelonbs consolidated assets include $7,773 million and $1,755 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelonbs consolidated liabilities include $2,594 million and $658 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.

[4]

Generationbs consolidated assets include $7,703 million and $1,695 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generationbs consolidated liabilities include $2,338 million and $362 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.

[5]

BGEbs consolidated assets include $50 million and $31 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of BGEbs consolidated VIE that can only be used to settle the liabilities of the VIE. BGEbs consolidated liabilities include $237 million and $269 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of BGEbs consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Variable_Interest_Entities_Ass

Variable Interest Entities - Assets and Liabilities of VIES which Creditors or Beneficiaries have no Recourse (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013		Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2014		Apr. 01, 2014	Dec. 31, 2013		Sep. 30, 2014		Dec. 31, 2013		Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2014		Dec. 31, 2013		Sep. 30, 2014		Dec. 31, 2013		Sep. 30, 2013	Dec. 31, 2012	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified							Variable Interest Entity, Primary Beneficiary [Member]		Variable Interest Entity, Primary Beneficiary [Member]	Variable Interest Entity, Primary Beneficiary [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]		Exelon Generation Co L L C [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]		Baltimore Gas and Electric Company [Member]
																		Variable Interest Entity, Primary Beneficiary [Member]		Variable Interest Entity, Primary Beneficiary [Member]								Variable Interest Entity, Primary Beneficiary [Member]		Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]	'		'		'	'	'		'	'		'		'		'	'	'		'		'		'		'	'	'		'
Cash and cash equivalents	$2,763		$1,609		$1,644	$1,486	$372		'	$62		$1,311		$1,258		$928	$671	$372		$62		$27		$31		$7	$89	$0		$0
Restricted cash	318		167		'	'	142		'	80		187		71		'	'	95		52		65		28		'	'	47		28
Accounts receivable, net	'		'		'	'	'		'	'		'		'		'	'	'		'		'		'		'	'	'		'
Customer	2,815		2,981		'	'	213		'	260		1,705		1,689		'	'	213		260		366		480		'	'	0		0
Other	898		1,175		'	'	53		'	0		325		353		'	'	53		0		90		114		'	'	0		0
Mark-to-market derivative assets (current assets)	744		727		'	'	40		'	21		744		727		'	'	40		21		'		'		'	'	0		0
Inventory	'		'		'	'	'		'	'		'		'		'	'	'		'		'		'		'	'	'		'
Materials and supplies	1,045		829		'	'	171		'	0		865		671		'	'	171		0		34		28		'	'	0		0
Other current assets	1,022		652		'	'	53		'	34		821		491		'	'	47		23		6		7		'	'	0		0
Total current assets	11,837		10,137		'	'	1,044		'	457		7,458		6,439		'	'	991		418		869		1,011		'	'	47		28
Property, plant and equipment, net	51,630		47,330		'	'	4,517		'	1,171		23,143		20,111		'	'	4,517		1,171		6,126		5,864		'	'	0		0
Nuclear decommissioning trust funds	10,349		8,071		'	'	2,034		'	0		10,349		8,071		'	'	2,034		0		'		'		'	'	0		0
Goodwill	2,672		2,625		'	'	46		'	0		47		0		'	'	46		0		'		'		'	'	0		0
Other noncurrent assets	1,139		964		'	'	132		'	127		714		645		'	'	115		106		26		26		'	'	3		3
Total noncurrent assets	'		'		'	'	6,729		'	1,298		'		'		'	'	6,712		1,277		'		'		'	'	3		3
Total assets	85,264		79,924		79,924	'	7,773		6,000	1,755		45,019		41,232		'	'	7,703		1,695		7,915		7,861		'	'	50		31
Short-term borrowings	562		341		'	'	1		'	0		14		22		'	'	1		0		20		135		'	'	0		0
Long-term debt due within one year	2,064		1,509		'	'	83		'	85		73		561		'	'	5		5		72		70		'	'	72		70
Accounts payable	2,502		2,484		'	'	264		'	170		1,318		1,322		'	'	264		170		207		270		'	'	0		0
Accrued expenses	1,462		1,633		'	'	78		'	26		840		976		'	'	72		22		167		111		'	'	7		4
Mark-to-market derivative liabilities (current liabilities)	249		159		'	'	18		'	29		235		142		'	'	18		29		'		'		'	'	0		0
Other current liabilities	195		261		'	'	53		'	10		192		249		'	'	53		10		'		'		'	'	0		0
Total current liabilities	8,431		7,728		'	'	497		'	320		3,835		3,867		'	'	413		236		757		827		'	'	79		74
Long-term debt	19,200		17,623		'	'	256		'	298		6,741		5,645		'	'	84		86		1,904		1,941		'	'	158		195
Asset retirement obligations	7,003		5,194		'	'	1,654		'	0		6,853		5,047		'	'	1,654		0		18		19		'	'	0		0
Pension obligation(a)	1,809		1,876		'	'	8	[1]	'	0	[1]	'		'		'	'	8	[1]	0	[1]	'		'		'	'	0	[1]	0	[1]
Other noncurrent liabilities	2,104		2,540		'	'	179		'	40		718		811		'	'	179		40		60		67		'	'	0		0
Total deferred credits and other liabilities	31,935		30,985		'	'	2,097		'	338		19,171		17,455		'	'	1,925		126		2,295		2,280		'	'	158		195
Total liabilities	$60,214	[2]	$56,984	[2]	'	'	$2,594		$2,000	$658		$30,693	[3]	$28,490	[3]	'	'	$2,338		$362		$5,214	[4]	$5,306	[4]	'	'	$237		$269

[1]	Includes the CNEG retail gasb pension obligation, which is presented as a net asset balance within the Prepaid Pension asset line item on Generationbs balance sheet. See Note b 13 - Retirement Benefits for additional details.
[2]	Exelonbs consolidated assets include $7,773 million and $1,755 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelonbs consolidated liabilities include $2,594 million and $658 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 3 - Variable Interest Entities.
[3]	Generationbs consolidated assets include $7,703 million and $1,695 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generationbs consolidated liabilities include $2,338 million and $362 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 3 - Variable Interest Entities.
[4]	BGEbs consolidated assets include $50 million and $31 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of BGEbs consolidated VIE that can only be used to settle the liabilities of the VIE. BGEbs consolidated liabilities include $237 million and $269 million at SeptemberB 30, 2014 and DecemberB 31, 2013, respectively, of BGEbs consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 3 - Variable Interest Entities.

Variable_Interest_Entities_Sum

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Variable Interest Entity [Line Items]	'		'
Total assets	$422	[1]	$460	[1]
Total liabilities	117	[1]	140	[1]
Exelon's ownership interest in VIE	62	[1]	86	[1]
Other ownership interests in VIE	243	[1]	234	[1]
Assets Held-in-trust, Noncurrent	365		458
Commercial Agreement Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Total assets	115	[1]	128	[1]
Total liabilities	2	[1]	17	[1]
Exelon's ownership interest in VIE	0	[1]	0	[1]
Other ownership interests in VIE	113	[1]	111	[1]
Equity Method Investment Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Total assets	307	[1]	332	[1]
Total liabilities	115	[1]	123	[1]
Exelon's ownership interest in VIE	62	[1]	86	[1]
Other ownership interests in VIE	130	[1]	123	[1]
Investments [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	66		'
Investments [Member] \| Maximum [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	'		74
Investments [Member] \| Maximum [Member] \| Commercial Agreement Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	0		7
Investments [Member] \| Maximum [Member] \| Equity Method Investment Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	66		67
Contract Intangible Asset [Member] \| Maximum [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	9		9
Contract Intangible Asset [Member] \| Maximum [Member] \| Commercial Agreement Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	9		9
Payment Guarantee [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	3		'
Payment Guarantee [Member] \| Maximum [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	'		5
Payment Guarantee [Member] \| Maximum [Member] \| Equity Method Investment Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	3		5
Asset Held In Trust Noncurrent [Member] \| Maximum [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	31	[2]	44	[2]
Asset Held In Trust Noncurrent [Member] \| Maximum [Member] \| Commercial Agreement Variable Interest Entities [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Registrants' maximum exposure to loss	31	[2]	44	[2]
Exelon Generation Co L L C [Member]	'		'
Variable Interest Entity [Line Items]	'		'
Assets Held-in-trust, Noncurrent	365		458
Payable to Zion Solutions	$334	[3]	$414	[3]

[1]	These items represent amounts on the unconsolidated VIE balance sheets, not on Exelonbs or Generationbs Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
[2]	These items represent amounts on Exelonbs and Generationbs 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 $365 million and $458 million as of SeptemberB 30, 2014 and DecemberB 31, 2013, respectively; offset by payables to ZionSolutions LLC of $334 million and $414 million as of SeptemberB 30, 2014 and DecemberB 31, 2013, respectively. These items are included to provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.
[3]	Excludes a liability recorded within Exelonbs and Generationbs Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.

Mergers_Acquisitions_and_Dispo2

Mergers, Acquisitions, and Dispositions - Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

Share data in Millions, except Per Share data, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Aug. 18, 2014

Jun. 30, 2014

Jun. 11, 2014

1-May-14

Dec. 31, 2013

Aug. 08, 2014

Jul. 18, 2014

Sep. 30, 2014

Jul. 18, 2014

Jun. 11, 2014

Jul. 18, 2014

Jul. 29, 2014

Sep. 30, 2014

Sep. 30, 2013

Mar. 31, 2014

Dec. 31, 2013

Jun. 11, 2014

Sep. 30, 2014

Pepco Holdings [Member]

Exelon Generation Co L L C [Member]

Junior Subordinated Debt [Member]

Bridge Loan [Member]

Electricity Generation Plant, Non-Nuclear [Member]

Minimum [Member]

Maximum [Member]

Pepco Holdings [Member]

Payments to Acquire Businesses and Interest in Affiliates [Abstract]

Payments to Acquire Businesses, Gross

$67,000,000

$60,000,000

$67,000,000

Business Combination, Integration Related Costs

57,000,000

Other Payments to Acquire Businesses

260,000,000

Business Combination Proposed Customer Benefits Package

100,000,000

Business Exit Costs

259,000,000

293,000,000

Cash Funding From Non Core Asset Sale

1,000,000,000

Expected Debt Issuance

3,500,000,000

Subordinated Debt, Amount

1,200,000,000

Equity Security units

57.5

Line of Credit Facility, Maximum Borrowing Capacity

8,500,000,000

[1]

8,500,000,000

[1]

7,200,000,000

Bridge Loan

3,900,000,000

7,200,000,000

Equity Method Investment, Ownership Percentage

67.00%

50.01%

Gain on Sale of Investments

329,000,000

Equity Method Investment, Net Sales Proceeds

615,000,000

Cash offered in exchange for each share of PHI stock

$27.25

$35

Payments to Acquire Assets, Investing Activities

90,000,000

Other Long-term Investments

18,000,000

Other Long Term Investments Maximum

180,000,000

Other noncurrent assets

1,139,000,000

964,000,000

108,000,000

714,000,000

645,000,000

Significant Acquisitions and Disposals, Acquisition Costs or Sale Proceeds

7,200,000,000

Expected Pre-Tax proceeds

1,300,000,000

Assets Held-for-sale, at Carrying Value

$900,000,000

[1]

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEdbs, PECObs and BGEbs service territories. These facilities expired on OctoberB 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 SeptemberB 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $9 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.9 billion to support the PHI transaction discussed below, as well as, applicable asset divestitures.

Mergers_Acquisitions_and_Dispo3

Mergers, Acquisitions, and Dispositions - Assets Disposition Table (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Electricity Generation Plant, Non-Nuclear [Member]
Assets Disposition Table [Line Items]	'	'	'
Property, plant and equipment, net (a)	'	'	$617	[1]
Inventory	'	'	31
Current assets	'	'	1
Total assets held for sale	649	14	649
Accounts payable	'	'	1
Accrued expenses	1,462	1,633	4
Other current liabilities	985	858	13
Total liabilities held for sale (b)	'	'	18	[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 Exelonbs and Generationbs Statements of Operations and Comprehensive Income. See Note 7 - Impairment of Long-Lived Assets for further information.
[2]	Included within Other current liabilities on Exelon's and Generation's Consolidated Balance Sheets.

Regulatory_Matters_Narrative_D

Regulatory Matters - Narrative (Details) (USD $)

0 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

48 Months Ended

0 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

0 Months Ended

Jun. 19, 2013

Sep. 30, 2014

Dec. 31, 2012

Sep. 18, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2008

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Apr. 10, 2014

Mar. 19, 2012

Sep. 30, 2010

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

31-May-13

Aug. 23, 2014

Aug. 21, 2014

Jul. 02, 2014

Dec. 13, 2013

17-May-13

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Sep. 15, 2014

Jul. 02, 2014

Feb. 26, 2014

Aug. 23, 2013

17-May-13

Sep. 30, 2014

Jun. 03, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Jun. 19, 2014

Jun. 19, 2013

Sep. 30, 2014

Oct. 15, 2014

Oct. 17, 2014

Smart_meter

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Exelon Generation Co L L C [Member]

Under Recovered Distribution Service Costs [Member]

AMI Expenses [Member]

Energy Efficiency And Demand Response Programs [Member]

Transmission Rate Formula [Member]

FERC Transmission Complaint [Member]

Subsequent Event [Member]

Smart_meter

Energy Efficiency And Demand Response Programs [Member]

Smart_meter

Minimum [Member]

Maximum [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Commonwealth Edison Co [Member]

Baltimore Gas and Electric Company [Member]

Regulatory Matters Additional Narrative Information [Line Items]

Rate of Return on Common Equity, Incentive Basis Points

0.50%

Net regulatory asset

$466,000,000

$463,000,000

$3,000,000

$19,000,000

$17,000,000

Public Utilities, Requested Rate Increase (Decrease), Amount

24,000,000

269,000,000

Expected revenue adjustment for current year

174,000,000

80,000,000

-20,000,000

Expected revenue adjustment for prior year

95,000,000

7,000,000

10,000,000

Requested Debt and Equity Return on Distribution

7.06%

Requested ROE

9.25%

Weighted Average Debt And Equity Return Electric Distribution

7.04%

Weighted Average Debt And Equity Return

8.62%

8.70%

9.20%

8.53%

8.35%

Public Utilities, Interim Rate Increase (Decrease), Amount

239,000,000

Approved Debt and Equity Rate on Distribution

7.54%

Approved ROE

10.30%

9.81%

10.80%

ICC Approved Rate Increase (Decrease), Amount

274,000,000

73,000,000

Demand response peak demand reduction

4.50%

Requested increase in electric revenues

118,000,000

101,000,000

Adjustment to Requested increase in electric revenues

99,000,000

83,000,000

Requested increase in gas revenues

68,000,000

30,000,000

Rate of return on common equity electric distribution

9.75%

Rate of return on common equity gas distribution

9.60%

Increase in electric delivery service revenue resulting from rate case settlement or order.

34,000,000

22,000,000

Increase in gas delivery service revenue resulting from rate case settlement or order.

12,000,000

38,000,000

Annual Depreciation Expense Decrease Regulated Property

20,000,000

Requested Rate Of Return Common Equity Electric Distribution

0.1065

0.105

Requested Rate Of Return Common Equity Gas Distribution

0.1055

0.1035

Gross transmission revenue requirement

524,000,000

488,000,000

167,000,000

158,000,000

Transmission revenue true up

11,000,000

25,000,000

4,000,000

1,000,000

Net transmission revenue requirement

535,000,000

513,000,000

171,000,000

157,000,000

Net Regulatory Asset

466,000,000

463,000,000

3,000,000

19,000,000

17,000,000

Regulatory Rate of Return Approved

11.30%

Public Utilities, Interim Rate Increase (Decrease), Percentage

10.57%

Public Utilities, Requested Rate Increase (Decrease), Percentage

11.14%

Revenue Reduction

10,000,000

30,000,000

Customer Refund Liability, Noncurrent

9,500,000

14,600,000

400,000

37,000,000

13,000,000

Estimated number of smart meters to be installed

1,600,000

2,000,000

Smart Meters Installed

600,000

500,000

Revised spend on its Smart Meter Procurement and Installation Plan

595,000,000

Spend on smart grid investments

120,000,000

Smart meter spend to date

516,000,000

Smart grid infrastructure spend to date

119,000,000

Total smart grid and smart meter investment grant amount

200,000,000

Smart meter investment grant awarded

140,000,000

Smart grid investment grant awarded

60,000,000

Reimbursements received from the DOE

200,000,000

Regulatory assets

5,589,000,000

5,910,000,000

928,000,000

933,000,000

1,520,000,000

1,448,000,000

500,000,000

524,000,000

223,000,000

285,000,000

223,000,000

285,000,000

254,000,000

159,000,000

69,000,000

35,000,000

74,000,000

58,000,000

111,000,000

66,000,000

151,000,000

148,000,000

151,000,000

148,000,000

Regulatory assets for original smart meters purchased

17,000,000

Vendor Refund

12,000,000

Amount of reimbursements received from the DOE applied to the originally installed Smart Meters.

16,000,000

Total Projected smart meter smart grid spend

480,000,000

Current Year AMI Events Balance

5,000,000

Depreciation Related To Original Meters

2,000,000

DOE Cash Payable to Sub Recipients

4,000,000

Upfront fee for opt-out of Smart Meter

Recurring Fees

Cumulative Consumption Reduction Targets

3.00%

Proposed funding of estimated costs associated with DLC demand program due to modification of incentive levels for other Phase II programs.

10,000,000

Customer Refund

9,500,000

14,600,000

400,000

37,000,000

13,000,000

Cash Collected

24,000,000

Rate Of Return On Common Equity

11.50%

11.30%

Common Equity Component Cap

55.00%

11.50%

Capital and OM estimates current year

14,800,000

Revenue Requirement

1,400,000

Minimum Purchase Obligation

25,000,000

Maximum Purchase Obligation

35,000,000

License Costs

$38,000,000

Rate Of Return On Common Equity In Federal Energy Regulatory Committee Complaint

8.70%

Transmission Rate Formula, First Basis Points Credited

0.50%

Regulatory_Matters_Regulatory_

Regulatory Matters Regulatory Matters - Schedule of Regulatory Assets (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Regulatory Assets [Line Items]	'		'
Current	$774		$760
Noncurrent	5,589		5,910
DSP Program [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Assets	28		34
Other Postretirement Benefits [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	208		221
Noncurrent	2,455		2,794
Deferred Income Tax Charge [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	7		10
Noncurrent	1,517		1,459
AMI Expenses [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	9		5
Noncurrent	254		159
AMI Meter Events [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	'		0
Noncurrent	'		5
Under Recovered Distribution Service Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	243		178
Noncurrent	223		285
Loss on Reacquired Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	9		12
Noncurrent	50		56
Fair Value Of Long Term Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	6	[1]	0	[1]
Noncurrent	192	[1]	219	[1]
Fair Value Of Supply Contract [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	3	[2]	12	[2]
Noncurrent	0		0	[2]
Employee Severance [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	4		16
Noncurrent	9		12
Asset Retirement Obligation Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		1
Noncurrent	111		102
Environmental Restoration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	39		40
Noncurrent	220		212
RTO Startup Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		2
Noncurrent	0		0
Under Recovered Uncollectible Accounts Expense [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	70		48
Renewable Energy And Associated REC [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	14		17
Noncurrent	164		176
Under Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	22		53
Noncurrent	5		0
Deferred Storm Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	3		3
Noncurrent	0		3
Electric Generation Related Regulatory Asset [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	12		13
Noncurrent	21		30
Rate Stabilization Deferral [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	75		71
Noncurrent	101		154
Energy Efficiency And Demand Response Programs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	84		73
Noncurrent	151		148
Merger Integration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	2		2
Noncurrent	7		9
ConservativeVoltageReductionProgram [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		'
Noncurrent	1		'
Regulatory Assets [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	17		31
Noncurrent	38		39
Under Recovered Decoupling Revenue [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	14	[3]	'
Noncurrent	0		'
Over-Recovered Natural Gas Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Assets	11		8
Over Recovered Electric Energy And Transmission Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Assets	5		16
Commonwealth Edison Co [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	330		329
Noncurrent	928		933
Commonwealth Edison Co [Member] \| Other Postretirement Benefits [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Deferred Income Tax Charge [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		2
Noncurrent	67		65
Commonwealth Edison Co [Member] \| AMI Expenses [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	9		5
Noncurrent	69		35
Commonwealth Edison Co [Member] \| AMI Meter Events [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	'		0
Noncurrent	'		0
Commonwealth Edison Co [Member] \| Under Recovered Distribution Service Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	243		178
Noncurrent	223		285
Commonwealth Edison Co [Member] \| Loss on Reacquired Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	7		9
Noncurrent	48		53
Commonwealth Edison Co [Member] \| Fair Value Of Long Term Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0	[1]
Noncurrent	0		0	[1]
Commonwealth Edison Co [Member] \| Fair Value Of Supply Contract [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0	[2]
Noncurrent	0		0	[2]
Commonwealth Edison Co [Member] \| Employee Severance [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		12
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Asset Retirement Obligation Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		1
Noncurrent	73		67
Commonwealth Edison Co [Member] \| Environmental Restoration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	32		33
Noncurrent	186		178
Commonwealth Edison Co [Member] \| RTO Startup Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		2
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Under Recovered Uncollectible Accounts Expense [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	70		48
Commonwealth Edison Co [Member] \| Renewable Energy And Associated REC [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	14		17
Noncurrent	164		176
Commonwealth Edison Co [Member] \| Under Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	19		52
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Deferred Storm Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Electric Generation Related Regulatory Asset [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Rate Stabilization Deferral [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Energy Efficiency And Demand Response Programs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Merger Integration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| ConservativeVoltageReductionProgram [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		'
Noncurrent	0		'
Commonwealth Edison Co [Member] \| Regulatory Assets [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	3		18
Noncurrent	28		26
Commonwealth Edison Co [Member] \| Under Recovered Decoupling Revenue [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		'
Noncurrent	0		'
PECO Energy Co [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	21		17
Noncurrent	1,520		1,448
PECO Energy Co [Member] \| Other Postretirement Benefits [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Deferred Income Tax Charge [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	1,377		1,317
PECO Energy Co [Member] \| AMI Expenses [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	74		58
PECO Energy Co [Member] \| AMI Meter Events [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	'		0
Noncurrent	'		5
PECO Energy Co [Member] \| Under Recovered Distribution Service Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Loss on Reacquired Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	2		3
Noncurrent	2		3
PECO Energy Co [Member] \| Fair Value Of Long Term Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0	[1]
Noncurrent	0		0	[1]
PECO Energy Co [Member] \| Fair Value Of Supply Contract [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0	[2]
Noncurrent	0		0	[2]
PECO Energy Co [Member] \| Employee Severance [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Asset Retirement Obligation Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	26		25
PECO Energy Co [Member] \| Environmental Restoration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	6		6
Noncurrent	33		33
PECO Energy Co [Member] \| RTO Startup Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Under Recovered Uncollectible Accounts Expense [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Renewable Energy And Associated REC [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Under Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Deferred Storm Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Electric Generation Related Regulatory Asset [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Rate Stabilization Deferral [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Energy Efficiency And Demand Response Programs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Merger Integration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| ConservativeVoltageReductionProgram [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		'
Noncurrent	0		'
PECO Energy Co [Member] \| Regulatory Assets [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	13		8
Noncurrent	8		7
PECO Energy Co [Member] \| Under Recovered Decoupling Revenue [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		'
Noncurrent	0		'
Baltimore Gas and Electric Company [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	206		181
Noncurrent	500		524
Baltimore Gas and Electric Company [Member] \| Other Postretirement Benefits [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Deferred Income Tax Charge [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	6		8
Noncurrent	73		77
Baltimore Gas and Electric Company [Member] \| AMI Expenses [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	111		66
Baltimore Gas and Electric Company [Member] \| AMI Meter Events [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	'		0
Noncurrent	'		0
Baltimore Gas and Electric Company [Member] \| Under Recovered Distribution Service Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Loss on Reacquired Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		1
Noncurrent	8		8
Baltimore Gas and Electric Company [Member] \| Fair Value Of Long Term Debt [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0	[1]
Noncurrent	0		0	[1]
Baltimore Gas and Electric Company [Member] \| Fair Value Of Supply Contract [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0	[2]
Noncurrent	0		0	[2]
Baltimore Gas and Electric Company [Member] \| Employee Severance [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	4		4
Noncurrent	9		12
Baltimore Gas and Electric Company [Member] \| Asset Retirement Obligation Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	12		10
Baltimore Gas and Electric Company [Member] \| Environmental Restoration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		1
Noncurrent	1		1
Baltimore Gas and Electric Company [Member] \| RTO Startup Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Under Recovered Uncollectible Accounts Expense [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Renewable Energy And Associated REC [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Under Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	3	[4]	1	[4]
Noncurrent	5		0
Baltimore Gas and Electric Company [Member] \| Deferred Storm Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	3		3
Noncurrent	0		3
Baltimore Gas and Electric Company [Member] \| Electric Generation Related Regulatory Asset [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	12		13
Noncurrent	21		30
Baltimore Gas and Electric Company [Member] \| Rate Stabilization Deferral [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	75		71
Noncurrent	101		154
Baltimore Gas and Electric Company [Member] \| Energy Efficiency And Demand Response Programs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	84		73
Noncurrent	151		148
Baltimore Gas and Electric Company [Member] \| Merger Integration Costs [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	2		2
Noncurrent	7		9
Baltimore Gas and Electric Company [Member] \| ConservativeVoltageReductionProgram [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	1		'
Noncurrent	1		'
Baltimore Gas and Electric Company [Member] \| Regulatory Assets [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	0		4
Noncurrent	0		6
Baltimore Gas and Electric Company [Member] \| Under Recovered Decoupling Revenue [Member]	'		'
Regulatory Assets [Line Items]	'		'
Current	14	[3]	'
Noncurrent	0		'
Baltimore Gas and Electric Company [Member] \| Under-Recovered Electric Revenue Decoupling [Member]	'		'
Regulatory Assets [Line Items]	'		'
Regulatory Assets	$14		'

[1]	Represents the regulatory asset recorded at Exelon Corporate for the difference in the fair value of the long-term debt of BGE as of the merger date. The asset is amortized over the life of the underlying debt.
[2]	Represents the regulatory asset recorded at Exelon Corporate representing the fair value of BGEbs supply contracts as of the close of the merger date. BGE is allowed full recovery of the costs of its electric and gas supply contracts through approved, regulated rates. The asset is amortized over a period of approximately 3 years.
[3]	Represents the electric and gas distribution costs recoverable from customers under BGEbs decoupling mechanism. As of SeptemberB 30, 2014, BGE had a regulatory asset of $14 million related to under-recovered electric revenue decoupling and a regulatory liability of $16 million related to over-recovered natural gas revenue decoupling. As of DecemberB 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.
[4]	Relates to $3 million associated with the transmission formula rate and $3 million of over-recovered natural gas supply costs as of SeptemberB 30, 2014. As of DecemberB 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs.

Regulatory_Matters_Regulatory_1

Regulatory Matters Regulatory Matters - Schedule of Regulatory Liabilities (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Regulatory Liabilities [Line Items]	'		'
Current	$364		$327
Noncurrent	4,593		4,388
Other Postretirement Benefits [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	53		2
Noncurrent	96		43
Nuclear Decommissioning [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	2,850		2,740
Removal Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	110		99
Noncurrent	1,455		1,423
Energy Efficiency Demand Response Programs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	28		53
Noncurrent	2		0
Dlc Program Cost [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		1
Noncurrent	10		10
Energy Efficiency Phase [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	32		21
Electric Transmission And Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	20		20
Noncurrent	100		114
Gas Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	8		8
Noncurrent	32		37
Over Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	73		78
Noncurrent	13		0
Over-Recovered Universal Service Fund Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	4		8
Noncurrent	0		0
Revenue Subject to Refund [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	47	[1]	38	[1]
Noncurrent	0	[1]	0	[1]
Over Recovered Decoupling Revenue [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	16	[2]	16	[2]
Noncurrent	0	[2]	0	[2]
Regulatory Liabilities Other [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	5		4
Noncurrent	3		0
Transmission Rate Formula [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liabilities	3		'
Over-Recovered Natural Gas Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liabilities	3		11
Under-Recovered Electric Supply Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liabilities	'		1
Baltimore Gas and Electric Company [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	45		48
Noncurrent	199		204
Baltimore Gas and Electric Company [Member] \| Over Recovered Decoupling Gas Revenue [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liabilities	16		9
Baltimore Gas and Electric Company [Member] \| Over Recovered Decoupling Electric Revenue [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Regulatory Liabilities	'		7
Baltimore Gas and Electric Company [Member] \| Other Postretirement Benefits [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Nuclear Decommissioning [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Removal Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	24		21
Noncurrent	198		204
Baltimore Gas and Electric Company [Member] \| Energy Efficiency Demand Response Programs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Dlc Program Cost [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Energy Efficiency Phase [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Electric Transmission And Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Gas Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		'
Noncurrent	0		'
Baltimore Gas and Electric Company [Member] \| Over Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	3	[3]	11	[3]
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Over-Recovered Universal Service Fund Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Baltimore Gas and Electric Company [Member] \| Revenue Subject to Refund [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0	[1]	0	[1]
Noncurrent	0	[1]	0	[1]
Baltimore Gas and Electric Company [Member] \| Over Recovered Decoupling Revenue [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	16	[2]	16	[2]
Noncurrent	0	[2]	0	[2]
Baltimore Gas and Electric Company [Member] \| Regulatory Liabilities Other [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	2		0
Noncurrent	1		0
PECO Energy Co [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	79		106
Noncurrent	655		629
PECO Energy Co [Member] \| Other Postretirement Benefits [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Nuclear Decommissioning [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	479		447
PECO Energy Co [Member] \| Removal Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
PECO Energy Co [Member] \| Energy Efficiency Demand Response Programs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		8
Noncurrent	2		0
PECO Energy Co [Member] \| Dlc Program Cost [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		1
Noncurrent	10		10
PECO Energy Co [Member] \| Energy Efficiency Phase [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	32		21
PECO Energy Co [Member] \| Electric Transmission And Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	20		20
Noncurrent	100		114
PECO Energy Co [Member] \| Gas Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	8		8
Noncurrent	32		37
PECO Energy Co [Member] \| Over Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	44	[4]	58	[4]
Noncurrent	0		0
PECO Energy Co [Member] \| Over-Recovered Universal Service Fund Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	4		8
Noncurrent	0		0
PECO Energy Co [Member] \| Revenue Subject to Refund [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0	[1]	0	[1]
Noncurrent	0	[1]	0	[1]
PECO Energy Co [Member] \| Over Recovered Decoupling Revenue [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0	[2]	0	[2]
Noncurrent	'		0	[2]
PECO Energy Co [Member] \| Regulatory Liabilities Other [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	3		3
Noncurrent	0		0
Commonwealth Edison Co [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	187		170
Noncurrent	3,643		3,512
Commonwealth Edison Co [Member] \| Other Postretirement Benefits [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Nuclear Decommissioning [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	2,371		2,293
Commonwealth Edison Co [Member] \| Removal Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	86		78
Noncurrent	1,257		1,219
Commonwealth Edison Co [Member] \| Energy Efficiency Demand Response Programs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	28		45
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Dlc Program Cost [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Energy Efficiency Phase [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Electric Transmission And Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Gas Distribution Tax Repairs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Over Recovered Energy And Transmission Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	26		9
Noncurrent	13		0
Commonwealth Edison Co [Member] \| Over-Recovered Universal Service Fund Costs [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	0		0
Commonwealth Edison Co [Member] \| Revenue Subject to Refund [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	47	[1]	38	[1]
Noncurrent	0	[1]	0	[1]
Commonwealth Edison Co [Member] \| Over Recovered Decoupling Revenue [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0	[2]	0	[2]
Noncurrent	0	[2]	0	[2]
Commonwealth Edison Co [Member] \| Regulatory Liabilities Other [Member]	'		'
Regulatory Liabilities [Line Items]	'		'
Current	0		0
Noncurrent	$2		$0

[1]	Primarily represents the regulatory liability for revenue subject to refund recorded pursuant to the ICCbs order in the 2007 Rate Case. See Note 3 b Regulatory Matters of the Exelon 2013 Form 10-K. for further information.
[2]	Represents the electric and gas distribution costs recoverable from customers under BGEbs decoupling mechanism. As of SeptemberB 30, 2014, BGE had a regulatory asset of $14 million related to under-recovered electric revenue decoupling and a regulatory liability of $16 million related to over-recovered natural gas revenue decoupling. As of DecemberB 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.
[3]	Relates to $3 million associated with the transmission formula rate and $3 million of over-recovered natural gas supply costs as of SeptemberB 30, 2014. As of DecemberB 31, 2013, includes $1 million of under-recovered electric supply costs and $11 million of over-recovered natural gas supply costs.
[4]	Includes $28 million related to the DSP program, $11 million related to the over-recovered natural gas costs under the PGC and $5 million related to over-recovered electric transmission costs as of SeptemberB 30, 2014. As of DecemberB 31, 2013, includes $34 million related to the DSP program, $8 million related to the over-recovered electric transmission costs and $16 million related to the over-recovered natural gas costs under the PGC.

Regulatory_Matters_Regulatory_2

Regulatory Matters Regulatory Matters - Purchase of Receivables Programs (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Purchase Of Receivables [Line Items]	'		'
Purchased receivables	$306	[1]	$263	[1]
Allowance for uncollectible accounts	-36	[2]	-30	[2]
Purchased receivables, net	270		233
Discount rate	1.00%		'
Commonwealth Edison Co [Member]	'		'
Purchase Of Receivables [Line Items]	'		'
Purchased receivables	152	[1]	105	[1]
Allowance for uncollectible accounts	-21	[2]	-16	[2]
Purchased receivables, net	131		89
PECO Energy Co [Member]	'		'
Purchase Of Receivables [Line Items]	'		'
Purchased receivables	78	[1]	72	[1]
Allowance for uncollectible accounts	-8	[2]	-7	[2]
Purchased receivables, net	70		65
Baltimore Gas and Electric Company [Member]	'		'
Purchase Of Receivables [Line Items]	'		'
Purchased receivables	76	[1]	86	[1]
Allowance for uncollectible accounts	-7	[2]	-7	[2]
Purchased receivables, net	$69		$79

[1]	PECObs gas POR program became effective on JanuaryB 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.

Investment_in_Constellation_En2

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	Apr. 01, 2014
Exelon Generation Co L L C [Member] \| Constellation Energy Nuclear Group [Member]	'
Schedule of Equity Method Investments [Line Items]	'
Current assets	$499
Nuclear decommissioning trust fund	1,955
Property, plant and equipment	2,941
Nuclear fuel	482
Other assets	10
Total assets	5,887
Current liabilities	237
Asset retirement obligation	1,684
Pension and other employee benefit obligations	281
Unamortized energy contract liabilities	171
Other liabilities	114
Total liabilities	2,487
Total net assets	$3,400

Investment_in_Constellation_En3

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

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

0 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Aug. 18, 2014

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2014

Mar. 31, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Dec. 31, 2012

Sep. 30, 2014

Mar. 31, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Apr. 01, 2014

Sep. 30, 2014

Apr. 01, 2014

Sep. 30, 2014

Apr. 01, 2014

Constellation Energy Nuclear Group [Member]

Exelon Generation Co L L C [Member]

Electricite De France LLC [Member]

Constellation Energy Group LLC [Member]

Constellation Energy Nuclear Group [Member]

EDFI [Member]

Payment Guarantee [Member]

Financial Guarantee [Member]

Variable Interest Entity, Primary Beneficiary [Member]

Constellation Energy Nuclear Group [Member]

Exelon Generation Co L L C [Member]

Constellation Energy Group LLC [Member]

Constellation Energy Nuclear Group [Member]

Exelon Generation Co L L C [Member]

Constellation Energy Nuclear Group [Member]

Exelon Generation Co L L C [Member]

Electricite De France LLC [Member]

Schedule of Equity Method Investments [Line Items]

Equity Method Investment, Ownership Percentage

67.00%

50.01%

Due from Affiliates

$400,000,000

Interest rate on loan to CENG

5.25%

Payments of Distributions to Affiliates

440,000,000

550,000,000

400,000,000

Reduction To Net Income Attributable To Noncontrolling Interest

4,000,000

8,000,000

Interest Rate On Distribution

8.50%

Related Party Purchase Of Nuclear Output By Third Party Percentage

49.99%

Payables to affiliates

124,000,000

181,000,000

245,000,000

205,000,000

Guarantor Obligations, Maximum Exposure, Undiscounted

9,542,000,000

6,136,000,000

165,000,000

145,000,000

Total equity investment earnings (losses) - CENG

-19,000,000

37,000,000

5,000,000

Revenues

6,912,000,000

[1]

6,502,000,000

[1]

20,173,000,000

[2]

18,725,000,000

[2]

4,412,000,000

4,255,000,000

12,591,000,000

11,858,000,000

58,000,000

17,000,000

12,000,000

155,000,000

45,000,000

Investment in CENG

1,925,000,000

1,900,000,000

Accumulated other comprehensive loss, net

-1,917,000,000

[3]

-2,661,000,000

[3]

-1,917,000,000

[3]

-2,661,000,000

[3]

-2,040,000,000

[3]

-2,767,000,000

[3]

1,500,000,000

11,000,000

[3]

243,000,000

[3]

11,000,000

[3]

243,000,000

[3]

214,000,000

[3]

513,000,000

[3]

116,000,000

Allocation Of Federal Tax Benefit Under Tax Sharing Agreement

152,000,000

Other Comprehensive Income (Loss), Tax

8,000,000

1,000,000

-77,000,000

70,000,000

17,000,000

-27,000,000

129,000,000

-177,000,000

77,000,000

Related Party Transaction Required Purchase Of Power Percentage

85.00%

15.00%

Revenue from Related Parties

[4]

2,000,000

[4]

[5]

2,000,000

[5]

112,000,000

384,000,000

647,000,000

1,129,000,000

52,000,000

90,000,000

Business Combination, Step Acquisition, Equity Interest in Acquiree, Remeasurement Gain

261,000,000

Business Combination, Step Acquisition, Equity Interest in Acquiree, Fair Value

136,000,000

Business Acquisition, Preexisting Relationship, Gain (Loss) Recognized

132,000,000

Guarantor Obligations, Current Carrying Value

75,000,000

4,000,000

7,000,000

Net Income (Loss) Attributable to Parent

171,000,000

248,000,000

Business Combination, Integration Related Costs

$4,000,000

$22,000,000

[1]

For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.

[2]

For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.

[3]

All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

[4]

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generationbs sale of certain products and services by and between Exelonbs 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.

[5]

Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generationbs sale of certain products and services by and between Exelonbs 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.

Recovered_Sheet1

Impairment of Long-Lived Assets (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

9 Months Ended

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Oct. 31, 2000

Sep. 30, 2014

Jun. 30, 2014

Sep. 30, 2013

Mar. 31, 2013

Jun. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

31-May-14

Exelon Generation Co L L C [Member]

Capital Leases, Net Investment in Direct Financing Leases [Abstract]

Carrying Amount Of Long Lived Assets To Be Written Down

$75,000,000

$151,000,000

Impaired Assets Fair Value

32,000,000

65,000,000

Tangible Asset Impairment Charges

24,000,000

14,000,000

86,000,000

39,000,000

Utilities Operating Expense, Impairments

21,000,000

92,000,000

Interest Costs Incurred

8,000,000

Estimated residual value of leased assets

685,000,000

1,465,000,000

1,600,000,000

Capital Lease Net Investment In Direct Financing Leases Prepayments Received

1,200,000,000

Proceeds From Lease Termination

335,000,000

Capital Leases Net Investment In Direct Financing Leases Writeoff

336,000,000

Operating and maintenance

1,982,000,000

1,000,000

1,735,000,000

6,005,000,000

5,391,000,000

1,114,000,000

936,000,000

3,308,000,000

2,943,000,000

Impairment of Long-Lived Assets to be Disposed of

$50,000,000

Impairment_of_Longlived_Assets2

Impairment of Long-lived Assets - Components of the Net Investment in Long-term Leases (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Oct. 31, 2000
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Oct. 31, 2000
Property, Plant and Equipment [Abstract]	'	'	'
Estimated residual value of leased assets	$685	$1,465	$1,600
Less: unearned income	328	767	'
Net investment in long-term leases	$357	$698	'

Fair_Value_of_Financial_Assets2

Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at the Carrying Amount (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Reported Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	$565	$344
Long-term debt (including amounts due within one year)	21,264	19,132
Long-term debt to financing trusts	648	648
SNF obligation	1,021	1,021
Estimate of Fair Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	565	344
Long-term debt (including amounts due within one year)	22,743	19,751
Long-term debt to financing trusts	677	631
SNF obligation	849	790
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	3	3
Long-term debt (including amounts due within one year)	1,168	0
Long-term debt to financing trusts	0	0
SNF obligation	0	0
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	562	341
Long-term debt (including amounts due within one year)	20,278	18,672
Long-term debt to financing trusts	0	0
SNF obligation	849	790
Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 3 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	1,297	1,079
Long-term debt to financing trusts	677	631
SNF obligation	0	0
Exelon Generation Co L L C [Member] \| Reported Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	14	22
Long-term debt (including amounts due within one year)	8,320	7,729
SNF obligation	1,021	1,021
Exelon Generation Co L L C [Member] \| Estimate of Fair Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	14	22
Long-term debt (including amounts due within one year)	8,840	7,648
SNF obligation	849	790
Exelon Generation Co L L C [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
SNF obligation	0	0
Exelon Generation Co L L C [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	14	22
Long-term debt (including amounts due within one year)	7,543	6,586
SNF obligation	849	790
Exelon Generation Co L L C [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 3 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	1,297	1,062
SNF obligation	0	0
Commonwealth Edison Co [Member] \| Reported Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	528	184
Long-term debt (including amounts due within one year)	5,708	5,675
Long-term debt to financing trusts	206	206
Commonwealth Edison Co [Member] \| Estimate of Fair Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	528	184
Long-term debt (including amounts due within one year)	6,422	6,255
Long-term debt to financing trusts	214	202
Commonwealth Edison Co [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	0	0
Commonwealth Edison Co [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	528	184
Long-term debt (including amounts due within one year)	6,422	6,238
Long-term debt to financing trusts	0	0
Commonwealth Edison Co [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 3 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	17
Long-term debt to financing trusts	214	202
PECO Energy Co [Member] \| Reported Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt (including amounts due within one year)	2,496	2,197
Long-term debt to financing trusts	184	184
PECO Energy Co [Member] \| Estimate of Fair Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt (including amounts due within one year)	2,720	2,358
Long-term debt to financing trusts	204	180
PECO Energy Co [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	0	0
PECO Energy Co [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt (including amounts due within one year)	2,720	2,358
Long-term debt to financing trusts	0	0
PECO Energy Co [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 3 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	204	180
Baltimore Gas and Electric Company [Member] \| Reported Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	23	138
Long-term debt (including amounts due within one year)	1,976	2,011
Long-term debt to financing trusts	258	258
Baltimore Gas and Electric Company [Member] \| Estimate of Fair Value Measurement [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	23	138
Long-term debt (including amounts due within one year)	2,196	2,148
Long-term debt to financing trusts	259	249
Baltimore Gas and Electric Company [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 1 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	3	3
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	0	0
Baltimore Gas and Electric Company [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 2 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	20	135
Long-term debt (including amounts due within one year)	2,196	2,148
Long-term debt to financing trusts	0	0
Baltimore Gas and Electric Company [Member] \| Estimate of Fair Value Measurement [Member] \| Fair Value, Inputs, Level 3 [Member]	'	'
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]	'	'
Short-term liabilities	0	0
Long-term debt (including amounts due within one year)	0	0
Long-term debt to financing trusts	$259	$249

Fair_Value_of_Financial_Assets3

Fair Value of Financial Assets and Liabilities - Fair Value Measurements of Assets and Liabilities, Recurring and Nonrecurring (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	$1,876		$1,230
Fixed income	'		'
Other investments	16		15
Total assets	13,902		11,162
Deferred compensation obligation	-105		-114
Total liabilities	-645		-573
Total net assets	13,257		10,589
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-105		-114
Mark-to-market derivative liabilities	291		300
Derivative Liability, Current	249		159
Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	323		459
Equity	'		'
Individually held	2,569		1,776
Exchange traded funds	170		115
Commingled funds	2,365		2,271
Equity funds subtotal	5,104		4,162
Balanced funds - commingled funds	273		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	967		882
Debt securities issued by states of the United States and political subdivisions of the states	429		294
Debt securities issued by foreign governments	105		87
Corporate debt securities	2,236		1,784
Federal agency mortgage-backed securities	79		10
Commercial mortgage-backed securities (non-agency)	39		40
Residential mortgage-backed securities (non-agency)	3		7
Mutual funds	21		18
Commingled funds	328		'
Fixed income subtotal	4,207		3,122
Middle market lending	354		314
Private Equity	54		5
Other debt obligations	19		14
Fair Value Assets Measured On Recurring Basis Real Estate	1		'
Nuclear decommissioning trust fund investments subtotal	10,335		8,076
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments	14		-5
Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	12		26
Equity	'		'
Individually held	7		16
Equity funds subtotal	7		16
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	15		49
Debt securities issued by states of the United States and political subdivisions of the states	19		20
Corporate debt securities	138		227
Commingled funds	4		'
Fixed income subtotal	176		296
Middle market lending	166		112
Other debt obligations	'		1
Pledged assets for Zion Station decommissioning subtotal	361		451
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Net assets (liabilities) excluded from nuclear decommissioning trust fund investments	4		7
Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		2
Fixed income	'		'
Mutual funds	46		54
Rabbi trust investments subtotal	46		56
Deferred compensation obligation	-45		-53
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-45		-53
Supplemental executive retirement plan fair value	1		1
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	35		32
Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	4,602		3,960
Proprietary trading	880		1,761
Effect of netting and allocation of collateral	4,248		4,424
Commodity derivative assets subtotal	1,234		1,297
Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-4,324		-3,020
Proprietary trading	-891		-1,703
Effect of netting and allocation of collateral	-4,707		-4,280
Commodity derivative assets subtotal	-508		-443
Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-24		-32
Interest rate and foreign currency derivative assets	'		-69
Interest rate and foreign currency derivative assets subtotal	-34		-37
Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-22		-32
Interest rate and foreign currency derivative assets	'		-48
Interest rate and foreign currency derivative assets subtotal	-32		-16
Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	1,876		1,230
Fixed income	'		'
Other investments	13		0
Total assets	5,881		4,533
Deferred compensation obligation	0		0
Total liabilities	0		1
Total net assets	5,881		4,534
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Collateral received from counterparties, net of collateral paid to counterparties	28		6
Fair Value, Inputs, Level 1 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	261		459
Equity	'		'
Individually held	2,569		1,776
Exchange traded funds	170		115
Commingled funds	0		0
Equity funds subtotal	2,739		1,891
Balanced funds - commingled funds	0		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	967		882
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Debt securities issued by foreign governments	0		0
Corporate debt securities	0		0
Federal agency mortgage-backed securities	0		0
Commercial mortgage-backed securities (non-agency)	0		0
Residential mortgage-backed securities (non-agency)	0		0
Mutual funds	0		0
Commingled funds	0		'
Fixed income subtotal	967		882
Middle market lending	0		0
Private Equity	0		0
Other debt obligations	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	0		'
Nuclear decommissioning trust fund investments subtotal	3,967		3,232
Fair Value, Inputs, Level 1 [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Individually held	5		16
Equity funds subtotal	5		16
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	13		45
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Corporate debt securities	0		0
Commingled funds	0		'
Fixed income subtotal	13		45
Middle market lending	0		0
Other debt obligations	'		0
Pledged assets for Zion Station decommissioning subtotal	18		61
Fair Value, Inputs, Level 1 [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		2
Fixed income	'		'
Mutual funds	46		54
Rabbi trust investments subtotal	46		56
Fair Value, Inputs, Level 1 [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	396		493
Proprietary trading	129		324
Effect of netting and allocation of collateral	563		863
Commodity derivative assets subtotal	-38		-46
Fair Value, Inputs, Level 1 [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-458		-540
Proprietary trading	-133		-328
Effect of netting and allocation of collateral	-591		-869
Commodity derivative assets subtotal	0		1
Fair Value, Inputs, Level 1 [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-19		-30
Interest rate and foreign currency derivative assets	'		-30
Interest rate and foreign currency derivative assets subtotal	1		0
Fair Value, Inputs, Level 1 [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-17		-31
Interest rate and foreign currency derivative assets	'		-31
Interest rate and foreign currency derivative assets subtotal	0		0
Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Other investments	0		0
Total assets	6,524		5,575
Deferred compensation obligation	-105		-114
Total liabilities	-214		-269
Total net assets	6,310		5,306
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-105		-114
Collateral received from counterparties, net of collateral paid to counterparties	200		-124
Fair Value, Inputs, Level 2 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	62		0
Equity	'		'
Individually held	0		0
Exchange traded funds	0		0
Commingled funds	2,365		2,271
Equity funds subtotal	2,365		2,271
Balanced funds - commingled funds	273		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0		0
Debt securities issued by states of the United States and political subdivisions of the states	429		294
Debt securities issued by foreign governments	105		87
Corporate debt securities	2,001		1,753
Federal agency mortgage-backed securities	79		10
Commercial mortgage-backed securities (non-agency)	39		40
Residential mortgage-backed securities (non-agency)	3		7
Mutual funds	21		18
Commingled funds	328		'
Fixed income subtotal	3,005		2,209
Middle market lending	0		0
Private Equity	0		0
Other debt obligations	19		14
Fair Value Assets Measured On Recurring Basis Real Estate	0		'
Nuclear decommissioning trust fund investments subtotal	5,724		4,494
Fair Value, Inputs, Level 2 [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	12		26
Equity	'		'
Individually held	2		0
Equity funds subtotal	2		0
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	2		4
Debt securities issued by states of the United States and political subdivisions of the states	19		20
Corporate debt securities	138		227
Commingled funds	4		'
Fixed income subtotal	163		251
Middle market lending	0		0
Other debt obligations	'		1
Pledged assets for Zion Station decommissioning subtotal	177		278
Fair Value, Inputs, Level 2 [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		0
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Fair Value, Inputs, Level 2 [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	2,523		2,582
Proprietary trading	537		1,315
Effect of netting and allocation of collateral	2,472		3,131
Commodity derivative assets subtotal	588		766
Fair Value, Inputs, Level 2 [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-2,194		-1,890
Proprietary trading	-555		-1,256
Effect of netting and allocation of collateral	-2,672		-3,007
Commodity derivative assets subtotal	-77		-139
Fair Value, Inputs, Level 2 [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-5		-2
Interest rate and foreign currency derivative assets	'		-39
Interest rate and foreign currency derivative assets subtotal	-35		-37
Fair Value, Inputs, Level 2 [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-5		-1
Interest rate and foreign currency derivative assets	'		-17
Interest rate and foreign currency derivative assets subtotal	-32		-16
Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Other investments	3		15
Total assets	1,497		1,054
Deferred compensation obligation	0		0
Total liabilities	-431		-305
Total net assets	1,066		749
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Collateral received from counterparties, net of collateral paid to counterparties	231		-26
Fair Value, Inputs, Level 3 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Individually held	0		0
Exchange traded funds	0		0
Commingled funds	0		0
Equity funds subtotal	0		0
Balanced funds - commingled funds	0		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0		0
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Debt securities issued by foreign governments	0		0
Corporate debt securities	235		31
Federal agency mortgage-backed securities	0		0
Commercial mortgage-backed securities (non-agency)	0		0
Residential mortgage-backed securities (non-agency)	0		0
Mutual funds	0		0
Commingled funds	0		'
Fixed income subtotal	235		31
Middle market lending	354		314
Private Equity	54		5
Other debt obligations	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	1		'
Nuclear decommissioning trust fund investments subtotal	644		350
Fair Value, Inputs, Level 3 [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Individually held	0		0
Equity funds subtotal	0		0
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0		0
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Corporate debt securities	0		0
Commingled funds	0		'
Fixed income subtotal	0		0
Middle market lending	166		112
Other debt obligations	'		0
Pledged assets for Zion Station decommissioning subtotal	166		112
Fair Value, Inputs, Level 3 [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		0
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Fair Value, Inputs, Level 3 [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	1,683		885
Proprietary trading	214		122
Effect of netting and allocation of collateral	1,213		430
Commodity derivative assets subtotal	684		577
Fair Value, Inputs, Level 3 [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-1,672		-590
Proprietary trading	-203		-119
Effect of netting and allocation of collateral	-1,444		-404
Commodity derivative assets subtotal	-431		-305
Fair Value, Inputs, Level 3 [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets	'		0
Interest rate and foreign currency derivative assets subtotal	0		0
Fair Value, Inputs, Level 3 [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets	'		0
Interest rate and foreign currency derivative assets subtotal	0		0
Designated as Hedging Instrument [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	25		'
Designated as Hedging Instrument [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Designated as Hedging Instrument [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	25		'
Designated as Hedging Instrument [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-12		'
Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-12		'
Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Derivative [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	12		'
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Mark-to-market derivative liabilities	265		285
Derivative Liability, Current	243		158
Derivative [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Derivative [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	12		'
Derivative [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-22		'
Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-22		'
Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Interest Rate Swap [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	21		'
Interest Rate Swap [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	18		'
Interest Rate Swap [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	3		'
Interest Rate Swap [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-20		'
Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-17		'
Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-3		'
Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	944		1,006
Fixed income	'		'
Other investments	16		15
Total assets	12,922		10,888
Deferred compensation obligation	-29		-29
Total liabilities	-368		-291
Total net assets	12,554		10,597
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-29		-29
Mark-to-market derivative liabilities	104		120
Derivative Liability, Current	235		142
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	323		459
Equity	'		'
Individually held	2,569		1,776
Exchange traded funds	170		115
Commingled funds	2,365		2,271
Equity funds subtotal	5,104		4,162
Balanced funds - commingled funds	273		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	967		882
Debt securities issued by states of the United States and political subdivisions of the states	429		294
Debt securities issued by foreign governments	105		87
Corporate debt securities	2,236		1,784
Federal agency mortgage-backed securities	79		10
Commercial mortgage-backed securities (non-agency)	39		40
Residential mortgage-backed securities (non-agency)	3		7
Mutual funds	21		18
Commingled funds	328		'
Fixed income subtotal	4,207		3,122
Middle market lending	354		314
Private Equity	54		5
Other debt obligations	19		14
Fair Value Assets Measured On Recurring Basis Real Estate	1		'
Nuclear decommissioning trust fund investments subtotal	10,335		8,076
Exelon Generation Co L L C [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	12		26
Equity	'		'
Individually held	7		16
Equity funds subtotal	7		16
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	15		49
Debt securities issued by states of the United States and political subdivisions of the states	19		20
Corporate debt securities	138		227
Commingled funds	4		'
Fixed income subtotal	176		296
Middle market lending	166		112
Other debt obligations	'		1
Pledged assets for Zion Station decommissioning subtotal	361		451
Exelon Generation Co L L C [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		0
Fixed income	'		'
Mutual funds	15		13
Rabbi trust investments subtotal	15		13
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	11		10
Exelon Generation Co L L C [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	4,602		3,960
Proprietary trading	880		1,761
Effect of netting and allocation of collateral	4,248		4,424
Commodity derivative assets subtotal	1,234		1,297
Exelon Generation Co L L C [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-4,146		-2,827
Proprietary trading	-891		-1,703
Effect of netting and allocation of collateral	-4,707		-4,280
Commodity derivative assets subtotal	-330		-250
Exelon Generation Co L L C [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-24		-32
Interest rate and foreign currency derivative assets	'		-62
Interest rate and foreign currency derivative assets subtotal	-17		-30
Exelon Generation Co L L C [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-22		-32
Interest rate and foreign currency derivative assets	'		-44
Interest rate and foreign currency derivative assets subtotal	-9		-12
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	944		1,006
Fixed income	'		'
Other investments	13		0
Total assets	4,918		4,266
Deferred compensation obligation	0		0
Total liabilities	0		1
Total net assets	4,918		4,267
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	261		459
Equity	'		'
Individually held	2,569		1,776
Exchange traded funds	170		115
Commingled funds	0		0
Equity funds subtotal	2,739		1,891
Balanced funds - commingled funds	0		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	967		882
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Debt securities issued by foreign governments	0		0
Corporate debt securities	0		0
Federal agency mortgage-backed securities	0		0
Commercial mortgage-backed securities (non-agency)	0		0
Residential mortgage-backed securities (non-agency)	0		0
Mutual funds	0		0
Commingled funds	0		'
Fixed income subtotal	967		882
Middle market lending	0		0
Private Equity	0		0
Other debt obligations	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	0		'
Nuclear decommissioning trust fund investments subtotal	3,967		3,232
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Individually held	5		16
Equity funds subtotal	5		16
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	13		45
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Corporate debt securities	0		0
Commingled funds	0		'
Fixed income subtotal	13		45
Middle market lending	0		0
Other debt obligations	'		0
Pledged assets for Zion Station decommissioning subtotal	18		61
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		0
Fixed income	'		'
Mutual funds	15		13
Rabbi trust investments subtotal	15		13
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	396		493
Proprietary trading	129		324
Effect of netting and allocation of collateral	563		863
Commodity derivative assets subtotal	-38		-46
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-458		-540
Proprietary trading	-133		-328
Effect of netting and allocation of collateral	-591		-869
Commodity derivative assets subtotal	0		1
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-19		-30
Interest rate and foreign currency derivative assets	'		-30
Interest rate and foreign currency derivative assets subtotal	1		0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 1 [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-17		-31
Interest rate and foreign currency derivative assets	'		-31
Interest rate and foreign currency derivative assets subtotal	0		0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Exchange traded funds	'		0
Commingled funds	'		2,271
Equity funds subtotal	'		2,271
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	'		0
Debt securities issued by states of the United States and political subdivisions of the states	'		294
Debt securities issued by foreign governments	'		87
Corporate debt securities	'		1,753
Federal agency mortgage-backed securities	'		10
Commercial mortgage-backed securities (non-agency)	'		40
Residential mortgage-backed securities (non-agency)	'		7
Mutual funds	'		18
Fixed income subtotal	'		2,209
Middle market lending	'		0
Private Equity	'		0
Other debt obligations	'		14
Nuclear decommissioning trust fund investments subtotal	'		4,494
Other investments	0		0
Total assets	6,507		5,568
Deferred compensation obligation	-29		-29
Total liabilities	-115		-180
Total net assets	6,392		5,388
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-29		-29
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	62		0
Equity	'		'
Individually held	0		0
Exchange traded funds	0		'
Commingled funds	2,365		'
Equity funds subtotal	2,365		'
Balanced funds - commingled funds	273		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0		'
Debt securities issued by states of the United States and political subdivisions of the states	429		'
Debt securities issued by foreign governments	105		'
Corporate debt securities	2,001		'
Federal agency mortgage-backed securities	79		'
Commercial mortgage-backed securities (non-agency)	39		'
Residential mortgage-backed securities (non-agency)	3		'
Mutual funds	21		'
Commingled funds	328		'
Fixed income subtotal	3,005		'
Middle market lending	0		'
Private Equity	0		'
Other debt obligations	19		'
Fair Value Assets Measured On Recurring Basis Real Estate	0		'
Nuclear decommissioning trust fund investments subtotal	5,724		'
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	12		26
Equity	'		'
Individually held	2		0
Equity funds subtotal	2		0
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	2		4
Debt securities issued by states of the United States and political subdivisions of the states	19		20
Corporate debt securities	138		227
Commingled funds	4		'
Fixed income subtotal	163		251
Middle market lending	0		0
Other debt obligations	'		1
Pledged assets for Zion Station decommissioning subtotal	177		278
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		0
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Commodity derivative assets subtotal	'		766
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	2,523		2,582
Proprietary trading	537		1,315
Effect of netting and allocation of collateral	2,472		3,131
Commodity derivative assets subtotal	588		'
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-2,194		-1,890
Proprietary trading	-555		-1,256
Effect of netting and allocation of collateral	-2,672		-3,007
Commodity derivative assets subtotal	-77		-139
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-5		-2
Interest rate and foreign currency derivative assets	'		-32
Interest rate and foreign currency derivative assets subtotal	-18		-30
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 2 [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	-5		-1
Interest rate and foreign currency derivative assets	'		-13
Interest rate and foreign currency derivative assets subtotal	-9		-12
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Other investments	3		15
Total assets	1,497		1,054
Deferred compensation obligation	0		0
Total liabilities	-253		-112
Total net assets	1,244		942
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Nuclear Decommissioning Trust Fund Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Individually held	0		0
Exchange traded funds	0		0
Commingled funds	0		0
Equity funds subtotal	0		0
Balanced funds - commingled funds	0		'
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0		0
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Debt securities issued by foreign governments	0		0
Corporate debt securities	235		31
Federal agency mortgage-backed securities	0		0
Commercial mortgage-backed securities (non-agency)	0		0
Residential mortgage-backed securities (non-agency)	0		0
Mutual funds	0		0
Commingled funds	0		'
Fixed income subtotal	235		31
Middle market lending	354		314
Private Equity	54		5
Other debt obligations	0		0
Fair Value Assets Measured On Recurring Basis Real Estate	1		'
Nuclear decommissioning trust fund investments subtotal	644		350
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Equity	'		'
Individually held	0		0
Equity funds subtotal	0		0
Fixed income	'		'
Debt securities issued by the U.S. Treasury and other U.S. government corporations and agencies	0		0
Debt securities issued by states of the United States and political subdivisions of the states	0		0
Corporate debt securities	0		0
Commingled funds	0		'
Fixed income subtotal	0		0
Middle market lending	166		112
Other debt obligations	'		0
Pledged assets for Zion Station decommissioning subtotal	166		112
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Rabbi Trust Investments [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	'		0
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Commodity Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Economic hedges	1,683		885
Proprietary trading	214		122
Effect of netting and allocation of collateral	1,213		430
Commodity derivative assets subtotal	684		577
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Commodity Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Economic hedges	-1,494		-397
Proprietary trading	-203		-119
Effect of netting and allocation of collateral	-1,444		-404
Commodity derivative assets subtotal	-253		-112
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Interest Rate Mark To Market Derivative Assets [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets	'		0
Interest rate and foreign currency derivative assets subtotal	0		0
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Interest Rate Mark To Market Derivative Liabilities [Member]	'		'
Fixed income	'		'
Effect of netting and allocation of collateral	0		0
Interest rate and foreign currency derivative assets	'		0
Interest rate and foreign currency derivative assets subtotal	0		0
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	13		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	13		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-2		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-2		'
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Derivative [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	7		'
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Mark-to-market derivative liabilities	101	[1]	109	[2]
Derivative Liability, Current	229	[1]	141	[2]
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	7		'
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-9		'
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-9		'
Exelon Generation Co L L C [Member] \| Derivative [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	21		'
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Derivative Liability, Current	1		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	18		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	3		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	0		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-20		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-17		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-3		'
Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Derivative Financial Instruments, Liabilities [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fixed income	'		'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	0		'
PECO Energy Co [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	304		175
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	313		184
Deferred compensation obligation	-15		-17
Total liabilities	-15		-17
Total net assets	298		167
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-15		-17
Cash surrender value of life insurance investments excluded from Rabbi Trust investments	14		14
PECO Energy Co [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	9		9
Rabbi trust investments subtotal	9		9
PECO Energy Co [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	304		175
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	313		184
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	313		184
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
PECO Energy Co [Member] \| Fair Value, Inputs, Level 1 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	9		9
Rabbi trust investments subtotal	9		9
PECO Energy Co [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	-15		-17
Total liabilities	-15		-17
Total net assets	-15		-17
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-15		-17
PECO Energy Co [Member] \| Fair Value, Inputs, Level 2 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
PECO Energy Co [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		0
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
PECO Energy Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Commonwealth Edison Co [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	178		193
Total assets	0		5
Deferred compensation obligation	-8		-8
Total liabilities	-186		-201
Total net assets	-186		-196
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-8		-8
Mark-to-market derivative liabilities	164		176
Derivative Liability, Current	14		17
Commonwealth Edison Co [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		5
Rabbi trust investments subtotal	0		5
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	0		5
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		5
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 1 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		5
Rabbi trust investments subtotal	0		5
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	-8		-8
Total liabilities	-8		-8
Total net assets	-8		-8
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-8		-8
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 2 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	178		193
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	-178		-193
Total net assets	-178		-193
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Baltimore Gas and Electric Company [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	5		31
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	10		37
Deferred compensation obligation	-5		0
Total liabilities	-5		-6
Total net assets	5		31
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-5		0
Baltimore Gas and Electric Company [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	5		6
Rabbi trust investments subtotal	5		6
Baltimore Gas and Electric Company [Member] \| Fair Value, Inputs, Level 1 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	5		31
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	10		37
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	10		37
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Baltimore Gas and Electric Company [Member] \| Fair Value, Inputs, Level 1 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	5		6
Rabbi trust investments subtotal	5		6
Baltimore Gas and Electric Company [Member] \| Fair Value, Inputs, Level 2 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	-5		-6
Total liabilities	-5		-6
Total net assets	-5		-6
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	-5		-6
Baltimore Gas and Electric Company [Member] \| Fair Value, Inputs, Level 2 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	0		0
Baltimore Gas and Electric Company [Member] \| Fair Value, Inputs, Level 3 [Member]	'		'
Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]	'		'
Cash equivalents	0		0
Fixed income	'		'
Commodity derivative assets subtotal	0		0
Total assets	0		0
Deferred compensation obligation	0		0
Total liabilities	0		0
Total net assets	0		0
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis [Abstract]	'		'
Deferred compensation	0		0
Baltimore Gas and Electric Company [Member] \| Fair Value, Inputs, Level 3 [Member] \| Rabbi Trust Investments [Member]	'		'
Fixed income	'		'
Mutual funds	0		0
Rabbi trust investments subtotal	$0		$0

[1]	Current and noncurrent assets are shown net of collateral of $(96) million and $(50) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(205) million and $(108) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $459 million at SeptemberB 30, 2014.
[2]	Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at DecemberB 31, 2013.

Fair_Value_of_Financial_Assets4

Fair Value of Financial Assets and Liabilities - Fair Value Assets Liabilities Measured On Recurring Basis Unobservable Input Reconciliation (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Exelon Generation Co L L C [Member]	'	'	'	'
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]	'	'	'	'
Gain (loss) reclassified to results of operating due to the settlement of derivative contracts	$87	$83	$20	$156
Exelon Generation Co L L C [Member] \| Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]	'	'	'	'
Purchases, sales, issuances and settlements	'	'	'	'
Settlements	'	'	'	-11
Fair Value, Inputs, Level 3 [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	843	793	749	656
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	77	-32	-279	-6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	-219
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	3	-1	14	234
Included in payable for Zion Station decommissioning	2	0	-2	-1
Included in noncurrent payables to affiliates	-44	-37	15	-55
Change in collateral	-79	30	-257	-13
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	148	41	455	151
Sales	-33	-29	-66	-70
Settlements	-27	-3	-46	-11
Transfers into Level 3	-21	-4	9	-11
Transfers out of Level 3	1	-5	-26	-4
Ending balance	1,066	701	1,066	701
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	164	51	-261	160
Fair Value, Inputs, Level 3 [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	977	878	942	949
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	77	-32	-279	-6
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	-219
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	3	-1	14	8
Included in payable for Zion Station decommissioning	2	0	-2	-1
Included in noncurrent payables to affiliates	0	0	0	0
Change in collateral	-79	30	-257	-13
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	148	41	455	151
Sales	-33	-29	-66	-70
Settlements	-27	-3	-46	-11
Transfers into Level 3	-21	-4	9	-11
Transfers out of Level 3	1	-5	-26	-4
Ending balance	1,244	823	1,244	823
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	164	51	-261	149
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]	'	'	'	'
Decrease in Fair Value Adjustment	'	'	'	11
Fair Value, Inputs, Level 3 [Member] \| Exelon Generation Co L L C [Member] \| Nuclear Decommissioning Trust Fund Investment Level Three Asset [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	592	240	350	183
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	1	0	5	2
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	3	-1	14	8
Included in payable for Zion Station decommissioning	0	0	0	0
Included in noncurrent payables to affiliates	0	'	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	83	23	331	90
Sales	-8	-14	-10	-27
Settlements	-27	-3	-46	'
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Ending balance	644	245	644	245
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	1	0	3	1
Fair Value, Inputs, Level 3 [Member] \| Exelon Generation Co L L C [Member] \| Pledged Assets For Zion Station Decommissioning [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	133	111	112	89
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	0	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0	0	0	0
Included in payable for Zion Station decommissioning	2	0	-2	-1
Included in noncurrent payables to affiliates	0	0	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	53	10	95	43
Sales	-18	-15	-43	-27
Settlements	0	0	0	0
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Ending balance	166	106	166	106
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	0	0	0	0
Fair Value, Inputs, Level 3 [Member] \| Exelon Generation Co L L C [Member] \| Derivative [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	242	516	465	660
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	76	-32	-284	-8
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	-219
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0	0	0	0
Included in payable for Zion Station decommissioning	0	0	0	0
Included in noncurrent payables to affiliates	0	0	0	0
Change in collateral	-79	30	-257	-13
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	12	8	27	16
Sales	0	0	-6	-8
Settlements	0	0	0	0
Transfers into Level 3	-21	-4	9	-11
Transfers out of Level 3	1	-5	-19	-4
Ending balance	431	461	431	461
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	163	51	-264	148
Fair Value, Inputs, Level 3 [Member] \| Exelon Generation Co L L C [Member] \| Other Investments [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	10	11	15	17
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	0	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0	0	0	0
Included in payable for Zion Station decommissioning	0	0	0	0
Included in noncurrent payables to affiliates	0	0	0	0
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	0	0	2	2
Sales	-7	0	-7	-8
Settlements	0	0	0	0
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	-7	0
Ending balance	3	11	3	11
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	0	0	0	0
Fair Value, Inputs, Level 3 [Member] \| Commonwealth Edison Co [Member]	'	'	'	'
Purchases, sales, issuances and settlements	'	'	'	'
Settlements	1	1	4	5
Footnotes To Fair Value Assets And Liabilities Measured On Recurring Basis Unobservable Input Reconciliation [Abstract]	'	'	'	'
Decrease in Fair Value Adjustment	'	'	19	'
Increase In Fair Value Adjustment	45	37	'	57
Fair Value, Inputs, Level 3 [Member] \| Commonwealth Edison Co [Member] \| Derivative [Member]	'	'	'	'
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]	'	'	'	'
Beginning balance	-134	-85	-193	-293
Total realized / unrealized gains (losses)	'	'	'	'
Included in net income	0	0	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Gain (Loss) Included in Other Comprehensive Income (Loss)	'	'	'	0
Fair Value Measurement With Unobservable Inputs Reconciliation Recurring Basis Included In Noncurrent Payables To Affiliates	0	0	0	226
Included in payable for Zion Station decommissioning	0	0	0	0
Included in noncurrent payables to affiliates	-44	-37	15	-55
Change in collateral	0	0	0	0
Purchases, sales, issuances and settlements	'	'	'	'
Purchases	0	0	0	0
Sales	0	0	0	0
Settlements	0	0	0	0
Transfers into Level 3	0	0	0	0
Transfers out of Level 3	0	0	0	0
Ending balance	-178	-122	-178	-122
The amount of total losses included in income attributed to the change in unrealized gains (losses) related to assets and liabilities held	0	0	0	11
Interest Rate Swap [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Purchases, sales, issuances and settlements	'	'	'	'
Settlements	'	'	'	$215

Fair_Value_of_Financial_Assets5

Fair Value of Financial Assets and Liabilities Fair Value of Financial Assets and Liabilities - Narrative (Details) (USD $)	Sep. 30, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Forward Power Basis	$3.57
Forward Gas Basis	0.45
Exelon Generation Co L L C [Member]	'
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]	'
Fair Value, Investments, Entities that Calculate Net Asset Value Per Share, Unfunded Commitments	$344,000,000

Fair_Value_of_Financial_Assets6

Fair Value of Financial Assets and Liabilities - Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Operating Revenue [Member]	'	'	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]	'	'	'	'
Total gains (losses) included in income	$70	($39)	($260)	($61)
Change in the unrealized gains (losses) relating to assets and liabilities held	142	42	-293	81
Purchased Fuel and Electric [Member]	'	'	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]	'	'	'	'
Total gains (losses) included in income	6	7	-24	60
Change in the unrealized gains (losses) relating to assets and liabilities held	21	9	29	78
Other, net [Member]	'	'	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]	'	'	'	'
Total gains (losses) included in income	1	0	5	2
Change in the unrealized gains (losses) relating to assets and liabilities held	1	0	3	1
Exelon Generation Co L L C [Member] \| Operating Revenue [Member]	'	'	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]	'	'	'	'
Total gains (losses) included in income	70	-39	-260	-67
Change in the unrealized gains (losses) relating to assets and liabilities held	142	42	-293	71
Exelon Generation Co L L C [Member] \| Purchased Fuel and Electric [Member]	'	'	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]	'	'	'	'
Total gains (losses) included in income	6	7	-24	59
Change in the unrealized gains (losses) relating to assets and liabilities held	21	9	29	77
Exelon Generation Co L L C [Member] \| Other, net [Member]	'	'	'	'
Fair Value Assets And Liabilities Measured On Recurring Basis Gain Loss Included In Earnings [Line Items]	'	'	'	'
Total gains (losses) included in income	1	0	5	2
Change in the unrealized gains (losses) relating to assets and liabilities held	$1	$0	$3	$1

Fair_Value_of_Financial_Assets7

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2014	Dec. 31, 2013
Derivatives Fair Value Footnotes [Abstract]	'	'
Cash collateral excluded	231,000,000	'
Fair Value, Inputs, Level 3 [Member]	'	'
Derivatives Fair Value Footnotes [Abstract]	'	'
Cash collateral excluded	'	26,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	189,000,000	488,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Forward power price assets	13,000,000	8
Forward gas price assets	2.54	2.98
Volatility percentage	'	14.00%
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Forward power price assets	194	176
Forward gas price assets	22.15	16.63
Volatility percentage	'	19.00%
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Minimum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Volatility percentage	8.00%	15.00%
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Option Model Valuation Technique [Member] \| Maximum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Volatility percentage	154.00%	142.00%
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	-11,000,000	-3,000,000
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Forward power price assets	14,000,000	10
Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Forward power price assets	191	176
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member]	'	'
Derivatives, Fair Value [Line Items]	'	'
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	178,000,000	193,000,000
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Minimum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Marketability Reserve	3.50%	3.50%
Forward heat rate	-8.00%	-8.00%
Renewable factor	86.00%	84.00%
Commonwealth Edison Co [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Marketability Reserve	8.00%	8.00%
Forward heat rate	-9.00%	-9.00%
Renewable factor	126.00%	128.00%
All Regions excluding New England [Member] \| Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Derivative [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Forward power price assets	146	100
Forward gas price assets	10.62	5.7
All Regions excluding New England [Member] \| Exelon Generation Co L L C [Member] \| Fair Value, Inputs, Level 3 [Member] \| Proprietary Trading [Member] \| Discounted Cash Flow [Member] \| Maximum [Member]	'	'
Fair Value Inputs [Abstract]	'	'
Forward power price assets	104	'

Derivative_Financial_Instrumen2

Derivative Financial Instruments - Summary of Interest Rate and Foreign Currency Hedges (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	$4		($1)
Mark-to-market derivative assets (noncurrent assets)	30		38
Total mark-to-market derivative assets	34		37
Mark-to-market derivative liabilities (current liabilities)	-6		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-26		-15
Total mark-to-market derivative liabilities	-32		-16
Total mark-to-market derivative net assets (liabilities)	2		21
Exelon Generation Co L L C [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	4		-1
Mark-to-market derivative assets (noncurrent assets)	13		31
Total mark-to-market derivative assets	17		30
Mark-to-market derivative liabilities (current liabilities)	-6		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-3		-11
Total mark-to-market derivative liabilities	-9		-12
Total mark-to-market derivative net assets (liabilities)	8		18
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets (noncurrent assets)	13		26
Total mark-to-market derivative assets	13		26
Mark-to-market derivative liabilities (current liabilities)	-1		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-1		-10
Total mark-to-market derivative liabilities	-2		-11
Total mark-to-market derivative net assets (liabilities)	11		15
Exelon Generation Co L L C [Member] \| Derivative [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	4		3
Mark-to-market derivative assets (noncurrent assets)	3		3
Total mark-to-market derivative assets	7		6
Mark-to-market derivative liabilities (current liabilities)	-7		-1
Mark-to-market derivative liabilities (noncurrent liabilities)	-2		-1
Total mark-to-market derivative liabilities	-9		-2
Total mark-to-market derivative net assets (liabilities)	-2		4
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	14		15
Mark-to-market derivative assets (noncurrent assets)	7		15
Total mark-to-market derivative assets	21	[1]	30	[1]
Mark-to-market derivative liabilities (current liabilities)	-11		-18
Mark-to-market derivative liabilities (noncurrent liabilities)	-9		-13
Total mark-to-market derivative liabilities	-20	[1]	-31	[1]
Total mark-to-market derivative net assets (liabilities)	1		-1	[1]
Exelon Generation Co L L C [Member] \| Collateral And Netting [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	-14		-19
Mark-to-market derivative assets (noncurrent assets)	-10		-13
Total mark-to-market derivative assets	-24	[2]	-32	[2]
Mark-to-market derivative liabilities (current liabilities)	13		19
Mark-to-market derivative liabilities (noncurrent liabilities)	9		13
Total mark-to-market derivative liabilities	22	[2]	32	[2]
Total mark-to-market derivative net assets (liabilities)	-2	[2]	0
Corporate, Non-Segment [Member] \| Designated as Hedging Instrument [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets (noncurrent assets)	12		7
Total mark-to-market derivative assets	12		7
Mark-to-market derivative liabilities (current liabilities)	0		0
Mark-to-market derivative liabilities (noncurrent liabilities)	-10		-4
Total mark-to-market derivative liabilities	-10		-4
Total mark-to-market derivative net assets (liabilities)	2		3
Corporate, Non-Segment [Member] \| Derivative [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	0		'
Mark-to-market derivative assets (noncurrent assets)	5		'
Total mark-to-market derivative assets	5		'
Mark-to-market derivative liabilities (current liabilities)	0		'
Mark-to-market derivative liabilities (noncurrent liabilities)	-13		'
Total mark-to-market derivative liabilities	-13		'
Total mark-to-market derivative net assets (liabilities)	($8)		'

[1]	Generation enters into interest rate derivative contracts to economically hedge risk associated with theB interest rate component of commodity positions.B 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.B 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_Instrumen3

Derivative Financial Instruments - Summary of Gains and Losses on Hedges (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Derivative [Line Items]	'		'		'		'
Derivative, Loss on Derivative	'		$0		'		($12)
Derivative, Gain on Derivative	'		-6		'		-2
Derivative, Net Hedge Ineffectiveness Gain (Loss)	'		'		2		'
Exelon Generation Co L L C [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Derivative, Loss on Derivative	1	[1]	-1	[1]	1	[1]	0	[1]
Fair Value Hedging [Member] \| Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Derivative, Gain on Derivative	-8		'		-3		'
Fair Value Hedging [Member] \| Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Derivative, Loss on Derivative	-4	[1]	-4	[1]	-12	[1]	-13	[1]
Interest Expense [Member] \| Fair Value Hedging [Member] \| Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Derivative, Gain on Derivative	-6		'		6		'
Interest Expense [Member] \| Fair Value Hedging [Member] \| Exelon Generation Co L L C [Member] \| Interest Rate Swap [Member] \| Designated as Hedging Instrument [Member]	'		'		'		'
Derivative [Line Items]	'		'		'		'
Gain (Loss) on Fair Value Hedges Recognized in Earnings	($4)		($4)		($12)		($12)

[1]	For the three and nine months ended SeptemberB 30, 2014, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with $2 million amount excluded from hedge effectiveness testing.

Derivative_Financial_Instrumen4

Derivative Financial Instruments Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	$744		$727
Mark-to-market derivative assets (noncurrent assets)	524		607
Mark-to-market derivative liabilities (current liabilities)	-249		-159
Mark-to-market derivative liabilities (noncurrent liabilities)	-291		-300
Derivative [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	740		728
Mark-to-market derivative assets (noncurrent assets)	494		569
Total mark-to-market derivative assets	1,234		1,297
Mark-to-market derivative liabilities (current liabilities)	-243		-158
Mark-to-market derivative liabilities (noncurrent liabilities)	-265		-285
Total mark-to-market derivative liabilities	-508		-443
Total mark-to-market derivative net assets (liabilities)	726		854
Exelon Generation Co L L C [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	744		727
Mark-to-market derivative assets (noncurrent assets)	507		600
Mark-to-market derivative liabilities (current liabilities)	-235		-142
Mark-to-market derivative liabilities (noncurrent liabilities)	-104		-120
Exelon Generation Co L L C [Member] \| Designated as Hedging Instrument [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	3,230		2,616
Mark-to-market derivative assets (noncurrent assets)	1,372		1,344
Total mark-to-market derivative assets	4,602		3,960
Mark-to-market derivative liabilities (current liabilities)	-3,017		-2,023
Mark-to-market derivative liabilities (noncurrent liabilities)	-1,129		-804
Total mark-to-market derivative liabilities	-4,146		-2,827
Total mark-to-market derivative net assets (liabilities)	456		1,133
Current assets collateral offset	-96		84
Noncurrent assets collateral offset	-50		72
Current liabilities collateral offset	-205		-12
Noncurrent liabilities collateral offset	-108		0
Total cash collateral received net of cash collateral posted	-459		-144
Exelon Generation Co L L C [Member] \| Derivative [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	740	[1]	728	[2]
Mark-to-market derivative assets (noncurrent assets)	494	[1]	569	[2]
Total mark-to-market derivative assets	1,234	[1]	1,297	[2]
Mark-to-market derivative liabilities (current liabilities)	-229	[1]	-141	[2]
Mark-to-market derivative liabilities (noncurrent liabilities)	-101	[1]	-109	[2]
Total mark-to-market derivative liabilities	-330	[1]	-250	[2]
Total mark-to-market derivative net assets (liabilities)	904	[1]	1,047	[2]
Exelon Generation Co L L C [Member] \| Proprietary Trading [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	752		1,476
Mark-to-market derivative assets (noncurrent assets)	128		285
Total mark-to-market derivative assets	880		1,761
Mark-to-market derivative liabilities (current liabilities)	-755		-1,410
Mark-to-market derivative liabilities (noncurrent liabilities)	-136		-293
Total mark-to-market derivative liabilities	-891		-1,703
Total mark-to-market derivative net assets (liabilities)	-11		58
Exelon Generation Co L L C [Member] \| Collateral And Netting [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	-3,242		-3,364
Mark-to-market derivative assets (noncurrent assets)	-1,006		-1,060
Total mark-to-market derivative assets	-4,248	[3]	-4,424	[3]
Mark-to-market derivative liabilities (current liabilities)	3,543		3,292
Mark-to-market derivative liabilities (noncurrent liabilities)	1,164		988
Total mark-to-market derivative liabilities	4,707	[3]	4,280	[3]
Total mark-to-market derivative net assets (liabilities)	459	[3]	-144	[3]
Commonwealth Edison Co [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative liabilities (current liabilities)	-14		-17
Mark-to-market derivative liabilities (noncurrent liabilities)	-164		-176
Commonwealth Edison Co [Member] \| Designated as Hedging Instrument [Member]	'		'
Derivative [Line Items]	'		'
Mark-to-market derivative assets (current assets)	0		0
Mark-to-market derivative assets (noncurrent assets)	0		0
Total mark-to-market derivative assets	0	[4]	0	[4]
Mark-to-market derivative liabilities (current liabilities)	-14		-17
Mark-to-market derivative liabilities (noncurrent liabilities)	-164		-176
Total mark-to-market derivative liabilities	-178	[4]	-193	[4]
Total mark-to-market derivative net assets (liabilities)	($178)	[4]	($193)	[4]

[1]	Current and noncurrent assets are shown net of collateral of $(96) million and $(50) million, respectively, and current and noncurrent liabilities are shown net of collateral of $(205) million and $(108) million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $459 million at SeptemberB 30, 2014.
[2]	Current and noncurrent assets are shown net of collateral of $84 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of $(12) million and $0 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was $144 million at DecemberB 31, 2013.
[3]	Exelon and Generation net all available amounts allowed under the derivative accounting guidance on the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral.B In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These are not reflected in the table above.
[4]	Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.

Derivative_Financial_Instrumen5

Derivative Financial Instruments - Summary of AOCI related to Cash Flow Hedges (Details) (USD $)	3 Months Ended				9 Months Ended				12 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013	Dec. 31, 2012
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]	'		'		'		'		'	'
Reclassifications from accumulated OCI to net income	'		'		'		$133		'	'
Net gain (loss) related to ineffective portion of changes in fair value of treasury rate locks	'		'		'		11		'	20
Effective Portion Of Change In Fair Value Of Treasury Rate Lock Net Of Tax	13		2		13		25		5	'
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, Net of Tax	12		33		52		215		'	'
Exelon Generation Co L L C [Member]	'		'		'		'		'	'
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]	'		'		'		'		'	'
Reclassifications from accumulated OCI to net income	4,300		3,871		11,944		10,729		'	'
Energy Related 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	57		255		119		532		532	'
Effective portion of changes in fair value	0		0		0		0		'	'
Accumulated OCI derivative gain - Ending Balance	41	[1]	204	[2],[3]	41	[1]	204	[2],[3]	'	'
Energy Related Hedges [Member] \| Operating Revenue One [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| 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		-51		-78		-328		'	'
Total Cash Flow Hedges [Member]	'		'		'		'		'	'
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]	'		'		'		'		'	'
Accumulated OCI derivative gain - Beginning Balance	47		245		120		368		368	'
Effective portion of changes in fair value	-3		2		-14		25		'	'
Accumulated OCI derivative gain - Ending Balance	28		199		28		199		'	368
Effective Portion Of Change In Fair Value Of Treasury Rate Lock Net Of Tax	'		'		'		'		'	-133
Total Cash Flow Hedges [Member] \| Operating Revenue One [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member]	'		'		'		'		'	'
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]	'		'		'		'		'	'
Reclassifications from accumulated OCI to net income	-16		-48		-78		-194		'	'
Interest Rate Contract [Member] \| Energy Related Hedges [Member] \| Exelon Generation Co L L C [Member]	'		'		'		'		'	'
Effect of Hedges on Accumulated Other Comprehensive Income [Roll Forward]	'		'		'		'		'	'
Accumulated OCI derivative gain - Ending Balance	'		$11		'		$11		'	'

[1]	Excludes $13 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of SeptemberB 30, 2014 and JuneB 30, 2014.
[2]	Amount is net of related income tax expense of $33 million for the three months ended September 30, 2013.
[3]	Excludes $11 million of losses, net of taxes, related to interest rate swaps and treasury rate locks as of SeptemberB 30, 2013 and June 30, 2013

Derivative_Financial_Instrumen6

Derivative Financial Instruments - Summary of Economic Hedges (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative [Line Items]	'	'	'	'
Change in fair value	$200	$180	($493)	$217
Reclassification to realized at settlement	63	66	17	61
Net mark-to-market gains (losses)	263	246	-476	278
Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	200	180	-493	223
Reclassification to realized at settlement	63	66	17	48
Net mark-to-market gains (losses)	263	246	-476	271
Other Segments [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	-6	'	-12	-3
Reclassification to realized at settlement	-1	'	-2	0
Net mark-to-market gains (losses)	256	246	-490	275
Purchased Power [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	2	0	-4	-3
Reclassification to realized at settlement	-1	0	-2	0
Net mark-to-market gains (losses)	264	'	-482	268
Operating Revenue One [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	'	'	'	134
Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	19	5	302	74
Reclassification to realized at settlement	-23	25	-207	63
Net mark-to-market gains (losses)	-4	30	95	137
Interest Expense [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	0	0	0	0
Reclassification to realized at settlement	0	0	0	0
Net mark-to-market gains (losses)	0	0	0	0
Interest Expense [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	0	'	'	0
Operating Revenue [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	0	0	0	-6
Reclassification to realized at settlement	0	0	0	13
Net mark-to-market gains (losses)	0	0	0	7
Operating Revenue [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	181	175	-795	149
Reclassification to realized at settlement	86	41	224	-15
Net mark-to-market gains (losses)	267	216	-571	134
Interest Rate Swap [Member] \| Other Segments [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	-8	0	-8	0
Reclassification to realized at settlement	0	0	0	0
Net mark-to-market gains (losses)	-8	0	-8	0
Interest Expense [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	-3	0	-5	-3
Reclassification to realized at settlement	0	0	0	0
Net mark-to-market gains (losses)	-3	0	-5	-3
Interest Expense [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	'	'	'	0
Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	0	0	0	0
Reclassification to realized at settlement	0	0	0	'
Net mark-to-market gains (losses)	-4	30	95	137
Operating Revenue [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	0	0	0	0
Reclassification to realized at settlement	0	0	0	'
Net mark-to-market gains (losses)	0	'	0	7
Operating Revenue [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	5	0	1	0
Reclassification to realized at settlement	-1	0	-2	'
Net mark-to-market gains (losses)	271	'	-572	'
Operating Revenue [Member] \| Operating Revenue [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	'	'	'	0
Operating Revenue [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Change in fair value	'	'	'	0
Interest Rate Swap [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	'	0	'	'
Interest Rate Swap [Member] \| Other Segments [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	-7	'	-14	-3
Interest Rate Swap [Member] \| Purchased Power [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	1	0	-6	-3
Interest Rate Swap [Member] \| Interest Rate Swap [Member] \| Other Segments [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	-8	0	-8	0
Interest Rate Swap [Member] \| Interest Expense [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	-3	0	-5	-3
Interest Rate Swap [Member] \| Purchased Power And Fuel [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	0	0	0	0
Interest Rate Swap [Member] \| Operating Revenue [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	0	0	0	0
Interest Rate Swap [Member] \| Operating Revenue [Member] \| Exelon Generation Co L L C [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Net mark-to-market gains (losses)	$4	'	($1)	$0

Derivative_Financial_Instrumen7

Derivative Financial Instruments - Summary of Proprietary Trading Activities (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Derivative [Line Items]	'	'	'	'
Proprietary Trading Activities Change In Fair Value	$1	$0	$0	$0
Proprietary Trading Activities Reclassification To Realized At Settlement	0	-1	1	-2
Proprietary Trading Activities Gain Loss Net	-11	-40	-18	-35
Operating Revenue [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Proprietary Trading Activities Change In Fair Value	-2	0	-2	1
Proprietary Trading Activities Reclassification To Realized At Settlement	-10	-39	-17	-34
Proprietary Trading Activities Gain Loss Net	-12	-39	-19	-33
Interest Rate Swap [Member] \| Operating Revenue [Member]	'	'	'	'
Derivative [Line Items]	'	'	'	'
Proprietary Trading Activities Gain Loss Net	$1	($1)	$1	($2)

Derivative_Financial_Instrumen8

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) (Exelon Generation Co L L C [Member], USD $)	Sep. 30, 2014
In Millions, unless otherwise specified	Sep. 30, 2014
Derivative [Line Items]	'
Investor-owned utilities, marketers and power producers	$264
Energy cooperative and municipalities	470
Financial institutions	749
Other	10
Net Exposure [Member]	'
Derivative [Line Items]	'
Investment grade	1,152
Non-investment grade	16
No external ratings - internally rated - investment grade	302
No external ratings - internally rated - non-investment grade	23
Total	1,493
Total Exposure Before Credit Collateral [Member]	'
Derivative [Line Items]	'
Investment grade	1,240
Non-investment grade	23
No external ratings - internally rated - investment grade	302
No external ratings - internally rated - non-investment grade	26
Total	1,591
Credit Collateral [Member]	'
Derivative [Line Items]	'
Investment grade	88
Non-investment grade	7
No external ratings - internally rated - investment grade	0
No external ratings - internally rated - non-investment grade	3
Total	98	[1]
Number Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]	'
Derivative [Line Items]	'
Investment grade	1
Non-investment grade	0
No external ratings - internally rated - investment grade	1
No external ratings - internally rated - non-investment grade	0
Total	2
Net Exposure Of Counterparties Greater Than Ten Percent Of Net Exposure [Member]	'
Derivative [Line Items]	'
Investment grade	423
Non-investment grade	0
No external ratings - internally rated - investment grade	180
No external ratings - internally rated - non-investment grade	0
Total	$603

[1]	As of SeptemberB 30, 2014, credit collateral held from counterparties where Generation had credit exposure included $94 million of cash and $4 million of letters of credit.

Derivative_Financial_Instrumen9

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) (Exelon Generation Co L L C [Member], USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Exelon Generation Co L L C [Member]	'		'
Derivative [Line Items]	'		'
Aggregate fair value of derivatives with credit-risk-related contingent features	($997)		($1,056)
Contractual right of offset related to derivative assets	694		846
Net liability position after contractual right of offset	($303)	[1]	($210)	[1]

[1]	Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.

Recovered_Sheet2

Derivative Financial Instruments - Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

12 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Feb. 06, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Designated as Hedging Instrument [Member]

Exelon Generation Co L L C [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Minimum [Member]

Maximum [Member]

Interest Rate Swap [Member]

Interest Rate Contract [Member]

Foreign Exchange Contract [Member]

Fair Value Hedging [Member]

Cash Flow Hedging [Member]

Antelope Valle [Member]

Other Solar Projects [Member]

PHI Merger [Member]

ExGen Texas Power [Member]

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

Commonwealth Edison Co Affiliate [Member]

PECO Energy Co Affiliate [Member]

Baltimore Gas And Electric Company Affiliate [Member]

GWh

Derivative [Member]

Designated as Hedging Instrument [Member]

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Derivative [Member]

Exelon Generation Co L L C [Member]

Interest Rate Swap [Member]

Interest Rate Contract [Member]

Cash Flow Hedging [Member]

Exelon Generation Co L L C [Member]

Cash Flow Hedging [Member]

Interest Rate Swap [Member]

Cash Flow Hedging [Member]

Reclassification out of Accumulated Other Comprehensive Income [Member]

Exelon Generation Co L L C [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Derivative [Member]

Designated as Hedging Instrument [Member]

Exelon Generation Co L L C [Member]

Designated as Hedging Instrument [Member]

Exelon Generation Co L L C [Member]

Derivative [Member]

Designated as Hedging Instrument [Member]

Interest Rate Contract [Member]

Designated as Hedging Instrument [Member]

Interest Rate Contract [Member]

Designated as Hedging Instrument [Member]

Exelon Generation Co L L C [Member]

Designated as Hedging Instrument [Member]

Derivative [Line Items]

Hypothetical Increase In Interest Rates

0.50%

Expected Generation Hedged In Next Twelve Months

98.00%

101.00%

Expected Generation Hedged In Year Two

86.00%

89.00%

Expected generation hedged in year three

55.00%

58.00%

Estimated percentage of natural gas purchases hedged

30.00%

10.00%

20.00%

Proprietary trading activities volume

3,006

2,499

8,129

6,066

Derivative, Notional Amount

$1,600

$240

$700

$150

$97

$322

$1,450

$1,275

$1,250

$505

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

2,431

781

400

Hypothetical increase in interest rates associated with variable-rate debt

Increase In Notional Amount Of Derivative Instruments

100

222

Increase In Notional Amount Of Derivative Instruments1

Interest rate swaps previously held by acquiree

550

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

Ineffective portion recognized in income

[1]

DOE interest rate swap

485

Unrealized Gain (Loss) on Interest Rate Cash Flow Hedges, Pretax, Accumulated Other Comprehensive Income (Loss)

Notional amounts on forward starting interest rate swaps

Mark-to-market derivative liabilities (noncurrent liabilities)

291

300

104

120

164

176

Interest Rate Derivative Assets Noncurrent

Derivative Liability, Current

249

159

235

142

Cash collateral received not offset against net derivative positions

Credit exposure under natural gas supply and management agreements

Cash collateral posted

669

Letters of credit held

Net receivable from electric utility

Net receivable from affiliated electric and gas utility

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

130

543

130

324

Expected reclassification from accumulated other comprehensive income to results of operations

Total

Letters of credit posted

389

364

Cash collateral held

169

206

Incremental collateral for loss of investment grade credit rating

2,100

2,000

Interest Rate Fair Value Hedge Asset at Fair Value

Counter Party With Exposure

[1]

For the three and nine months ended SeptemberB 30, 2014, the loss on Generation swaps included $4 million and $12 million realized in earnings, respectively, with $2 million amount excluded from hedge effectiveness testing.

Debt_and_Credit_Agreements_Com

Debt and Credit Agreements - Commercial Paper Borrowings Outstanding (Details) (Commercial Paper [Member], USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Exelon Generation Co L L C [Member]	'	'
Short-term Debt [Line Items]	'	'
Commercial paper borrowings	$0	$0
Commonwealth Edison Co [Member]	'	'
Short-term Debt [Line Items]	'	'
Commercial paper borrowings	528	184
Baltimore Gas and Electric Company [Member]	'	'
Short-term Debt [Line Items]	'	'
Commercial paper borrowings	$20	$135

Debt_and_Credit_Agreements_Lin

Debt and Credit Agreements - Lines of Credit under Committed Credit Facilities (Details) (USD $)	Sep. 30, 2014		Jun. 30, 2014	Jun. 11, 2014		1-May-14
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	$8,500,000,000	[1]	'	'		'
Bridge Loan	'		3,900,000,000	3,900,000,000		7,200,000,000
Line of Credit Facility, Current Borrowing Capacity	22,000,000		'	'		'
Parent [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	500,000,000	[1],[2]	'	'		'
Exelon Generation Co L L C [Member] \| Community and Minority Banks [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	50,000,000		'	'		'
Outstanding letters of credit	9,000,000		'	'		'
Exelon Generation Co L L C [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	5,300,000,000		'	'		'
Exelon Generation Co L L C [Member] \| Letter of Credit [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Outstanding letters of credit	300,000,000	[1],[2]	'	100,000,000	[1],[2]	'
Exelon Generation Co L L C [Member] \| Letter of Credit [Member] \| Debt Instrument, Redemption, Period Three [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Outstanding letters of credit	100,000,000	[1],[2]	'	'		'
Commonwealth Edison Co [Member] \| Community and Minority Banks [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	34,000,000		'	'		'
Outstanding letters of credit	18,000,000		'	'		'
Commonwealth Edison Co [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	1,000,000,000	[1],[2]	'	'		'
PECO Energy Co [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Current Borrowing Capacity	27,000,000		'	'		'
PECO Energy Co [Member] \| Community and Minority Banks [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	34,000,000		'	'		'
Outstanding letters of credit	21,000,000		'	'		'
PECO Energy Co [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	600,000,000	[1],[2]	'	'		'
Baltimore Gas and Electric Company [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Current Borrowing Capacity	27,000,000		'	'		'
Baltimore Gas and Electric Company [Member] \| Community and Minority Banks [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	5,000,000		'	'		'
Outstanding letters of credit	1,000,000		'	'		'
Baltimore Gas and Electric Company [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	600,000,000	[1],[2]	'	'		'
Syndicated Revolver 1 [Member] \| Exelon Generation Co L L C [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	5,100,000,000	[1],[2]	'	'		'
Syndicated Revolver 2 [Member] \| Exelon Generation Co L L C [Member] \| Revolving Credit Facility [Member]	'		'	'		'
Debt Instrument [Line Items]	'		'	'		'
Line of Credit Facility, Maximum Borrowing Capacity	$200,000,000	[1],[2]	'	'		'

[1]	Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEdbs, PECObs and BGEbs service territories. These facilities expired on OctoberB 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 SeptemberB 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $9 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.9 billion to support the PHI transaction discussed below, as well as, applicable asset divestitures.
[2]	Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.

Debt_and_Credit_Agreements_Nar

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

0 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

3 Months Ended

0 Months Ended

Jun. 01, 2014

Jun. 30, 2014

Sep. 30, 2014

Jun. 11, 2014

1-May-14

Jun. 05, 2013

Sep. 30, 2014

Sep. 18, 2014

Sep. 30, 2014

Mar. 28, 2014

Sep. 30, 2014

Jun. 30, 2014

Jun. 11, 2014

Apr. 01, 2014

Sep. 30, 2014

Apr. 01, 2014

Sep. 30, 2014

Sep. 18, 2014

Feb. 06, 2014

Sep. 30, 2014

Sep. 18, 2014

Feb. 06, 2014

Sep. 18, 2014

Oct. 24, 2014

Oct. 06, 2014

Oct. 01, 2014

Oct. 06, 2014

Mar. 28, 2014

Parent Company [Member]

Commonwealth Edison Co [Member]

Exelon Generation Co L L C [Member]

ExGen Texas Power, LLC [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Standby Letters of Credit [Member]

Revolving Credit Facility [Member]

Parent [Member]

Convertible Debt Securities [Member]

Maximum [Member]

Minimum [Member]

Senior Notes [Member]

Long Term Debt Issuances [Member]

Interest Rate Swap [Member]

Subsequent Event [Member]

Revolving Credit Facility [Member]

Commonwealth Edison Co [Member]

Exelon Generation Co L L C [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Revolving Credit Facility [Member]

Secured Debt [Member]

ExgenRenewablesI425June62021[Member]

Exelon Generation Co L L C [Member]

ExGen Texas Power, LLC [Member]

Exelon Generation Co L L C [Member]

Senior Loans [Member]

Maximum [Member]

Minimum [Member]

Unsecured Debt [Member]

ExGen Texas Power, LLC [Member]

ExGen Renewables I, LLC [Member]

Unsecured Debt [Member]

Non Recourse Debt [Member]

Minimum [Member]

Exelon Generation Co L L C [Member]

PECO Energy Co [Member]

Senior Loans [Member]

Exelon Generation Co L L C [Member]

Non Recourse Debt [Member]

Exelon Generation Co L L C [Member]

Debt Instrument [Line Items]

Amount Of Aggregate Letters of Credit Available

$500,000,000

Line of Credit Facility, Expiration Date

28-Mar-19

Additional Amount of Aggregate Letters of Credit Available

500,000,000

Outstanding borrowings/facility draws

100,000,000

Line of Credit Facility, Maximum Borrowing Capacity

8,500,000,000

[1]

8,500,000,000

[1]

20,000,000

1,000,000,000

[1],[2]

5,300,000,000

600,000,000

[1],[2]

600,000,000

[1],[2]

500,000,000

[1],[2]

1,000,000,000

Cumulative amount in commitments

315,000,000

[1],[2]

Basis points adders for prime-based borrowings

0.28%

0.08%

0.28%

0.00%

0.07%

Basis Points For Libor Based Borrowings

0.01275

0.01075

0.01275

0.009

0.01

0.00165

Bridge Loan

3,900,000,000

7,200,000,000

Interest Expense, Commercial Paper

11,000,000

20,000,000

Subordinated Debt, Amount

1,150,000,000

equity units issued

23,000,000

Shares Issued, Price Per Share

$35

$50

Proceeds from Issuance of Subordinated Long-term Debt

1,110,000,000

Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions

60,000,000

35,000,000

Subordinated Borrowing, Interest Rate

2.50%

Equity Units, Annual Distribution Rate

6.50%

Forward Contract Payment Rate

4.00%

Per Unit Conversion Rate For Equity Security Units

$50

Market Price required for Equity Unit Conversion

$43.75

Common Shares Issueable At Maturity

1.1429

1.4286

Equity Units Share Price

$43.75

$35

Share Price

$35

Long-term Debt

131,000,000

1,150,000,000

675,000,000

300,000,000

Debt Instrument, Collateral Amount

2,700,000,000

Interest Rate

2.50%

4750000.00%

4.25%

1.00%

2.03%

2.34%

5.00%

3.14%

3.06%

Derivative, Notional Amount

240,000,000

505,000,000

Repayments of First Mortgage Bond

250,000,000

Repayments of Secured Debt

$11,000,000

[1]

Excludes additional credit facility agreements for Generation, ComEd, PECO and BGE with aggregate commitments of $50 million, $34 million, $34 million and $5 million, respectively, arranged with minority and community banks located primarily within ComEdbs, PECObs and BGEbs service territories. These facilities expired on OctoberB 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 SeptemberB 30, 2014, letters of credit issued under these agreements for Generation, ComEd, PECO and BGE totaled $9 million, $18 million, $21 million and $1 million, respectively. Also, excludes the unsecured bridge credit facility of $3.9 billion to support the PHI transaction discussed below, as well as, applicable asset divestitures.

[2]

Includes credit facilities for Exelon Corporate, PECO and BGE with aggregate commitments of $22 million, $27 million and $27 million, respectively, that expire in August 2018.

Debt_and_Credit_Agreements_Sch

Debt and Credit Agreements - Schedule of Issuance of Long-Term Debt (Details) (USD $)

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Jun. 11, 2014

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

In Millions, unless otherwise specified

Convertible Debt Securities [Member]

Long Term Debt Issuances [Member]

Exelon Generation Co L L C [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Floating Rate Debt [Member]

Long Term Debt Issuances [Member]

Exelon Generation Co L L C [Member]

UpstreamGasLending221July222016[Member]

NuclearFuelPurchaseContract3350june302018 [Member]

Unsecured Debt [Member]

First Mortgage Bonds [Member]

Senior Notes [Member]

First Mortgage Bonds [Member]

Senior Notes [Member]

Long Term Debt Issuances [Member]

NuclearFuelPurchaseContract3350june302018 [Member]

ExgenRenewablesI425June62021[Member]

Energy Efficiency Project Financing [Member]

AVSR [Member]

NuclearFuelPurchaseContract3250june302018Member [Member]

Energy Efficiency Project Financing [Member]

NuclearFuelPurchaseContract3250june302018Member [Member]

ExGen Texas Power [Member]

Continental Wind 6000 February 28, 2033 [Member]

FirstMortgageBondSeries115January152019 [Member]

FirstMortgageBondSeries116January152044 [Member]

FirstMortgageBondSeries114August152043 [Member] [Member]

FirstAndRefundingMortageBondsOctoberu12044 [Member]

FirstAndRefundMortgageBondOctober152016 [Member]

FirstAndRefundMortgageBondOctober152043 [Member]

SeniorNotesJuly12023Member [Member]

DOE Financing Project [Member]

DOE Project Financing, 3.092% January 2, 2037 [Member]

CEU Credit Agreement [Member]

Debt Instrument [Line Items]

Interest Rate

2.50%

3.35%

4.12%

3.25%

6.00%

2.15%

4.70%

4600000.00%

4.15%

1200000.00%

4800000.00%

3350000.00%

4.40%

Long-term Debt

$131

$1,150

$38

$300

$12

$125

$32

$675

$613

$300

$350

$300

$250

$300

Long-term Debt, Excluding Current Maturities

19,200

17,623

6,741

5,645

5,448

5,058

2,246

1,947

1,904

1,941

204

Subordinated Debt, Amount

$1,150

Debt_and_Credit_Agreements_Ret

Debt and Credit Agreements - Retirement and Redemptions of Current and Long-Term Debt (Details) (USD $)

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

In Millions, unless otherwise specified

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Commonwealth Edison Co [Member]

Long Term Debt Retirements [Member]

Fixed Rate Debt [Member]

Continetal Wind [Member]

Minimum [Member]

Maximum [Member]

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Commonwealth Edison Co [Member]

Long Term Debt Retirements [Member]

Junior Subordinated Debt [Member]

Armstrong Co Tax Exempt, 5% December 1,2042 [Member]

MEDCO Tax-Exempt Bonds [Member]

Senior Notes [Member]

Capital Lease Obligations [Member]

Rate Stabilization Bonds, April 1, 2017 [Member]

Medium Term, Notes 6.73% 6.75% June 15, 2012 [Member]

Senior Notes [Member]

Rate Stabilization Bonds, April 1, 2017 [Member]

First Mortgage Bonds [Member]

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Commonwealth Edison Co [Member]

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

SeniorSecuredNotes525January152014Member [Member]

Kennett Square Capital Lease, 7.83%, September 20, 2020 [Member]

ExgenRenewables425February62021 [Member]

AVSR [Member]

Clear Horizon solar [Member]

Sacramento Solar [Member]

FirstMortgageBond163January12014 [Member]

Pollution Control Notes [Member]

Rate Stabilization Bonds, April 1, 2017 [Member]

Pollution Control Notes [Member]

Continental Wind 6000 February 28, 2033 [Member]

Rate Stabilization Bonds, April 1, 2017 [Member]

Debt Instrument [Line Items]

Long-term Debt

$131

$500

$33

$400

$35

$600

$20

$17

$20

Interest Rate

8.63%

7.63%

7.50%

5.35%

7.83%

2.56%

5720000.00%

2.56%

6125000.00%

4.40%

1.63%

4.10%

5.72%

5.85%

6.00%

1.93%

1.95%

Long-term Debt, Excluding Current Maturities

$19,200

$17,623

$6,741

$5,645

$1,904

$1,941

$5,448

$5,058

$450

$125

$127

$18

Income_Taxes_Reconciliation_to

Income Taxes - Reconciliation to Effective Tax Rate (Details)	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'	'
U.S. Federal statutory rate	35.00%	35.00%	35.00%	35.00%
Increase (decrease) due to:	'	'	'	'
State income taxes, net of Federal income tax benefit	1.10%	3.00%	0.50%	5.30%
Qualified nuclear decommissioning trust fund income	-0.30%	3.50%	2.00%	3.20%
Domestic production activities deduction	-2.40%	'	-2.70%	'
Tax exempt income	'	0.20%	'	0.20%
Health care reform legislation	0.00%	0.10%	0.10%	0.10%
Amortization of investment tax credit, net deferred taxes	-1.00%	-1.50%	-1.10%	-2.30%
Plant basis differences	-0.80%	-0.80%	-1.60%	-1.70%
Production tax credits and other credits	1.90%	2.20%	2.10%	2.40%
Noncontrolling interest	-1.20%	'	-1.40%	'
Other	-0.30%	0.50%	-1.50%	0.20%
Effective income tax rate	28.20%	37.40%	27.20%	37.20%
Exelon Generation Co L L C [Member]	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'	'
U.S. Federal statutory rate	35.00%	35.00%	35.00%	35.00%
Increase (decrease) due to:	'	'	'	'
State income taxes, net of Federal income tax benefit	0.70%	2.60%	-1.40%	1.80%
Qualified nuclear decommissioning trust fund income	-0.40%	5.30%	3.60%	5.10%
Domestic production activities deduction	-3.20%	'	-4.80%	'
Tax exempt income	'	0.30%	'	0.30%
Health care reform legislation	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, net deferred taxes	-1.20%	-2.10%	-1.70%	-3.40%
Plant basis differences	0.00%	0.00%	0.00%	0.00%
Production tax credits and other credits	2.40%	3.30%	3.70%	3.90%
Noncontrolling interest	-1.60%	'	-2.60%	'
Other	-1.40%	0.10%	-2.50%	1.10%
Effective income tax rate	25.50%	37.30%	21.90%	35.40%
Commonwealth Edison Co [Member]	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'	'
U.S. Federal statutory rate	35.00%	35.00%	35.00%	35.00%
Increase (decrease) due to:	'	'	'	'
State income taxes, net of Federal income tax benefit	5.00%	5.40%	5.00%	5.20%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Domestic production activities deduction	0.00%	'	0.00%	'
Tax exempt income	'	0.00%	'	0.00%
Health care reform legislation	0.20%	0.40%	0.20%	0.90%
Amortization of investment tax credit, net deferred taxes	-0.30%	-0.40%	-0.30%	-0.80%
Plant basis differences	0.00%	-0.40%	-0.30%	-1.20%
Production tax credits and other credits	0.00%	0.00%	0.00%	0.00%
Noncontrolling interest	0.00%	'	0.00%	'
Other	0.10%	0.30%	0.10%	0.80%
Effective income tax rate	40.00%	40.30%	39.70%	39.90%
PECO Energy Co [Member]	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'	'
U.S. Federal statutory rate	35.00%	35.00%	35.00%	35.00%
Increase (decrease) due to:	'	'	'	'
State income taxes, net of Federal income tax benefit	0.10%	-0.30%	0.30%	1.90%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Domestic production activities deduction	0.00%	'	0.00%	'
Tax exempt income	'	0.00%	'	0.00%
Health care reform legislation	0.00%	0.00%	0.00%	0.00%
Amortization of investment tax credit, net deferred taxes	-0.10%	-0.10%	-0.10%	-0.10%
Plant basis differences	-11.30%	-6.90%	-11.00%	-7.30%
Production tax credits and other credits	0.00%	0.00%	0.00%	0.00%
Noncontrolling interest	0.00%	'	0.00%	'
Other	-0.10%	-0.10%	0.10%	0.00%
Effective income tax rate	23.60%	27.60%	24.30%	29.50%
Baltimore Gas and Electric Company [Member]	'	'	'	'
Effective Income Tax Rate Reconciliation, Percent [Abstract]	'	'	'	'
U.S. Federal statutory rate	35.00%	35.00%	35.00%	35.00%
Increase (decrease) due to:	'	'	'	'
State income taxes, net of Federal income tax benefit	4.60%	5.60%	4.90%	5.60%
Qualified nuclear decommissioning trust fund income	0.00%	0.00%	0.00%	0.00%
Domestic production activities deduction	0.00%	'	0.00%	'
Tax exempt income	'	0.00%	'	0.00%
Health care reform legislation	0.20%	0.20%	0.20%	0.20%
Amortization of investment tax credit, net deferred taxes	-0.30%	-0.30%	-0.30%	-0.30%
Plant basis differences	0.50%	0.10%	0.50%	-0.40%
Production tax credits and other credits	0.00%	0.00%	0.00%	0.00%
Noncontrolling interest	0.00%	'	0.00%	'
Other	-1.20%	-0.20%	-0.50%	0.00%
Effective income tax rate	38.80%	40.40%	39.80%	40.10%

Income_Taxes_Narrative_Details

Income Taxes - Narrative (Details) (USD $)

3 Months Ended

9 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

Mar. 31, 2014

Sep. 30, 2014

Mar. 31, 2013

Dec. 31, 2009

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Mar. 31, 2013

Sep. 30, 2014

Mar. 31, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2014

Parent Company [Member]

Exelon Generation Co L L C [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Minimum [Member]

Maximum [Member]

Income Tax Additional Narrative Information [Line Items]

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

$1,808,000,000

$2,175,000,000

$1,342,000,000

$1,415,000,000

$151,000,000

$324,000,000

$44,000,000

Unrecognized Tax Benefits, Increase Resulting from Settlements with Taxing Authorities

180,000,000

Increase (Decrease) in Income Taxes

75,000,000

Effective Income Tax Rate Reconciliation, Tax Settlement, Amount

90,000,000

Deferred tax gain under involuntary conversion provisions of the IRC

1,200,000,000

IRS asserted penalties for understatement of tax

87,000,000

Expected non-cash charge to earnings

265,000,000

170,000,000

Non-cash equity contributions

172,000,000

Potential tax and interest from a successful IRS challenge of the like-kind exchange transaction position

800,000,000

310,000,000

Early termination amount

335,000,000

Taxes Payable, Current

285,000,000

155,000,000

Cash tax benefit (detriment) as a result of repair costs deduction

$100,000,000

$120,000,000

Nuclear_Decommissioning_Rollfo

Nuclear Decommissioning - Rollforward of Nuclear Decommissioning ARO (Details) (Exelon Generation Co L L C [Member], USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Asset Retirement Obligation, Period Increase (Decrease)	$1,800		'
Nuclear Decommissioning Asset Retirement Obligation [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Nuclear Decommissioning ARO, Beginning Balance	4,855	[1]	'
Accretion expense	243		'
Asset Retirement Obligation, Period Increase (Decrease)	-125		'
Costs incurred to decommission retired plants	-5		'
Nuclear Decommissioning ARO, Ending Balance	6,652	[1]	'
Current portion of ARO	9		9
Nuclear Decommissioning Asset Retirement Obligation [Member] \| Nuclear Decommissioning Asset Retirement Obligation [Member]	'		'
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]	'		'
Nuclear Decommissioning ARO, Ending Balance	$1,684	[2]	'

[1]	Includes $9 million as the current portion of the ARO at SeptemberB 30, 2014 and DecemberB 31, 2013 which is included in Other current liabilities on Exelonbs and Generationbs Consolidated Balance Sheets.
[2]	Includes the fair value of the CENG ARO liability as of April 1, 2014, the date of consolidation. See Note 6 b Investment in Constellation Energy Nuclear Group, LLC for additional information.

Nuclear_Decommissioning_Detail

Nuclear Decommissioning (Details) (USD $)	3 Months Ended	9 Months Ended		9 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014	Sep. 30, 2013
				Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Nuclear Plant [Member]	Limerick and Three Mile Island Nuclear Units [Member]
							Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]
Nuclear Decommissioning Additional Narrative Information [Line Items]	'	'	'	'	'	'	'	'
Asset Retirement Obligation, Period Increase (Decrease)	'	'	'	$1,800	'	'	$17	$51
Other Income	16	'	'	'	'	'	'	'
Nuclear Decommissioning Annual Recovery Current	'	24	'	'	'	'	'	'
Decommissioning Shortfall	'	'	'	50	'	'	'	'
Decommissioning Shortfall Percentage	'	'	'	5.00%	'	'	'	'
Half Of Non Decommissioning Withdraw	'	50.00%	'	'	'	'	'	'
Decommissioning Fund Investments	10,349	10,349	8,071	10,349	8,071	'	'	'
Decommissioning Liability, Noncurrent	260	260	305	260	305	'	85	'
Additional NRC Funding Assurance Parent Guarantees	'	'	'	'	'	$115	'	'

Nuclear_Decommissioning_Unreal

Nuclear Decommissioning - Unrealized Gains on NDT Funds (Details) (Exelon Generation Co L L C [Member], USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Exelon Generation Co L L C [Member]	'		'		'		'
Unrealized Losses On Nuclear Decommissioning Trust Fund Investment [Line Items]	'		'		'		'
Net unrealized gains (losses) on decommissioning trust funds - regulatory agreement units	($107)	[1]	$103	[1]	$126	[1]	$196	[1]
Net unrealized gains (losses) on decommissioning trust funds - non-regulatory agreement units	-41	[2],[3]	46	[2],[3]	100	[2],[3]	70	[2],[3]
Unrealized Gain Loss Investment Income Pledged Assets	$7		($9)		$27		($5)

[1]	Net unrealized gains (losses) related to Generationbs NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelonbs Consolidated Balance Sheets and Noncurrent payables to affiliates on Generationbs Consolidated Balance Sheets.
[2]	Excludes $7 million of net unrealized gains and $9 million of net unrealized losses related to the Zion Station pledged assets for the three months ended SeptemberB 30, 2014 and 2013, respectively, and $27 million of net unrealized gains and $5 million of net unrealized losses related to the Zion Station pledged assets for the nine months ended SeptemberB 30, 2014 and 2013, respectively. Net unrealized gains (losses) related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelonbs and Generationbs Consolidated Balance Sheets.
[3]	Net unrealized gains (losses) related to Generationbs NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelonbs and Generationbs Consolidated Statements of Operations and Comprehensive Income.

Nuclear_Decommissioning_Assets

Nuclear Decommissioning - Assets, Payables and Withdrawals by ZionSolutions (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013
Nuclear Decommissioning Additional Narrative Information [Line Items]	'		'		'
Pledged assets for Zion Station decommissioning	$365		'		$458
Exelon Generation Co L L C [Member]	'		'		'
Nuclear Decommissioning Additional Narrative Information [Line Items]	'		'		'
Pledged assets for Zion Station decommissioning	365		'		458
Payable to Zion Solutions	334	[1]	'		414	[1]
Current portion of payable to Zion Solutions	74	[2]	'		109	[2]
Withdrawals by Zion Solutions to pay decommissioning costs	$618	[3]	$498	[3]	'

[1]	Excludes a liability recorded within Exelonbs and Generationbs 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 Exelonbs and Generationbs Consolidated Balance Sheets.
[3]	Cumulative withdrawals since SeptemberB 1, 2010.

Retirement_Benefits_Narrative_

Retirement Benefits - Narrative (Details) (USD $)

3 Months Ended

1 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

9 Months Ended

6 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

5 Months Ended

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Apr. 30, 2014

Jun. 30, 2014

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Mar. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Sep. 30, 2014

Mar. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Aug. 31, 2014

Sep. 30, 2014

Remeasurement [Member]

Exelon Legacy Benefit Plans [Member]

Business Services Company [Member]

Exelon Generation Co L L C [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Constellation Energy Nuclear Group [Member]

Pension Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Exelon Sponsored Benefit Plan [Member]

Remeasurement [Member]

CENG [Member]

Exelon Legacy Benefit Plans [Member]

CENG [Member]

Exelon Legacy Benefit Plans [Member]

CENG [Member]

Exelon Generation Co L L C [Member]

Minimum [Member]

Maximum [Member]

Defined Benefit Plan Disclosure [Line Items]

Benefit obligation increase (decrease) reflecting actual census data

$35,000,000

$12,000,000

Changes in plan assets and benefit obligations recognized in OCI

1,000,000

12,000,000

Increase in regulatory assets due valuation received by Exelon for its legacy pension and other postretirement benefit obligations.

34,000,000

Increase in regulatory liabilities due to updated valuation of Exelon's legacy pension and postretirement benefit obligations

5,000,000

Pension Obligations Valuation Adjustment

13,000,000

Other postretirement benefit obligation increase (decrease) due to updated valuation adjustment

790,000,000

3,000,000

Regulatory asset increase (decrease) due to updated valuation adjustment

15,000,000

125,000,000

Pension And Other Postretirement Benefit Expense Included In Capital And Operating And Maintenance Expense

149,000,000

11,000,000

[1]

24,000,000

[1]

37,000,000

[1]

58,000,000

[1]

54,000,000

[2]

87,000,000

[2]

193,000,000

[2]

259,000,000

[2]

33,000,000

77,000,000

129,000,000

231,000,000

7,000,000

11,000,000

28,000,000

32,000,000

17,000,000

14,000,000

50,000,000

41,000,000

2,000,000

5,000,000

3,000,000

6,000,000

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 assets

7.00%

7.75%

6.59%

Discount rate

4.80%

3.60%

4.30%

4.90%

4.55%

Expected qualified pension plan contributions

308,000,000

160,000,000

119,000,000

11,000,000

43,000,000

53,000,000

51,000,000

Expected non-qualified pension plan contributions

18,000,000

9,000,000

3,000,000

1,000,000

Expected other postretirement benefit plan contributions

$290,000,000

$128,000,000

$5,000,000

$121,000,000

$4,000,000

$18,000,000

[1]

These amounts primarily represent amounts billed to Exelonbs subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.

[2]

For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.

Retirement_Benefits_Calculatio

Retirement Benefits - Calculation of Net Periodic Benefit Cost (Details) (USD $)

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

3 Months Ended

6 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Pension Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

CENG [Member]

Pension Plan, Defined Benefit [Member]

Other Postretirement Benefit Plan, Defined Benefit [Member]

Defined Benefit Plan Disclosure [Line Items]

Savings Plan Matching Contributions

$34

[1]

$18

[1]

$82

[1]

$61

[1]

Service cost

[2]

218

[3]

238

[3]

[2]

[3]

122

[3]

Interest cost

189

[2]

163

[2]

561

[3]

488

[3]

[2]

144

[3]

145

[3]

Expected return on assets

-251

[2]

-253

[2]

-743

[3]

-761

[3]

-39

[2]

-33

[2]

-115

[3]

-99

[3]

Amortization of:

Prior service cost (benefit)

[2]

[3]

-44

[2]

-4

[2]

-79

[3]

-14

[3]

Actuarial loss

106

[2]

140

[2]

316

[3]

421

[3]

[2]

[3]

Settlement charges

[2]

[3]

[2]

[3]

Net periodic benefit cost

121

[2]

141

[2]

362

[3]

405

[3]

[2]

[3]

216

[3]

Pension and Other Postretirement Benefit Costs

[1]

Includes $1 million related to CENG for the three months ended September 30, 2014 and for the period from April 1, 2014 to September, 30 2014. CENG is not included in the 2013 amounts.

[2]

For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. CENG is not included in the 2013 amounts.

[3]

For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.

Retirement_Benefits_Allocated_

Retirement Benefits - Allocated Portion of Pension and Postretirement Benefit Plan Costs (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Exelon Generation Co L L C [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Pension and Other Postretirement Benefit Costs	$54	[1]	$87	[1]	$193	[1]	$259	[1]
Commonwealth Edison Co [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Pension and Other Postretirement Benefit Costs	33		77		129		231
PECO Energy Co [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Pension and Other Postretirement Benefit Costs	7		11		28		32
Baltimore Gas and Electric Company [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Pension and Other Postretirement Benefit Costs	17		14		50		41
Business Services Company [Member]	'		'		'		'
Defined Benefit Plan Disclosure [Line Items]	'		'		'		'
Pension and Other Postretirement Benefit Costs	$11	[2]	$24	[2]	$37	[2]	$58	[2]

[1]	For the three months ended September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $2 million and $3 million, respectively. For the period April 1, 2014 to September 30, 2014, the cost for pension benefits and other postretirement benefits related to CENG were $5 million and $6 million, respectively. CENG is not included in the 2013 amounts.
[2]	These amounts primarily represent amounts billed to Exelonbs subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd, PECO or BGE amounts above.

Retirement_Benefits_Defined_Co

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

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

6 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Exelon Generation Co L L C [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Business Services Company [Member]

CENG [Member]

Defined Benefit Plan Disclosure [Line Items]

Savings Plan Matching Contributions

$34

[1]

$18

[1]

$82

[1]

$61

[1]

$17

[1]

$41

[1]

$29

[1]

$20

$16

[2]

[1]

Includes $1 million related to CENG for the three months ended September 30, 2014 and for the period from April 1, 2014 to September, 30 2014. CENG is not included in the 2013 amounts.

[2]

These amounts primarily represent amounts billed to Exelonbs 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 $)	0 Months Ended
In Millions, unless otherwise specified	Apr. 01, 2014
Restructuring and Related Activities [Abstract]	'
Severance Costs	$27

Severance_Severance_Liabilitie

Severance - Severance Liabilities (Details) (USD $)	9 Months Ended			3 Months Ended	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Mar. 31, 2014	Sep. 30, 2014	Sep. 30, 2014
	Sep. 30, 2014	Employee Severance [Member]	Employee Severance [Member]	Other Severance Charges [Member]	Other Severance Charges [Member]	Other Segment [Member]
Restructuring Reserve [Roll Forward]	'	'	'	'	'	'
Beginning Balance	$53	$16	$2	'	'	'
Severance Charges Expense	2	'	'	'	'	19
Payments for Restructuring	-36	'	'	-4	-7	'
Ending Balance	$17	$16	$2	'	'	'

Severance_Constellation_Merger

Severance - Constellation Merger-Related Severance (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014
Corporate Restructuring Severance Benefit Obligation [Line Items]	'
Beginning Balance	$53
Payments	-36
Ending Balance	17
Exelon Generation Co L L C [Member]	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'
Beginning Balance	10
Payments	-5
Ending Balance	5
Commonwealth Edison Co [Member]	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'
Beginning Balance	0
Payments	0
Ending Balance	0
PECO Energy Co [Member]	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'
Beginning Balance	0
Payments	0
Ending Balance	0
Baltimore Gas and Electric Company [Member]	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'
Beginning Balance	6
Payments	-4
Ending Balance	$2

Severance_Ongoing_Severance_Pl

Severance - Ongoing Severance Plans (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Corporate Restructuring Severance Benefit Obligation [Line Items]	'	'	'	'
Severance charges recorded	($2)	$12	$4	$14
Exelon Generation Co L L C [Member]	'	'	'	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'	'	'	'
Severance charges recorded	-2	11	3	12
Commonwealth Edison Co [Member]	'	'	'	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'	'	'	'
Severance charges recorded	0	1	1	2
PECO Energy Co [Member]	'	'	'	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'	'	'	'
Severance charges recorded	0	0	0	0
Baltimore Gas and Electric Company [Member]	'	'	'	'
Corporate Restructuring Severance Benefit Obligation [Line Items]	'	'	'	'
Severance charges recorded	$0	$0	$0	$0

Changes_in_Accumulated_Other_C2

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

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2014

Dec. 31, 2013

Sep. 30, 2013

Dec. 31, 2012

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

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Defined Benefit Plans Adjustment [Member]

Accumulated Translation Adjustment [Member]

Accumulated Equity Investment [Member]

Exelon Generation Co L L C [Member]

PECO Energy Co [Member]

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

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Accumulated Defined Benefit Plans Adjustment [Member]

Accumulated Translation Adjustment [Member]

Accumulated Equity Investment [Member]

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

Accumulated Net Unrealized Investment Gain (Loss) [Member]

Movement in Accumulated Other Comprehensive Income [Roll Forward]

Beginning balance

($2,040)

[1]

($2,767)

[1]

$120

[1]

$368

[1]

($2,260)

[1]

($3,137)

[1]

($10)

[1]

$108

[1]

$214

[1]

$513

[1]

$114

[1]

$512

[1]

($10)

[1]

$108

[1]

OCI before reclassifications

229

[1]

138

[1]

-14

[1]

-2

[1]

-1

[1]

240

[1]

-6

[1]

-5

[1]

-6

[1]

-8

[1]

-3

[1]

-1

[1]

-6

[1]

-5

[1]

Amounts reclassified from AOCI

-106

[1],[2]

-32

[1],[2]

-78

[1],[2]

-194

[1],[2]

157

[1],[2]

-119

[1],[2]

-197

[1],[2]

-323

[1],[2]

-78

[1],[2]

-328

[1],[2]

-119

[1],[2]

Net current-period OCI

-11

123

[1]

106

[1]

-92

[1]

-169

[1]

-2

[1]

-1

[1]

331

[1]

230

[1]

-6

[1]

-5

[1]

-108

[1]

-26

-32

-203

[1]

-270

[1]

-86

[1]

-316

[1]

-3

[1]

-1

[1]

-6

[1]

-5

[1]

-108

[1]

Ending balance

($1,917)

[1]

($2,661)

[1]

($1,917)

[1]

($2,661)

[1]

$28

[1]

$199

[1]

($1)

[1]

($1,929)

[1]

($2,907)

[1]

($16)

[1]

($5)

[1]

$53

[1]

$11

[1]

$243

[1]

$11

[1]

$243

[1]

$28

[1]

$196

[1]

($1)

[1]

($1)

[1]

($16)

[1]

($5)

[1]

$53

[1]

All amounts are net of tax. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.

[2]

See tables following changes in accumulated other comprehensive income tables for details about these reclassifications.

Changes_in_Accumulated_Other_C3

Changes in Accumulated Other Comprehensive Income - Reclassification out of Accumulated Other Comprehensive Income (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Operating revenues	$6,912	[1]	$6,502	[1]	$20,173	[2]	$18,725	[2]
Income before income taxes	1,496		1,175		2,371		1,968
Income taxes	-422		-439		-646		-733
Net income	1,074		736		1,725		1,235
Prior service benefit reclassified to periodic benefit cost	8		0		11		0
Other Nonoperating Income (Expense)	354		155		702		311
Equity in earnings (loss) of unconsolidated affiliates	1		37		-20		7
Interest Expense	247		228		691		1,091
Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Net income	-7	[3]	-8	[3]	106	[3]	32	[3]
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Income before income taxes	28	[3]	83	[3]	130	[3]	322	[3]
Income taxes	-12	[3]	-35	[3]	-52	[3]	-128	[3]
Net income	16	[3]	48	[3]	78	[3]	194	[3]
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Energy Related Derivative [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Operating revenues	28	[3]	84	[3]	130	[3]	324	[3]
Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedging [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Interest Expense	'		-1	[3]	'		-2	[3]
Accumulated Defined Benefit Plans Adjustment [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Income before income taxes	-42	[3]	-93	[3]	-149	[3]	-259	[3]
Income taxes	16	[3]	37	[3]	58	[3]	102	[3]
Net income	-26	[3]	-56	[3]	-91	[3]	-157	[3]
Prior service benefit reclassified to periodic benefit cost	19	[3],[4]	'		29	[3],[4]	-1	[3],[4]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	-61	[3],[4]	-92	[3],[4]	-178	[3],[4]	-257	[3],[4]
Equity Method Investments \| Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Income before income taxes	5	[3]	0	[3]	198	[3]	-8	[3]
Income taxes	-2	[3]	0	[3]	-79	[3]	3	[3]
Net income	3	[3]	0	[3]	119	[3]	-5	[3]
Other Nonoperating Income (Expense)	5	[3]	'		5	[3]	'
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax	'		-1	[3],[5]	'		-1	[3],[5]
Equity in earnings (loss) of unconsolidated affiliates	'		0	[3]	'		-8	[3]
Gain on consolidation of CENG	'		'		193	[3]	'
Exelon Generation Co L L C [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Operating revenues	4,412		4,255		12,591		11,858
Income before income taxes	1,140		773		1,327		1,231
Income taxes	-291		-288		-290		-436
Net income	849		485		1,037		795
Other Nonoperating Income (Expense)	342		134		661		229
Equity in earnings (loss) of unconsolidated affiliates	1		37		-20		7
Interest Expense	77		69		224		210
Exelon Generation Co L L C [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Net income	19	[3]	50	[3]	197	[3]	323	[3]
Exelon Generation Co L L C [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Income before income taxes	28	[3]	83	[3]	130	[3]	543	[3]
Income taxes	-12	[3]	-33	[3]	-52	[3]	-215	[3]
Net income	16	[3]	50	[3]	78	[3]	328	[3]
Exelon Generation Co L L C [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Energy Related Derivative [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Operating revenues	28	[3]	84	[3]	130	[3]	543	[3]
Exelon Generation Co L L C [Member] \| Accumulated Net Gain (Loss) from Designated or Qualifying Cash Flow Hedges [Member] \| Reclassification out of Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedging [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Interest Expense	'		-1	[3]	'		0	[3]
Exelon Generation Co L L C [Member] \| Equity Method Investments \| Reclassification out of Accumulated Other Comprehensive Income [Member]	'		'		'		'
Reclassification Adjustment out of Accumulated Other Comprehensive Income [Line Items]	'		'		'		'
Income before income taxes	5	[3]	0	[3]	198	[3]	-8	[3]
Income taxes	-2	[3]	0	[3]	-79	[3]	3	[3]
Net income	3	[3]	0	[3]	119	[3]	-5	[3]
Other Nonoperating Income (Expense)	5	[3]	'		5	[3]	'
Equity in earnings (loss) of unconsolidated affiliates	'		0	[3]	'		-8	[3]
Gain on consolidation of CENG	'		'		$193	[3]	'

[1]	For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.
[2]	For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.
[3]	All amounts are net of tax. Amounts in parenthesis represent a decrease in net income.
[4]	This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 13b Retirement Benefits for additional details).
[5]	Amortization of deferred compensation unit is allocated to capital and operating and maintenance expense.

Changes_in_Accumulated_Other_C4

Changes in Accumulated Other Comprehensive Income - Components of Other Comprehensive Income (Loss) (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Pension and non-pension postretirement benefit plans:	'	'	'	'
Prior service benefit reclassified to periodic benefit cost	$8	$0	$11	$0
Actuarial gain (loss) reclassified to periodic cost	-24	33	-69	97
Pension and non-pension postretirement benefit plans valuation adjustment	5	-6	-153	44
Change in unrealized gain (loss) on cash flow hedges	15	-35	62	-109
Change in unrealized income on equity investments	3	9	73	32
Deferred compensation unit valuation adjustment	0	0	0	6
Change in marketable securities	1	0	-1	0
Total	8	1	-77	70
Exelon Generation Co L L C [Member]	'	'	'	'
Pension and non-pension postretirement benefit plans:	'	'	'	'
Change in unrealized gain (loss) on cash flow hedges	13	-36	57	-209
Change in unrealized income on equity investments	3	9	73	32
Change in marketable securities	1	0	-1	0
Total	$17	($27)	$129	($177)

Common_Stock_Narrative_Details

Common Stock - Narrative (Details) (USD $)	1 Months Ended	3 Months Ended
Share data in Millions, except Per Share data, unless otherwise specified	Jun. 30, 2014	Sep. 30, 2014	Jun. 05, 2013
Common Stock [Abstract]	'	'	'
Temporary Equity, Share Subscriptions	'	'	57.5
Shares Issued, Price Per Share	'	'	$35
Forward Contract Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value	'	'	$1,850,000,000
Investment Banking, Advisory, Brokerage, and Underwriting Fees and Commissions	60,000,000	35,000,000	'
Forward Contract Indexed to Issuer's Equity, Forward Rate Per Share	$33.58	'	'
Junior Subordinated Notes, Noncurrent	'	'	$1,150,000,000
Forward Contract Indexed to Issuer's Equity, Indexed Shares	'	'	23

Earnings_Per_Share_and_Equity_2

Earnings Per Share and Equity - Schedule of Earnings per Share (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]	'	'	'	'
Net income attributable to common shareholders	$993	$738	$1,604	$1,224
Average common shares outstanding b basic	861	857	860	856
Potentially dilutive effect of stock options, performance share awards and restricted stock	2	3	3	4
Average common shares outstanding b diluted	863	860	863	860

Earnings_Per_Share_and_Equity_3

Earnings Per Share and Equity - Narrative (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
In Millions, except Share data, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Equity units issued [Member]	Equity units issued [Member]	Employee Stock Option [Member]	Employee Stock Option [Member]	Employee Stock Option [Member]	Equity Forward Units [Member]	Equity Forward Units [Member]	PECO Energy Co [Member]
Statement Of Equity Line Item [Line Items]	'	'	'	'	'	'	'	'	'	'
Stock options not included in the calculation of diluted common shares outstanding	'	'	2,000,000	1,000,000	16,000,000	20,000,000	16,000,000	2,000,000	1,000,000	'
Treasury Stock, Shares held	35,000,000	35,000,000	'	'	'	'	'	'	'	'
Treasury Stock, Value	$2,327	$2,327	'	'	'	'	'	'	'	'
Preferred Stock Redemption Premium	'	'	'	'	'	'	'	'	'	6
PECO Cumulative Preferred Securities Redeemable	'	'	'	'	'	'	'	'	'	$87

Commitments_and_Contingencies_2

Commitments and Contingencies - Energy Commitments (Details) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified	Sep. 30, 2014
Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	$917
2014	103
2015	324
2016	180
2017	151
2018	36
Thereafter	123
Exelon Generation Co L L C [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	2,008
2014	104
2015	578
2016	450
2017	303
2018	129
Thereafter	444
Operating Leases, Future Minimum Payments Receivable [Abstract]	'
2014	23
2015	132
2016	133
2017	136
2018	137
Thereafter	729
Exelon Generation Co L L C [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	493	[1],[2]
2014	80	[1],[2]
2015	182	[1],[2]
2016	57	[1],[2]
2017	43	[1],[2]
2018	30	[1],[2]
Thereafter	101	[1],[2]
Exelon Generation Co L L C [Member] \| Net Capacity Purchases [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	1,451	[3]
2014	91	[3]
2015	396	[3]
2016	269	[3]
2017	208	[3]
2018	98	[3]
Thereafter	389	[3]
Exelon Generation Co L L C [Member] \| Power Purchases [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	434	[4]
2014	7	[4]
2015	162	[4]
2016	166	[4]
2017	80	[4]
2018	15	[4]
Thereafter	4	[4]
Exelon Generation Co L L C [Member] \| Transmission Rights Purchases [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	123	[5]
2014	6	[5]
2015	20	[5]
2016	15	[5]
2017	15	[5]
2018	16	[5]
Thereafter	51	[5]
Commonwealth Edison Co [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	92	[6]
2014	13	[6]
2015	38	[6]
2016	16	[6]
2017	5	[6]
2018	5	[6]
Thereafter	15	[6]
Commonwealth Edison Co [Member] \| Energy Supply Procurement [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	731	[7]
2014	111	[7]
2015	329	[7]
2016	151	[7]
2017	140	[7]
2018	0	[7]
Thereafter	0	[7]
Commonwealth Edison Co [Member] \| Renewable Energy Including Renewable Energy Credits [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	1,538	[8]
2014	22	[8]
2015	73	[8]
2016	76	[8]
2017	77	[8]
2018	78	[8]
Thereafter	1,212	[8]
PECO Energy Co [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	29	[6]
2014	7	[6]
2015	11	[6]
2016	2	[6]
2017	1	[6]
2018	1	[6]
Thereafter	7	[6]
PECO Energy Co [Member] \| DSP Program Electric Procurement Contracts [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	498	[9]
2014	193	[9]
2015	305	[9]
2016	0	[9]
2017	0	[9]
2018	0	[9]
Thereafter	0	[9]
PECO Energy Co [Member] \| Alternative Energy Credits [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	13	[10]
2014	1	[10]
2015	2	[10]
2016	2	[10]
2017	2	[10]
2018	2	[10]
Thereafter	4	[10]
Baltimore Gas and Electric Company [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	302	[6]
2014	2	[6]
2015	93	[6]
2016	105	[6]
2017	102	[6]
2018	0	[6]
Thereafter	0	[6]
Baltimore Gas and Electric Company [Member] \| Energy Supply Procurement [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	1,055	[11]
2014	198	[11]
2015	621	[11]
2016	236	[11]
2017	0	[11]
2018	0	[11]
Thereafter	0	[11]
Baltimore Gas and Electric Company [Member] \| Curtailment Services [Member]	'
Unrecorded Unconditional Purchase Obligation, Fiscal Year Maturity [Abstract]	'
Total	125	[12]
2014	10	[12]
2015	40	[12]
2016	34	[12]
2017	29	[12]
2018	$12	[12]

[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]	Net capacity purchases include PPAs and other capacity contracts including those that are accounted for as operating leases. Amounts presented in the commitments represent Generationbs expected payments under these arrangements at SeptemberB 30, 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 SeptemberB 30, 2014, capacity offsets were $23 million, $132, million $133 million, $136, million, $137 million, and $729 million for years 2014, 2015, 2016, 2017, 2018, and thereafter, respectively. Expected payments include certain fixed capacity charges which may be reduced based on plant availability.
[4]	The table excludes renewable energy purchases that are contingent in nature.
[5]	Transmission rights purchases include estimated commitments for additional transmission rights that will be required to fulfill firm sales contracts.
[6]	Purchase obligations include commitments related to smart meter installation. See Note 5 b Regulatory Matters for additional information.
[7]	ComEd entered into various contracts for the procurement of electricity that started to expire in 2012, and will continue to expire through 2017. ComEd is permitted to recover its electric supply procurement costs from retail customers with no mark-up. As of September 30, 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.
[8]	Primarily related to ComEd 20-year contracts for renewable energy and RECs that began in June 2012. ComEd is permitted to recover its renewable energy and REC costs from retail customers with no mark-up. The commitments represent the maximum settlements with suppliers for renewable energy and RECs under the existing contract terms.
[9]	PECO entered into various contracts for the procurement of electric supply to serve its default service customers that expire between 2014 and 2015. PECO is permitted to recover its electric supply procurement costs from default service customers with no mark-up in accordance with its PAPUC-approved DSP Programs. See Note 5 b Regulatory Matters for additional information.
[10]	PECO is subject to requirements related to the use of alternative energy resources established by the AEPS Act. See NoteB 5 b Regulatory Matters for additional information.
[11]	BGE entered into various contracts for the procurement of electricity that expire between 2014 through 2016. The cost of power under these contracts is recoverable under MDPSC approved fuel clauses. See Note 5 b Regulatory Matters for additional information.
[12]	BGE has entered into various contracts with curtailment services providers related to transactions in PJMbs capacity market. See Note 5 bRegulatory Matters for additional information.

Commitments_and_Contingencies_3

Commitments and Contingencies - Fuel Purchase Obligations (Details) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified	Sep. 30, 2014
Exelon Generation Co L L C [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	$2,008
2014	104
2015	578
2016	450
2017	303
2018	129
Thereafter	444
Exelon Generation Co L L C [Member] \| Public Utilities, Inventory, Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	9,636
2014	351
2015	1,512
2016	1,226
2017	1,271
2018	1,003
Thereafter	4,273
PECO Energy Co [Member] \| Public Utilities, Inventory, Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	387
2014	57
2015	120
2016	94
2017	35
2018	15
Thereafter	66
Baltimore Gas and Electric Company [Member] \| Public Utilities, Inventory, Fuel [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	624
2014	40
2015	115
2016	81
2017	64
2018	53
Thereafter	$271

Commitments_and_Contingencies_4

Commitments and Contingencies - Other Purchase Obligations (Details) (USD $)	Sep. 30, 2014
In Millions, unless otherwise specified	Sep. 30, 2014
Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	$917
2014	103
2015	324
2016	180
2017	151
2018	36
Thereafter	123
Exelon Generation Co L L C [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	2,008
2014	104
2015	578
2016	450
2017	303
2018	129
Thereafter	444
Exelon Generation Co L L C [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	493	[1],[2]
2014	80	[1],[2]
2015	182	[1],[2]
2016	57	[1],[2]
2017	43	[1],[2]
2018	30	[1],[2]
Thereafter	101	[1],[2]
Commonwealth Edison Co [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	92	[3]
2014	13	[3]
2015	38	[3]
2016	16	[3]
2017	5	[3]
2018	5	[3]
Thereafter	15	[3]
PECO Energy Co [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	29	[3]
2014	7	[3]
2015	11	[3]
2016	2	[3]
2017	1	[3]
2018	1	[3]
Thereafter	7	[3]
Baltimore Gas and Electric Company [Member] \| Other Purchase Obligations [Member]	'
Unrecorded Unconditional Purchase Obligation [Line Items]	'
Total	302	[3]
2014	2	[3]
2015	93	[3]
2016	105	[3]
2017	102	[3]
2018	0	[3]
Thereafter	$0	[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 5 b Regulatory Matters for additional information.

Commitments_and_Contingencies_5

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

9 Months Ended

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Jun. 30, 2012

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Sep. 30, 2013

Sep. 30, 2014

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Beebe Construction [Member]

Perryman Construction [Member]

Fourmile Construction [Member]

Combine-cycle Turbine Units [Member]

Minimum [Member]

Maximum [Member]

Equity Method Investments [Member]

Exelon Generation Co L L C [Member]

Guarantor Obligations [Line Items]

Accrued environmental liabilities

$6,000,000

2015

578,000,000

75,000,000

86,000,000

2014

104,000,000

7,000,000

27,000,000

2017

303,000,000

334,000,000

20,000,000

Business Acquisition, Direct Investment With State And Local Governments Due To Settlement

1,000,000,000

Business Acquisition, Construction Cost

95,000,000

120,000,000

Minimum future operating lease payments due in one year

Minimum future operating lease payments due in three years

10,000,000

Minimum future operating lease payments due in four years

12,000,000

Minimum future operating lease payments due in five years

13,000,000

Minimum future operating lease payments due beyond five years

290,000,000

Business Acquisition, Development Of New Generation Cost

600,000,000

650,000,000

Business Acquisition, Expected New Generation Mwh

285

300

Noncash Merger Related Costs

$44,000,000

($6,000,000)

[1]

$44,000,000

[1]

($6,000,000)

[1]

$105,000,000

[1]

Relates to integration costs to achieve distribution synergies related to the Constellation merger transaction that were reclassified to a regulatory asset. See Note 5 b Regulatory Matters for more information.

Commitments_and_Contingencies_6

Commitments and Contingencies - Schedule of Equity Investment Commitments (Details) (Exelon Generation Co L L C [Member], USD $)	Sep. 30, 2014
In Millions, unless otherwise specified	Sep. 30, 2014
Guarantor Obligations [Line Items]	'
2014	$104
2015	578
2016	450
2017	303
2018	129
Total	2,008
Equity Method Investments [Member]	'
Guarantor Obligations [Line Items]	'
Other Unrecorded Amounts	20
2014	27
2015	86
2016	34
2017	20
2018	15
Total	$182

Commitments_and_Contingencies_7

Commitments and Contingencies - Schedule of Commercial Commitments (Details) (USD $)	Sep. 30, 2014
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	$9,542,000,000
Underwriting Discount	60,000,000	[1]
Financial Standby Letter of Credit [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	1,021,000,000	[2]
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	4,902,000,000	[3]
Estimated net exposure for commercial transaction obligations	467,000,000
Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	3,559,000,000	[4]
Exelon Generation Co L L C [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	6,136,000,000
Exelon Generation Co L L C [Member] \| Financial Standby Letter of Credit [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	973,000,000	[2]
Exelon Generation Co L L C [Member] \| Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	1,604,000,000	[5]
Estimated net exposure for commercial transaction obligations	205,000,000
Exelon Generation Co L L C [Member] \| Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	3,559,000,000	[4]
Commonwealth Edison Co [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	226,000,000
Commonwealth Edison Co [Member] \| Financial Standby Letter of Credit [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	20,000,000	[2]
Commonwealth Edison Co [Member] \| Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	206,000,000	[6]
Commonwealth Edison Co [Member] \| Trust Preferred Securities [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	200,000,000
PECO Energy Co [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	203,000,000
PECO Energy Co [Member] \| Financial Standby Letter of Credit [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	22,000,000	[2]
PECO Energy Co [Member] \| Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	181,000,000	[7]
PECO Energy Co [Member] \| Trust Preferred Securities [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	178,000,000
Baltimore Gas and Electric Company [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	260,000,000
Baltimore Gas and Electric Company [Member] \| Financial Standby Letter of Credit [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	1,000,000	[2]
Baltimore Gas and Electric Company [Member] \| Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	259,000,000	[8]
Baltimore Gas and Electric Company [Member] \| Trust Preferred Securities [Member]	'
Guarantor Obligations [Line Items]	'
Guarantor Obligations, Maximum Exposure, Undiscounted	$250,000,000
Commonwealth Edison III [Member] \| Commonwealth Edison Co [Member]	'
Guarantor Obligations [Line Items]	'
Percentage owned finance subsidiary	100.00%
PECO Trust III and IV [Member] \| PECO Energy Co [Member]	'
Guarantor Obligations [Line Items]	'
Percentage owned finance subsidiary	100.00%
Baltimore Gas and Electric Capital Trust II [Member] \| Baltimore Gas and Electric Company [Member]	'
Guarantor Obligations [Line Items]	'
Percentage owned finance subsidiary	100.00%

[1]	Represents the underwriters discount for Exelonbs forward equity transaction. See Note 16 b Common Stock of the Combined Notes to Consolidated Financial Statements for further details of the equity securities offering.
[2]	Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
[3]	Primarily reflects parental guarantees issued on behalf of Generation to allow the flexibility needed to conduct business with counterparties without having to post other forms of collateral. Also reflects guarantees issued to ensure performance under specific contracts, preferred securities of financing trusts, property leases, indemnifications, NRC minimum funding assurance requirements and miscellaneous guarantees. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $467 million at SeptemberB 30, 2014, which represents the total amount Exelon could be required to fund based on SeptemberB 30, 2014 market prices.
[4]	Represents the maximum amount that Generation would be required to pay for retrospective premiums in the event of nuclear disaster at any domestic site, including CENG sites, under the Secondary Financial Protection pool as required under the Price-Anderson Act as well as the current aggregate annual retrospective premium obligation that could be imposed by NEIL. See the Nuclear Insurance section within this note for additional details on Generationbs nuclear insurance premiums.
[5]	Primarily reflects guarantees issued to ensure performance under energy marketing and other specific contracts. The estimated net exposure for obligations under commercial transactions covered by these guarantees was $205 million at SeptemberB 30, 2014, which represents the total amount Generation could be required to fund based on SeptemberB 30, 2014 market prices.
[6]	Primarily reflects full and unconditional guarantees of $200 million Trust Preferred Securities of ComEd Financing III, which is a 100% owned finance subsidiary of ComEd.
[7]	Primarily reflects full and unconditional guarantees of $178 million Trust Preferred Securities of PECO Trust III and IV, which are 100% owned finance subsidiaries of PECO.
[8]	Primarily reflects full and unconditional guarantees of $250 million Trust Preferred Securities of BGE Capital Trust II, which is a 100% owned finance subsidiary of BGE.

Commitments_and_Contingencies_8

Commitments and Contingencies - Contingencies Narrative (Details) (USD $)	9 Months Ended									0 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2014		Dec. 31, 2013	Jan. 31, 2005	Feb. 26, 2014
		Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]	Nuclear Insurance Premiums [Member]		Nuclear Insurance Premiums [Member]		Sithe Guarantee [Member]	Sithe Guarantee [Member]	Sithe Guarantee [Member]
		reactor					Exelon Generation Co L L C [Member]			Exelon Generation Co L L C [Member]	Exelon Generation Co L L C [Member]
Commitments And Contingencies Additional Narrative Information [Line Items]	'	'	'	'	'		'		'	'	'
Nuclear insurance liability limit per incident	'	'	'	'	'		$13,600,000,000		'	'	'
Required nuclear liability insurance per site	'	375,000,000	'	'	'		'		'	'	'
Total of U.S. licensed nuclear reactors	'	104	'	'	'		'		'	'	'
Nuclear financial protection pool value	'	13,200,000,000	'	'	'		19,000,000		'	'	'
Nuclear Insurance Financial Protection Pool Surcharge On Nuclear Incident Assessment	5.00%	'	'	'	'		'		'	'	'
Maximum assessment mandated by Price-Anderson Act per nuclear reactor for a nuclear incident	'	'	'	'	'		127,300,000		'	'	'
Maximum liability per nuclear incident	'	'	'	3,600,000,000	'		2,700,000,000		'	'	'
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	'	'		'		'	'	'
Acquisition of interest in subsidiary	'	'	'	'	'		'		'	'	50.00%
Sale of interest in subsidiary	'	'	'	'	'		'		'	100.00%	'
Guarantor Obligations, Maximum Exposure, Undiscounted	$9,542,000,000	$6,136,000,000	'	'	$3,559,000,000	[1]	$3,559,000,000	[1]	$200,000,000	'	'

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

Commitments_and_Contingencies_9

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

9 Months Ended

12 Months Ended

0 Months Ended

3 Months Ended

9 Months Ended

1 Months Ended

9 Months Ended

0 Months Ended

9 Months Ended

3 Months Ended

In Millions, unless otherwise specified

Sep. 30, 2014

Dec. 31, 2013

Apr. 11, 2014

Jun. 30, 2013

Sep. 30, 2014

Mar. 31, 2014

Sep. 30, 2014

Jan. 31, 2013

Oct. 31, 2007

Sep. 30, 2014

Dec. 31, 2013

Apr. 12, 2012

Feb. 28, 2012

Sep. 30, 2014

Commonwealth Edison Co [Member]

Midwest Generation, LLC [Member]

PECO Energy Co [Member]

Baltimore Gas and Electric Company [Member]

Exelon Generation Co L L C [Member]

Cotter Corporation [Member]

Sixty-Eighth Street Dump [Member]

Rossville ash site [Member]

Accrual For MGP Investigation And Remediation [Member]

Defendant

MGPSite

state

Defendant

Exelon Generation Co L L C [Member]

Baltimore Gas and Electric Company [Member]

Exelon Generation Co L L C [Member]

Commonwealth Edison Co [Member]

PECO Energy Co [Member]

Principle_responsible_party

Accrual For Environmental Loss Contingencies [Line Items]

Total number of MGP sites

Approved clean-up

Sites under study/remediation

Accrual for Environmental Loss Contingencies, Period Increase (Decrease)

$26

Low end of range of cooling tower cost

430

Consent decree penalty

Environmental loss contingencies

States subject to the Cross State Air Pollution Rule

Emissions allowance balance

Net investment in long-term direct financing leases

357

698

Payments for operating leases

Coal Rail Car Lease Proof of Claims

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

Midwest Generation's estimated environmental investigation and remediation costs

Total cost of remediation to be shared by PRPs

DOJ potential settlement

Loss Contingency, Number of Defendants

Number Of Stations Violating Clean Air Act

Loss Contingency Number Of Parties Jointly And Severally Liable In Environmental Protection Agency Action

Minimum estimated clean-up costs for all potentially responsible parties

Maximum estimated clean-up costs for all potentially responsible parties

1.7

Loss Contingency, Estimate of Possible Loss

Minimum GHG emissions by stationary sources to qualify for regulation

100,000

Minimum additional GHG emissions by stationary sources after a modification

75,000

Effective Number Of Years For Tailoring Rule

'6 years

Recovered_Sheet3

Commitments and Contingencies - Litigation and Regulatory Matters (Details) (USD $)	12 Months Ended	9 Months Ended		0 Months Ended	9 Months Ended		9 Months Ended
	Dec. 31, 2013	Sep. 30, 2014	Dec. 31, 2013	Jul. 11, 2011	Sep. 30, 2014	Jun. 05, 2013	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2014
		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]	Baltimore Gas and Electric Company [Member]
		Open_claim		Customer	claimant	Customer	Maximum [Member]	Minimum [Member]	claimant
					Customer
Asbestos Loss Contingency [Abstract]	'	'	'	'	'	'	'	'	'
Asbestos liability reserve	'	$103,000,000	$90,000,000	'	'	'	'	'	'
Asbestos liability reserve related to open claims	'	22,000,000	'	'	'	'	'	'	'
Open asbestos liability claims	'	265	'	'	'	'	'	'	'
Asbestos liability reserve related to anticipated claims	'	81,000,000	'	'	'	'	'	'	'
Increase (decrease) in the value of the asbestos liability reserve	25,000,000	15,000,000	'	'	'	'	'	'	'
Number of claimants	'	'	'	'	'	'	'	'	486
Continuous Power Interruption [Abstract]	'	'	'	'	'	'	'	'	'
Minimum number of customers ComEd can be held liable to for power interruption	'	'	'	'	30,000	'	'	'	'
Number of customers affected by a major storm	'	'	'	900,000	'	'	'	'	'
Number of customers proposed by the ICC that ComEd should not be granted a waiver under Continuous Power Interruption	'	'	'	'	'	34,559	'	'	'
Telephone Consumer Protection Act Lawsuit [Abstract]	'	'	'	'	'	'	'	'	'
Possible Defendants Number	'	'	'	'	1,200,000	'	'	'	'
Loss Contingency, Damages Sought, Value	'	'	'	'	'	'	$1,500	$500	'

Recovered_Sheet4

Commitments and Contingencies - Schedule of Accruals for Environmental Matters (Details) (USD $)	Sep. 30, 2014	Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Total Accrual For Environmental Loss Contingencies [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	$342	$338
Total Accrual For Environmental Loss Contingencies [Member] \| Exelon Generation Co L L C [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	55	56
Total Accrual For Environmental Loss Contingencies [Member] \| Commonwealth Edison Co [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	241	234
Total Accrual For Environmental Loss Contingencies [Member] \| PECO Energy Co [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	45	47
Total Accrual For Environmental Loss Contingencies [Member] \| Baltimore Gas and Electric Company [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	1	1
Accrual For MGP Investigation And Remediation [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	280	273
Accrual For MGP Investigation And Remediation [Member] \| Exelon Generation Co L L C [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	0	0
Accrual For MGP Investigation And Remediation [Member] \| Commonwealth Edison Co [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	237	229
Accrual For MGP Investigation And Remediation [Member] \| PECO Energy Co [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	43	44
Accrual For MGP Investigation And Remediation [Member] \| Baltimore Gas and Electric Company [Member]	'	'
Accrual For Environmental Loss Contingencies [Line Items]	'	'
Accrued environmental liabilities	$0	$0

Supplemental_Financial_Informa2

Supplemental Financial Information - Narrative (Details) (USD $)	9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013
Supplemental Financial Information Tables [Line Items]	'	'
Smart Grid Grant Project Capital Expenditures	'	$68
Smart Grid Grant Reimbursements	'	64
PECO Energy Co [Member]	'	'
Supplemental Financial Information Tables [Line Items]	'	'
Smart Grid Grant Project Capital Expenditures	2	22
Smart Grid Grant Reimbursements	5	30
Financing Receivable, Net	19	'
Financing Receivable, Allowance for Credit Losses	19	18
Baltimore Gas and Electric Company [Member]	'	'
Supplemental Financial Information Tables [Line Items]	'	'
Smart Grid Grant Project Capital Expenditures	'	46
Smart Grid Grant Reimbursements	'	34
Low To Medium Risk [Member] \| PECO Energy Co [Member]	'	'
Supplemental Financial Information Tables [Line Items]	'	'
Financing Receivable, Net	1	1
Risk Level, Medium [Member] \| PECO Energy Co [Member]	'	'
Supplemental Financial Information Tables [Line Items]	'	'
Financing Receivable, Net	4	4
Risk Level, High [Member] \| PECO Energy Co [Member]	'	'
Supplemental Financial Information Tables [Line Items]	'	'
Financing Receivable, Net	$14	$13

Supplemental_Financial_Informa3

Supplemental Financial Information - Operations (Detail) (USD $)	3 Months Ended			9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013		Sep. 30, 2014	Sep. 30, 2013
Decommissioning-Related Activities [Abstract]	'	'		'	'
Net realized income on decommissioning trust funds - Regulatory Agreement Units	$55	$138	[1]	$167	$221	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	39	35	[1]	102	65	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	-107	103		126	196
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	-41	46		100	70
Net unrealized income (losses) on pledged assets	7	-9		27	-5
Regulatory offset to decommissioning trust fund-related activities	29	-189	[2]	-270	-338	[2]
Total decommissioning-related activities	-18	124		252	209
Investment income	0	1		1	6
Long-term lease income	4	7		20	20
Interest income related to uncertain income tax positions	25	'		41	24
AFUDC - equity	5	4		17	16
Gain (Loss) on Disposition of Assets	338	10		356	17
Other Income	0	9		15	19
Other, net	354	155		702	311
Exelon Generation Co L L C [Member]	'	'		'	'
Decommissioning-Related Activities [Abstract]	'	'		'	'
Net realized income on decommissioning trust funds - Regulatory Agreement Units	55	138	[1]	167	221	[1]
Net realized income on decommissioning trust funds - Non-Regulatory Agreement Units	39	35	[1]	102	65	[1]
Net unrealized income (losses) on decommissioning trust funds - Regulatory Agreement Units	-107	103		126	196
Net unrealized income (losses) on decommissioning trust funds - Non-Regulatory Agreement	-41	46		100	70
Net unrealized income (losses) on pledged assets	7	-9		27	-5
Regulatory offset to decommissioning trust fund-related activities	29	-189	[2]	-270	-338	[2]
Total decommissioning-related activities	-18	124		252	209
Investment income	0	0		1	-1
Interest income related to uncertain income tax positions	27	'		53	3
Gain (Loss) on Disposition of Assets	338	8		355	13
Other Income	-5	2		0	5
Other, net	342	134		661	229
Commonwealth Edison Co [Member]	'	'		'	'
Decommissioning-Related Activities [Abstract]	'	'		'	'
Investment income	0	'		0	'
Interest income related to uncertain income tax positions	0	'		0	0
AFUDC - equity	0	2		3	8
Gain (Loss) on Disposition of Assets	0	2		1	2
Other Income	4	3		10	8
Other, net	4	7		14	18
PECO Energy Co [Member]	'	'		'	'
Decommissioning-Related Activities [Abstract]	'	'		'	'
Investment income	0	0		-1	-1
Interest income related to uncertain income tax positions	0	'		0	1
AFUDC - equity	2	1		5	3
Gain (Loss) on Disposition of Assets	0	0		0	0
Other Income	0	0		1	1
Other, net	2	1		5	4
Baltimore Gas and Electric Company [Member]	'	'		'	'
Decommissioning-Related Activities [Abstract]	'	'		'	'
Investment income	1	2	[3]	5	7	[3]
Interest income related to uncertain income tax positions	0	'		0	'
AFUDC - equity	3	1		9	5
Gain (Loss) on Disposition of Assets	0	0		0	0
Other Income	0	1		0	1
Other, net	$4	$4		$14	$13

[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 b Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
[3]	Relates to the cash return on BGEbs rate stabilization deferral. See Note 5 b Regulatory Matters for additional information regarding the rate stabilization deferral.

Supplemental_Financial_Informa4

Supplemental Financial Information - Cash Flow (Details) (USD $)	3 Months Ended		9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013
Depreciation, Amortization and Accretion [Abstract]	'	'	'		'
Property, plant and equipment	'	'	$1,549		$1,420
Regulatory assets	'	'	150		153
Amortization of intangible assets, net	'	'	33		33
Amortization of energy contract assets and liabilities	'	'	83	[1]	342	[1]
Nuclear fuel	'	'	790	[2]	689	[2]
Asset retirement obligation accretion	'	'	251	[3]	207	[3]
Total depreciation, amortization and accretion	'	'	2,856		2,844
Other Non-Cash Operating Activities [Abstract]	'	'	'		'
Pension and non-pension postretirement benefits costs	'	'	437		621
Gain (loss) on equity method investments	-1	-37	20		-7
Provision for uncollectible accounts	'	'	96		83
Stock-based compensation costs	'	'	111		99
Other Decommissioning Related Activity	'	'	-102	[4]	-110	[4]
Energy-related options	'	'	92	[5]	87	[5]
Amortization of regulatory asset related to debt costs	'	'	8		9
Amortization of rate stabilization deferral	'	'	50		49
Amortization of debt fair value adjustment	'	'	-45		-28
Discrete impacts from EIMA	'	'	-32	[6]	-206	[6]
Amortization of debt costs	'	'	36		13
Merger related commitments	'	'	44		-6	[7]
Inventory Write-down	'	'	'		7
Other	'	'	-17		-27
Total other noncash operating activities	'	'	698		584
Changes In Other Assets and Liabilities [Abstract]	'	'	'		'
Under/over-recovered energy and transmission costs	'	'	53		-47
Other regulatory assets and liabilities	'	'	-63		-50
Increase (Decrease) in Deposits	'	'	-280	[8]	'
Increase (Decrease) in Other Current Liabilities	'	'	-78		'
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	'	'	168		'
Increase (Decrease) in Other Noncurrent Liabilities	'	'	'		26	[9]
Other current assets and liabilities	'	'	'		-169
Other noncurrent assets and liabilities	'	'	'		205
Total changes in other assets and liabilities	'	'	-536		-35
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Non cash Fair Value Adjustment for CENG	'	'	-3,400	[10]	'
Debt exchange	'	'	131	[11]	'
Non Cash Debt Instrument Issued	'	'	70	[12]	'
Consolidated VIE dividend to non-controlling interest	'	'	-415		0
Total noncash investing and financing activities	'	'	-3,199		63
Indemnification Agreement [Member]	'	'	'		'
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Consolidated VIE dividend to non-controlling interest	'	'	'		63
Exelon Generation Co L L C [Member]	'	'	'		'
Depreciation, Amortization and Accretion [Abstract]	'	'	'		'
Property, plant and equipment	'	'	686		610
Amortization of intangible assets, net	'	'	33		33
Amortization of energy contract assets and liabilities	'	'	93	[1]	398	[1]
Nuclear fuel	'	'	790	[2]	689	[2]
Asset retirement obligation accretion	'	'	251	[3]	207	[3]
Total depreciation, amortization and accretion	'	'	1,853		1,937
Other Non-Cash Operating Activities [Abstract]	'	'	'		'
Pension and non-pension postretirement benefits costs	'	'	193		259
Gain (loss) on equity method investments	-1	-37	20		-7
Provision for uncollectible accounts	'	'	10		16
Stock-based compensation costs	'	'	'		0
Other Decommissioning Related Activity	'	'	-102	[4]	-110	[4]
Energy-related options	'	'	92	[5]	87	[5]
Amortization of regulatory asset related to debt costs	'	'	'		0
Amortization of rate stabilization deferral	'	'	'		0
Amortization of debt fair value adjustment	'	'	-17		-28
Discrete impacts from EIMA	'	'	'		0	[6]
Amortization of debt costs	'	'	9		7
Merger related commitments	'	'	44		0	[7]
Inventory Write-down	'	'	'		7
Other	'	'	2		0
Total other noncash operating activities	'	'	251		231
Changes In Other Assets and Liabilities [Abstract]	'	'	'		'
Increase (Decrease) in Deposits	'	'	-280	[8]	'
Increase (Decrease) in Other Current Liabilities	'	'	24		'
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	'	'	111		'
Other current assets and liabilities	'	'	'		-123
Other noncurrent assets and liabilities	'	'	'		-40
Total changes in other assets and liabilities	'	'	-367		-163
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Non cash Fair Value Adjustment for CENG	'	'	-3,400	[10]	'
Non Cash Debt Instrument Issued	'	'	70	[12]	'
Consolidated VIE dividend to non-controlling interest	'	'	-415		0
Total noncash investing and financing activities	'	'	-3,330		63
Exelon Generation Co L L C [Member] \| Indemnification Agreement [Member]	'	'	'		'
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Consolidated VIE dividend to non-controlling interest	'	'	'		63
Commonwealth Edison Co [Member]	'	'	'		'
Depreciation, Amortization and Accretion [Abstract]	'	'	'		'
Property, plant and equipment	'	'	438		413
Regulatory assets	'	'	83		88
Total depreciation, amortization and accretion	'	'	521		501
Other Non-Cash Operating Activities [Abstract]	'	'	'		'
Pension and non-pension postretirement benefits costs	'	'	129		231
Provision for uncollectible accounts	'	'	9		-6
Stock-based compensation costs	'	'	0		'
Energy-related options	'	'	'		0	[5]
Amortization of regulatory asset related to debt costs	'	'	6		7
Discrete impacts from EIMA	'	'	-32	[6]	-206	[6]
Amortization of debt costs	'	'	4		3
Other	'	'	0		-3
Total other noncash operating activities	'	'	116		26
Changes In Other Assets and Liabilities [Abstract]	'	'	'		'
Under/over-recovered energy and transmission costs	'	'	63		-63
Other regulatory assets and liabilities	'	'	-14		-35
Increase (Decrease) in Deposits	'	'	0	[8]	'
Increase (Decrease) in Other Current Liabilities	'	'	-9		'
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	'	'	-22		'
Other current assets and liabilities	'	'	'		47
Other noncurrent assets and liabilities	'	'	'		261	[13]
Total changes in other assets and liabilities	'	'	62		210
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Indemnification of like-kind exchange position	'	'	168		0
Total noncash investing and financing activities	'	'	4		175
Commonwealth Edison Co [Member] \| Indemnification Agreement [Member]	'	'	'		'
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Indemnification of like-kind exchange position	'	'	4	[14]	175	[10]
PECO Energy Co [Member]	'	'	'		'
Depreciation, Amortization and Accretion [Abstract]	'	'	'		'
Property, plant and equipment	'	'	169		164
Regulatory assets	'	'	7		7
Total depreciation, amortization and accretion	'	'	176		171
Other Non-Cash Operating Activities [Abstract]	'	'	'		'
Pension and non-pension postretirement benefits costs	'	'	28		32
Gain (loss) on equity method investments	'	'	'		0
Provision for uncollectible accounts	'	'	39		48
Stock-based compensation costs	'	'	0		0
Other Decommissioning Related Activity	'	'	'		0	[4]
Energy-related options	'	'	'		0	[5]
Amortization of regulatory asset related to debt costs	'	'	2		2
Amortization of rate stabilization deferral	'	'	'		0
Amortization of debt fair value adjustment	'	'	'		0
Discrete impacts from EIMA	'	'	'		0	[6]
Amortization of debt costs	'	'	2		2
Merger related commitments	'	'	'		0	[7]
Other	'	'	-1		0
Total other noncash operating activities	'	'	70		84
Changes In Other Assets and Liabilities [Abstract]	'	'	'		'
Under/over-recovered energy and transmission costs	'	'	-14		-10
Other regulatory assets and liabilities	'	'	-14		0
Increase (Decrease) in Deposits	'	'	0	[8]	'
Increase (Decrease) in Other Current Liabilities	'	'	-48	[15]	'
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	'	'	-1		'
Other current assets and liabilities	'	'	'		-31	[15]
Other noncurrent assets and liabilities	'	'	'		-6
Total changes in other assets and liabilities	'	'	-75		-47
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Indemnification of like-kind exchange position	'	'	24		0
Baltimore Gas and Electric Company [Member]	'	'	'		'
Depreciation, Amortization and Accretion [Abstract]	'	'	'		'
Property, plant and equipment	'	'	215		194
Regulatory assets	'	'	60		58
Total depreciation, amortization and accretion	'	'	275		252
Other Non-Cash Operating Activities [Abstract]	'	'	'		'
Pension and non-pension postretirement benefits costs	'	'	50		41
Gain (loss) on equity method investments	'	'	'		0
Provision for uncollectible accounts	'	'	38		25
Stock-based compensation costs	'	'	0		0
Other Decommissioning Related Activity	'	'	'		0	[4]
Energy-related options	'	'	'		0	[5]
Amortization of regulatory asset related to debt costs	'	'	0		0
Amortization of rate stabilization deferral	'	'	50		49
Amortization of debt fair value adjustment	'	'	'		0
Discrete impacts from EIMA	'	'	'		0	[6]
Amortization of debt costs	'	'	2		1
Merger related commitments	'	'	'		-6	[7]
Other	'	'	-11		-5
Total other noncash operating activities	'	'	129		105
Changes In Other Assets and Liabilities [Abstract]	'	'	'		'
Under/over-recovered energy and transmission costs	'	'	6		26
Other regulatory assets and liabilities	'	'	-89		-85
Increase (Decrease) in Deposits	'	'	0	[8]	'
Increase (Decrease) in Other Current Liabilities	'	'	25		'
Increase (Decrease) in Other Noncurrent Assets and Liabilities, Net	'	'	9		'
Other current assets and liabilities	'	'	'		-35
Other noncurrent assets and liabilities	'	'	'		-25
Total changes in other assets and liabilities	'	'	-67		-119
Cash Flow, Noncash Investing and Financing Activities Disclosure [Abstract]	'	'	'		'
Indemnification of like-kind exchange position	'	'	$0		'

[1]	Included in Operating revenues or Purchased power and fuel expense on the Registrantsb Consolidated Statements of Operations and Comprehensive Income.
[2]	Included in Purchased power and fuel expense on the Registrantsb Consolidated Statements of Operations and Comprehensive Income.
[3]	Included in Operating and maintenance expense on the Registrantsb Consolidated Statements of Operations and Comprehensive Income.
[4]	Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 15 - Asset Retirement Obligations of the Exelon 2013 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
[5]	Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
[6]	Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate tariff. See Note 5 b Regulatory Matters for more information.
[7]	Relates to integration costs to achieve distribution synergies related to the Constellation merger transaction that were reclassified to a regulatory asset. See Note 5 b Regulatory Matters for more information.
[8]	Relates primarily to cash deposits made to ISO's/RTO's.
[9]	Relates to settlement of forward starting interest rate swaps that Exelon entered into in anticipation of Continental Wind, LLC non-recourse project financing that was completed on September 30, 2013. See Note 9 b Derivative Financial Instruments for more information on interest rate swaps.
[10]	See Note 6 b Investment in Constellation Energy Nuclear Group, LLC for additional information.
[11]	Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 16 b Common Stock for additional information.
[12]	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.
[13]	Relates primarily to interest payable related to like-kind exchange tax position. See Note 11 b Income Taxes for discussion of the like-kind exchange tax position.
[14]	See Note 11 b Income Taxes for discussion of the like-kind exchange tax position.
[15]	Relates primarily to prepaid utility taxes.

Supplemental_Financial_Informa5

Supplemental Financial Information - Balance Sheet (Details) (USD $)	Sep. 30, 2014		Dec. 31, 2013
In Millions, unless otherwise specified	Sep. 30, 2014		Dec. 31, 2013
Property, Plant and Equipment, Net [Abstract]	'		'
Accumulated depreciation	$14,932	[1]	$13,713	[2]
Accounts receivable, net	'		'
Allowance for uncollectible accounts	291		272
Exelon Generation Co L L C [Member]	'		'
Property, Plant and Equipment, Net [Abstract]	'		'
Accumulated depreciation	7,868	[1]	7,034	[2]
Accounts receivable, net	'		'
Allowance for uncollectible accounts	55		57
Accumulated amortization of nuclear fuel	2,729		2,371
Commonwealth Edison Co [Member]	'		'
Property, Plant and Equipment, Net [Abstract]	'		'
Accumulated depreciation	3,370		3,184
Accounts receivable, net	'		'
Allowance for uncollectible accounts	80		62
PECO Energy Co [Member]	'		'
Property, Plant and Equipment, Net [Abstract]	'		'
Accumulated depreciation	2,972		2,935
Accounts receivable, net	'		'
Allowance for uncollectible accounts	115		107
Baltimore Gas and Electric Company [Member]	'		'
Property, Plant and Equipment, Net [Abstract]	'		'
Accumulated depreciation	2,825		2,702
Accounts receivable, net	'		'
Allowance for uncollectible accounts	$41		$46

[1]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,729 million.
[2]	Includes accumulated amortization of nuclear fuel in the reactor core of $2,371 million.

Segment_Information_Narrative_

Segment Information - Narrative (Details)	9 Months Ended
	Sep. 30, 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_Reconcilia

Segment Information - Reconciliation to Consolidated Financial Statements (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013		Dec. 31, 2013
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	$6,912	[1]	$6,502	[1]	$20,173	[2]	$18,725	[2]	'
Operating revenues from affiliates	0	[3]	2	[3]	0	[4]	2	[4]	'
Net income (loss)	1,074		736		1,725		1,235		'
Assets	85,264		79,924		85,264		79,924		79,924
Exelon Generation Co L L C [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	-15		'		'		'		'
Generation Midwest [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	1,061		1,013		3,313		3,271		'
Segment Elimination [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	'		'		'		603		'
Generation Total Consolidated Group [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	4,412	[5]	4,255	[5]	12,591		11,858		'
Commonwealth Edison Co Affiliate [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	22		125		203		'		'
Operating Segments [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Utility taxes	22		21		67		60		'
Operating Segments [Member] \| Exelon Generation Co L L C [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	4,412	[1],[6]	4,255	[1],[6]	12,591	[2],[7],[8]	11,858	[2],[7],[8]	'
Operating revenues from affiliates	112	[3],[6]	373	[3],[6]	630	[4],[7],[8]	1,083	[4],[7],[8]	'
Net income (loss)	849	[6]	485	[6]	1,037	[7],[8]	795	[7],[8]	'
Assets	45,019	[6]	41,232	[6]	45,019	[6]	41,232	[6]	'
Operating Segments [Member] \| Generation Midwest [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	1,062	[5]	1,018	[5]	3,302	[9]	3,274	[9]	'
Operating Segments [Member] \| Commonwealth Edison Co [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	1,222	[1]	1,156	[1]	3,484	[2]	3,395	[2]	'
Operating revenues from affiliates	1	[3]	1	[3]	2	[4]	2	[4]	'
Net income (loss)	126		126		335		140		'
Assets	24,845		24,118		24,845		24,118		'
Utility taxes	61		65		180		182		'
Operating Segments [Member] \| PECO Energy Co [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	693	[1]	728	[1]	2,343	[2]	2,295	[2]	'
Operating revenues from affiliates	0	[3]	1	[3]	1	[4]	1	[4]	'
Net income (loss)	81		92		255		292		'
Assets	10,051		9,617		10,051		9,617		'
Utility taxes	34		33		99		97		'
Operating Segments [Member] \| Baltimore Gas and Electric Company [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	697	[1]	737	[1]	2,404	[2]	2,271	[2]	'
Operating revenues from affiliates	3	[3]	2	[3]	21	[4]	10	[4]	'
Net income (loss)	49		53		156		160		'
Assets	7,915		7,861		7,915		7,861		'
Utility taxes	21		20		64		62		'
Operating Segments [Member] \| Generation Total Consolidated Group [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	'		'		12,591	[9]	11,858	[9]	'
Operating Segments [Member] \| PECO Energy Co Affiliate [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	28		82		165		321		'
Operating Segments [Member] \| Baltimore Gas And Electric Company Affiliate [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	83		144		290		356		'
Operating Segments [Member] \| Commonwealth Edison Co Affiliate [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	1		143		175		409		'
Operating Segments [Member] \| Commonwealth Edison Co Affiliate [Member] \| Generation Midwest [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	'		'		'		7		'
Other Segments [Member] \| Corporate and Other [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	305	[1],[10]	294	[1],[10]	924	[10],[2]	909	[10],[2]	'
Operating revenues from affiliates	302	[10],[3]	294	[10],[3]	920	[10],[4]	909	[10],[4]	'
Net income (loss)	-31	[10]	-20	[10]	-58	[10]	-152	[10]	'
Assets	8,713	[10]	8,317	[10]	8,713	[10]	8,317	[10]	'
Intersegment Eliminations [Member] \| Generation Midwest [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	-1		-5		11		-3		'
Intersegment Eliminations [Member] \| Segment Elimination [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	-417	[1]	-668	[1]	-1,573	[2]	-2,003	[2]	'
Operating revenues from affiliates	-418	[3]	-669	[3]	-1,574	[4]	-2,003	[4]	'
Net income (loss)	0		0		0		0		'
Assets	-11,279		-11,221		-11,279		-11,221		'
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]	'		'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'		'
Revenues	$0		$0		$0		$0		'

[1]	For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.
[2]	For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.
[3]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generationbs sale of certain products and services by and between Exelonbs 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.
[4]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generationbs sale of certain products and services by and between Exelonbs 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.
[5]	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[6]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended SeptemberB 30, 2014 include revenue from sales to PECO of $28 million and sales to BGE of $83 million in the Mid-Atlantic region, and sales to ComEd of $1 million in the Midwest region. For the three months ended SeptemberB 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $82 million and sales to BGE of $144 million in the Mid-Atlantic region, and sales to ComEd of $143 million in the Midwest region
[7]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended SeptemberB 30, 2014 include revenue from sales to PECO of $165 million and sales to BGE of $290 million in the Mid-Atlantic region, and sales to ComEd of $175 million in the Midwest. For the nine months ended SeptemberB 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $321 million and sales to BGE of $356 million in the Mid-Atlantic region, and sales to ComEd of $409 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 include activity recorded at CENG from April 1, 2014, the date of integration, through SeptemberB 30, 2014.
[9]	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[10]	Other primarily includes Exelonbs corporate operations, shared service entities and other financing and investment activities.

Segment_Information_Generation

Segment Information - Generation Total Revenues (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	$6,912	[1]	$6,502	[1]	$20,173	[2]	$18,725	[2]
Revenue from Related Parties	0	[3]	2	[3]	0	[4]	2	[4]
Net income (loss)	1,074		736		1,725		1,235
Segment Elimination [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	'		'		'		603
Generation Mid Atlantic [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	1,289		1,391		3,984	[5]	3,943	[5]
Generation New England [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	272		340		1,033		933
Generation New York [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	232		184		613	[5]	527	[5]
Generation ERCOT [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	302		427		741		1,034
Generation Other Regions [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	375	[6]	271	[6]	1,023	[6]	737	[6]
Generation Reportable Segments Total [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	3,531		3,626		10,707		10,445
Generation All Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	881	[7]	629	[7]	1,884	[8]	1,413	[8]
Generation Total Consolidated Group [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	4,412	[9]	4,255	[9]	12,591		11,858
Exelon Generation Co L L C [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	-15		'		'		'
Operating Segments [Member] \| Generation Mid Atlantic [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	1,285	[9]	1,381	[9]	3,998	[10],[5]	3,932	[10],[5]
Operating Segments [Member] \| Generation New England [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	272	[9]	341	[9]	1,028	[10]	942	[10]
Operating Segments [Member] \| Generation New York [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	230	[9]	198	[9]	614	[10],[5]	547	[10],[5]
Operating Segments [Member] \| Generation ERCOT [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	303	[9]	430	[9]	743	[10]	1,042	[10]
Operating Segments [Member] \| Generation Other Regions [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	381	[6],[9]	278	[6],[9]	1,027	[10],[6]	708	[10],[6]
Operating Segments [Member] \| Generation Reportable Segments Total [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	3,533	[9]	3,646	[9]	10,712	[10]	10,445	[10]
Operating Segments [Member] \| Generation Total Consolidated Group [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	'		'		12,591	[10]	11,858	[10]
Operating Segments [Member] \| Exelon Generation Co L L C [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	4,412	[1],[11]	4,255	[1],[11]	12,591	[12],[2],[5]	11,858	[12],[2],[5]
Revenue from Related Parties	112	[11],[3]	373	[11],[3]	630	[12],[4],[5]	1,083	[12],[4],[5]
Net income (loss)	849	[11]	485	[11]	1,037	[12],[5]	795	[12],[5]
Intersegment Eliminations [Member] \| Segment Elimination [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	-417	[1]	-668	[1]	-1,573	[2]	-2,003	[2]
Revenue from Related Parties	-418	[3]	-669	[3]	-1,574	[4]	-2,003	[4]
Net income (loss)	0		0		0		0
Intersegment Eliminations [Member] \| Generation Mid Atlantic [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	4		10		-14	[5]	11	[5]
Intersegment Eliminations [Member] \| Generation New England [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	0		-1		5		-9
Intersegment Eliminations [Member] \| Generation New York [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	2		-14		-1	[5]	-20	[5]
Intersegment Eliminations [Member] \| Generation ERCOT [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	-1		-3		-2		-8
Intersegment Eliminations [Member] \| Generation Other Regions [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	-6	[6]	-7	[6]	-4	[6]	29	[6]
Intersegment Eliminations [Member] \| Generation Reportable Segments Total [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	-2		-20		-5		0
Intersegment Eliminations [Member] \| Generation All Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	2	[7]	20	[7]	5	[8]	0	[8]
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	0		0		0		0
Other Segments [Member] \| Corporate and Other [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	305	[1],[13]	294	[1],[13]	924	[13],[2]	909	[13],[2]
Revenue from Related Parties	302	[13],[3]	294	[13],[3]	920	[13],[4]	909	[13],[4]
Net income (loss)	-31	[13]	-20	[13]	-58	[13]	-152	[13]
Other Segments [Member] \| Generation All Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	879	[7],[9]	609	[7],[9]	1,879	[10],[8]	1,413	[10],[8]
Commonwealth Edison Co Affiliate [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	22		125		203		'
Commonwealth Edison Co Affiliate [Member] \| Operating Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	$1		$143		$175		$409

[1]	For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.
[2]	For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.
[3]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generationbs sale of certain products and services by and between Exelonbs 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.
[4]	Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with the Generationbs sale of certain products and services by and between Exelonbs 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.
[5]	Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through SeptemberB 30, 2014.
[6]	Other regions include the South, West and Canada, which are not considered individually significant.
[7]	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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $22 million decrease to revenues and $125 million decrease to revenues for the three months ended SeptemberB 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.
[8]	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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $203 million decrease to revenues and $603 million decrease to revenues, for the nine months ended SeptemberB 30, 2014 and 2013, respectively, and elimination of intersegment revenues.
[9]	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[10]	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[11]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended SeptemberB 30, 2014 include revenue from sales to PECO of $28 million and sales to BGE of $83 million in the Mid-Atlantic region, and sales to ComEd of $1 million in the Midwest region. For the three months ended SeptemberB 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $82 million and sales to BGE of $144 million in the Mid-Atlantic region, and sales to ComEd of $143 million in the Midwest region
[12]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended SeptemberB 30, 2014 include revenue from sales to PECO of $165 million and sales to BGE of $290 million in the Mid-Atlantic region, and sales to ComEd of $175 million in the Midwest. For the nine months ended SeptemberB 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $321 million and sales to BGE of $356 million in the Mid-Atlantic region, and sales to ComEd of $409 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.
[13]	Other primarily includes Exelonbs corporate operations, shared service entities and other financing and investment activities.

Segment_Information_Generation1

Segment Information - Generation Total Revenues Net of Purchased Power and Fuel Expense (Details) (USD $)	3 Months Ended				9 Months Ended
In Millions, unless otherwise specified	Sep. 30, 2014		Sep. 30, 2013		Sep. 30, 2014		Sep. 30, 2013
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		$194	[1],[2]	'		'
Intersegment RNF	178	[2]	179	[2]	'		'
Total RNF	428	[2]	373	[2]	'		'
Revenues	6,912	[3]	6,502	[3]	20,173	[4]	18,725	[4]
Generation Total Consolidated Group [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Total RNF	'		'		5,520		5,564
Revenues	4,412	[5]	4,255	[5]	12,591		11,858
Exelon Generation Co L L C [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	-15		'		'		'
Generation Mid Atlantic [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		857	[1]	'		'
Intersegment RNF	14		7		'		'
Total RNF	935		864		2,550	[6]	2,475	[6]
Revenues	1,289		1,391		3,984	[6]	3,943	[6]
Generation Midwest [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		606	[1]	'		'
Intersegment RNF	-6		-5		'		'
Total RNF	716		601		1,877		2,001
Revenues	1,061		1,013		3,313		3,271
Generation New England [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		52	[1]	'		'
Intersegment RNF	-30		10		'		'
Total RNF	90		62		290		142
Revenues	272		340		1,033		933
Generation New York [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		29	[1]	'		'
Intersegment RNF	10		-38		'		'
Total RNF	186		-9		313	[6]	-17	[6]
Revenues	232		184		613	[6]	527	[6]
Generation ERCOT [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		222	[1]	'		'
Intersegment RNF	-77		-78		'		'
Total RNF	109		144		250		357
Revenues	302		427		741		1,034
Generation Other Regions [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		116	[1],[7]	'		'
Intersegment RNF	-89	[7]	-75	[7]	'		'
Total RNF	68	[7]	41	[7]	249	[7]	147	[7]
Revenues	375	[7]	271	[7]	1,023	[7]	737	[7]
Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		1,882	[1]	'		'
Intersegment RNF	-178		-179		'		'
Total RNF	2,104		1,703		'		'
Revenues	'		44		78		386
Generation All Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		2,076	[1]	-519	[1],[8]	200	[1],[8]
Intersegment RNF	0		0		510	[8]	259	[8]
Total RNF	2,532		2,076		-9	[8]	459	[8]
Revenues	881	[9]	629	[9]	1,884	[10]	1,413	[10]
Generation Reportable Segments Total [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Total RNF	'		'		5,529		5,105
Revenues	3,531		3,626		10,707		10,445
Operating Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	250	[1],[2]	'		'		'
Operating Segments [Member] \| Generation Total Consolidated Group [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		'		5,520	[1]	5,564	[1]
Revenues	'		'		12,591	[11]	11,858	[11]
Operating Segments [Member] \| Exelon Generation Co L L C [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	4,412	[12],[3]	4,255	[12],[3]	12,591	[13],[4],[6]	11,858	[13],[4],[6]
Operating Segments [Member] \| Generation Mid Atlantic [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	921	[1]	'		2,610	[1],[6]	2,477	[1],[6]
Revenues	1,285	[5]	1,381	[5]	3,998	[11],[6]	3,932	[11],[6]
Operating Segments [Member] \| Generation Midwest [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	722	[1]	'		1,856	[1]	2,002	[1]
Revenues	1,062	[5]	1,018	[5]	3,302	[11]	3,274	[11]
Operating Segments [Member] \| Generation New England [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	120	[1]	'		362	[1]	156	[1]
Revenues	272	[5]	341	[5]	1,028	[11]	942	[11]
Operating Segments [Member] \| Generation New York [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	176	[1]	'		289	[1],[6]	14	[1],[6]
Revenues	230	[5]	198	[5]	614	[11],[6]	547	[11],[6]
Operating Segments [Member] \| Generation ERCOT [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	186	[1]	'		457	[1]	477	[1]
Revenues	303	[5]	430	[5]	743	[11]	1,042	[11]
Operating Segments [Member] \| Generation Other Regions [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	157	[1],[7]	'		465	[1],[7]	238	[1],[7]
Revenues	381	[5],[7]	278	[5],[7]	1,027	[11],[7]	708	[11],[7]
Operating Segments [Member] \| Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	2,282	[1]	'		'		'
Operating Segments [Member] \| Generation All Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	2,532	[1]	'		'		'
Operating Segments [Member] \| Generation Reportable Segments Total [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
RNF from external customers	'		'		6,039	[1]	5,364	[1]
Revenues	3,533	[5]	3,646	[5]	10,712	[11]	10,445	[11]
Intersegment Eliminations [Member] \| Generation Total Consolidated Group [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		0		0
Revenues	0		0		0		0
Intersegment Eliminations [Member] \| Generation Mid Atlantic [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		-60	[6]	-2	[6]
Revenues	4		10		-14	[6]	11	[6]
Intersegment Eliminations [Member] \| Generation Midwest [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		21		-1
Revenues	-1		-5		11		-3
Intersegment Eliminations [Member] \| Generation New England [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		-72		-14
Revenues	0		-1		5		-9
Intersegment Eliminations [Member] \| Generation New York [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		24	[6]	-31	[6]
Revenues	2		-14		-1	[6]	-20	[6]
Intersegment Eliminations [Member] \| Generation ERCOT [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		-207		-120
Revenues	-1		-3		-2		-8
Intersegment Eliminations [Member] \| Generation Other Regions [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		-216	[7]	-91	[7]
Revenues	-6	[7]	-7	[7]	-4	[7]	29	[7]
Intersegment Eliminations [Member] \| Generation All Other Segments [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Revenues	2	[9]	20	[9]	5	[10]	0	[10]
Intersegment Eliminations [Member] \| Generation Reportable Segments Total [Member]	'		'		'		'
Segment Reporting Information [Line Items]	'		'		'		'
Intersegment RNF	'		'		-510		-259
Revenues	($2)		($20)		($5)		$0

[1]	Includes purchases and sales from third parties and affiliated sales to ComEd, PECO and BGE.
[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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $15 million increase to RNF and $44 million decrease to RNF for the three months ended SeptemberB 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.
[3]	For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $22 million and $21 million, respectively, are included in revenues and expenses for Generation. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $61 million and $65 million, respectively, are included in revenues and expenses for ComEd. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $34 million and $33 million, respectively, are included in revenues and expenses for PECO. For the three months ended SeptemberB 30, 2014 and 2013, utility taxes of $21 million and $20 million, respectively, are included in revenues and expenses for BGE.
[4]	For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $67 million and $60 million, respectively, are included in revenues and expenses for Generation. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $180 million and $182 million, respectively, are included in revenues and expenses for ComEd. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $99 million and $97 million, respectively, are included in revenues and expenses for PECO. For the nine months ended SeptemberB 30, 2014 and 2013, utility taxes of $64 million and $62 million, respectively, are included in revenues and expenses for BGE.
[5]	Includes all electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[6]	Amounts include activity recorded at CENG from April 1, 2014, the date of integration, through SeptemberB 30, 2014.
[7]	Other regions include the South, West and Canada, which are not considered individually significant.
[8]	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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $78 million decrease to RNF and $386 million decrease to RNF for the nine months ended SeptemberB 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.
[9]	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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $22 million decrease to revenues and $125 million decrease to revenues for the three months ended SeptemberB 30, 2014 and 2013, respectively, and the elimination of intersegment revenues.
[10]	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 at the date of merger with Constellation and the consolidation of CENG in purchase accounting of $203 million decrease to revenues and $603 million decrease to revenues, for the nine months ended SeptemberB 30, 2014 and 2013, respectively, and elimination of intersegment revenues.
[11]	Includes all wholesale and retail electric sales to third parties and affiliated sales to ComEd, PECO and BGE.
[12]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the three months ended SeptemberB 30, 2014 include revenue from sales to PECO of $28 million and sales to BGE of $83 million in the Mid-Atlantic region, and sales to ComEd of $1 million in the Midwest region. For the three months ended SeptemberB 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $82 million and sales to BGE of $144 million in the Mid-Atlantic region, and sales to ComEd of $143 million in the Midwest region
[13]	Generation includes the six power marketing reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Regions. Intersegment revenues for Generation for the nine months ended SeptemberB 30, 2014 include revenue from sales to PECO of $165 million and sales to BGE of $290 million in the Mid-Atlantic region, and sales to ComEd of $175 million in the Midwest. For the nine months ended SeptemberB 30, 2013, intersegment revenues for Generation include revenue from sales to PECO of $321 million and sales to BGE of $356 million in the Mid-Atlantic region, and sales to ComEd of $409 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.

Subsequent_Event_Details

Subsequent Event (Details) (Subsequent Event [Member], USD $)	0 Months Ended
In Millions, unless otherwise specified	Oct. 24, 2014
Subsequent Event [Line Items]	'
Expected Cash Proceeds on Sale of Assets	$475
Expected Total Proceeds Working Capital	60
Expected After Tax Net Cash Proceeds	418
Minimum [Member]	'
Subsequent Event [Line Items]	'
Expected Assets Impairment Charge	350
Maximum [Member]	'
Subsequent Event [Line Items]	'
Expected Assets Impairment Charge	$400